# Use	these	links	to	rapidly	review	the	document

TABLE	OF	CONTENTS

# UNITED	STATES	SECURITIES	AND	EXCHANGE	COMMISSION

ANNUAL	REPORT	PURSUANT	TO	SECTION	13	OR	15(d)	OF	THE SECURITIES	EXCHANGE	ACT	OF	1934

For	the	Fiscal	Year	Ended	December	31,	2004

Commission	file	number	1-5153

# Marathon	Oil	Corporation

(Exact	name	of	registrant	as	specified	in	its	charter)

Delaware

(State	of	Incorporation)

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

(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

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	at	least	the	past	90	days.	Yes	þ	No	o

Indicate	by	check	mark	if	disclosure	of	delinquent	filers	pursuant	to	Item	405	of	Regulation	S-K	(§229.405	of	this	chapter)	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.	o

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

Aggregate	market	value	of	Common	Stock	held	by	non-affiliates	as	of	June	30,	2004:	$13	billion.	The	amount	shown	is	based	on	the	closing	price	of	the registrant's	Common	Stock	on	the	New	York	Stock	Exchange	composite	tape	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	under	the	Securities	Act	of	1933.

There	were	347,013,291	shares	of	Marathon	Oil	Corporation	Common	Stock	outstanding	as	of	February	28,	2005.

# Documents	Incorporated	By	Reference:

Portions	of	the	registrant's	proxy	statement	relating	to	its	2005	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.

* The	Common	Stock	is	listed	on	the	New	York	Stock	Exchange,	the	Chicago	Stock	Exchange	and	the	Pacific	Stock	Exchange.

								Unless	the	context	otherwise	indicates,	references	in	this	Form	10-K	to	"Marathon,"	"we,"	"our,"	or	"us"	are	references	to	Marathon	Oil	Corporation,	its	wholly- owned	and	majority-owned	subsidiaries,	and	its	ownership	interest	in	equity	investees	(corporate	entities,	partnerships,	limited	liability	companies	and	other	ventures,	in which	Marathon	exerts	significant	influence	by	virtue	of	its	ownership	interest,	typically	between	20	and	50	percent).

# SIGNATURES

# GLOSSARY	OF	CERTAIN	DEFINED	TERMS

# Disclosures	Regarding	Forward-Looking	Statements

								This	annual	report	on	Form	10-K,	particularly	Item	1.	and	Item	2.	Business	and	Properties,	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	"anticipates,"	"believes,"	"estimates,"	"expects,"	"forecasts,"	"plans,"	"predicts"	or	"projects"	or	variations	of	these	words,	suggesting	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	with	respect	to	Marathon	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	and	refined	products;	levels	of worldwide	prices	of	liquid	hydrocarbons,	natural	gas	and	refined	products;	levels	of	reserves,	proved	or	otherwise,	of	liquid	hydrocarbons	or	natural	gas;	the	acquisition or	divestiture	of	assets;	the	effect	of	restructuring	or	reorganization	of	business	components;	the	potential	effect	of	judicial	proceedings	on	the	business	and	financial condition;	and	the	anticipated	effects	of	actions	of	third	parties	such	as	competitors,	or	federal,	state	or	local	regulatory	authorities.

# PART	I

# Item	1.	and	2.	Business	and	Properties

# 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,	Marathon	disposed	of	its	steel	business	through	a	tax-free	distribution	of	the	common	stock	of	its	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,	Marathon's	certificate	of	incorporation	was	amended	on	December	31,	2001	and,	from	that	date,	Marathon	has	only	one	class	of common	stock	authorized.

								Our	principal	operating	subsidiaries	are	Marathon	Oil	Company	and	Marathon	Ashland	Petroleum	LLC	("MAP").	Marathon	Oil	Company	and	its	predecessors have	been	engaged	in	the	oil	and	gas	business	since	1887.	MAP	is	62-percent	owned	by	Marathon	and	38-percent	owned	by	Ashland	Inc.	("Ashland").

# Segment	and	Geographic	Information

								Our	operations	consist	of	three	operating	segments:	1)	Exploration	and	Production	("E&P")	–	explores	for	and	produces	crude	oil	and	natural	gas;	2)	Refining, Marketing	and	Transportation	("RM&T")	–	refines,	markets	and	transports	crude	oil	and	petroleum	products;	and	3)	Integrated	Gas	("IG")	–	markets	and	transports natural	gas	and	products	manufactured	from	natural	gas,	such	as	liquefied	natural	gas	("LNG")	and	methanol.	For	operating	segment	and	geographic	information,	see Note	8	to	the	Consolidated	Financial	Statements	on	page	F-19.

# Exploration	and	Production

								We	are	currently	conducting	exploration,	development	and	production	activities	in	nine	countries.	Principal	exploration	activities	are	in	the	United	States,	Norway, Angola,	Equatorial	Guinea	and	Canada.	Principal	development	and	production	activities	are	in	the	United	States,	the	United	Kingdom,	Ireland,	Norway,	Equatorial Guinea,	Gabon	and	Russia.	We	are	also	pursuing	opportunities	in	north	and	west	Africa	and	the	Middle	East.

								Our	2004	worldwide	liquid	hydrocarbon	production	averaged	170,000	barrels	per	day	("bpd"),	a	decrease	of	12	percent	from	2003	levels.	Our	2004	worldwide sales	of	natural	gas	production,	including	gas	acquired	for	injection	and	subsequent	resale,	averaged	999	million	cubic	feet	per	day	("mmcfd"),	a	decrease	of	15	percent compared	to	2003.	In	total,	our	2004	worldwide	production	averaged	337,000	barrels	of	oil	equivalent	("boe")	per	day,	compared	to	389,000	boe	per	day	in	2003.	(For purposes	of	determining	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	gas	volume	to	obtain	boe.)	In	2005,	our	worldwide	production	is	expected to	average	approximately	325,000	to	350,000	boe	per	day,	excluding	acquisitions	and	dispositions.

								The	above	projection	of	2005	worldwide	liquid	hydrocarbon	and	natural	gas	production	volumes	is	a	forward-looking	statement.	Some	factors	that	could potentially	affect	timing	and	levels	of	production	include	pricing,	supply	and	demand	for	petroleum	products,	amount	of	capital	available	for	exploration	and development,	regulatory	constraints,	production	decline	rates	of	mature	fields,	timing	of	commencing	production	from	new	wells,	drilling	rig	availability,	future acquisitions	or	dispositions	of	producing	properties,	unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	the	government	or	military	response thereto,	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	statement.

# Exploration

								In	the	United	States	during	2004,	we	drilled	35	gross	(17	net)	exploratory	wells	of	which	22	gross	(10	net)	wells	encountered	hydrocarbons.	Of	these	22	wells,	3 gross	(1	net)	wells	were	temporarily	suspended	or	are	in	the	process	of	completing.	Internationally,	we	drilled	21	gross	(16	net)	exploratory	wells	of	which	13	gross	(10 net)	wells	encountered	hydrocarbons.	Of	these	13	wells,	13	gross	(9	net)	wells	were	temporarily	suspended	or	are	in	the	process	of	completing.

								United	States		–		The	Gulf	of	Mexico	continues	to	be	a	core	area	for	us	with	the	potential	to	add	new	reserves.	At	the	end	of	2004,	we	had	interests	in	123	blocks	in the	Gulf	of	Mexico,	including	94	in	the	deepwater	area.

								During	2004,	we	announced	that	the	Neptune	7	appraisal	well	on	the	Neptune	Unit	in	the	Gulf	of	Mexico	encountered	hydrocarbons.	This	discovery	follows	the Neptune	3	discovery	in	2002	and	the	Neptune	5	discovery	in	2003.	Two	successful	appraisal	sidetrack	wells	also	were	drilled	from	the	original	Neptune	5	location.	Front end	engineering	and	design	for	a	Neptune	development	is	currently	underway.	We	hold	a	30	percent	interest	in	the	Neptune	Unit.

								Announced	in	2003,	the	Perseus	discovery	is	located	on	Viosca	Knoll	Block	830	in	the	Gulf	of	Mexico	approximately	five	miles	from	the	existing	Petronius platform.	The	Perseus	discovery	was	expected	to	begin	production	in	2004	via	an	extended-reach	well	drilled	from	the	Petronius	platform.	Due	to	hurricane	activity	in September	2004	and	the	resulting	damage	to	the	Petronius	platform,	production	from	Perseus	has	been	delayed	until	repairs	of	the	Petronius	platform	can	be	completed. We	hold	a	50	percent	interest	in	the	Perseus	discovery.

								In	2001	a	successful	discovery	well	was	drilled	on	the	Ozona	prospect	in	the	Gulf	of	Mexico	and	in	2002	two	sidetrack	wells	were	drilled,	one	of	which	was successful.	We	have	established	an	integrated	project	team	to	formulate	a	development	plan.	We	are	currently	negotiating	commercial	terms	of	a	production	handling agreement	with	a	nearby	operator.	We	are	also	in	the	process	of	reviewing	seismic	data	to	obtain	a	better	understanding	of	the	complex	salt	formations	in	the	area	and	to optimize	the	location	of	the	next	well.	We	hold	a	68	percent	interest	in	the	Ozona	prospect.

								Other	United	States	exploration	activity	during	2004	included	three	wells	in	the	Cook	Inlet	area	of	Alaska,	two	of	which	were	discoveries,	and	11	wells	in	the Anadarko	Basin	in	Oklahoma,	nine	of	which	were	discoveries.

								Norway		–		During	2004	we	announced	the	Hamsun	discovery.	The	well	is	located	on	production	license	(PL)	150,	which	is	approximately	136	miles	from Stavanger,	Norway,	and	approximately	six	miles	south	of	the	Alvheim	area.	The	discovery	well	and	three	sidetracks	encountered	oil	and	gas.	Results	are	being	analyzed and	development	scenarios	are	being	examined	including	a	possible	tie-back	to	the	Alvheim	development.	We	are	the	operator	of	PL150,	owning	a	65	percent	interest. The	Hamsun	well	builds	on	our	successful	2003	Norwegian	drilling	program,	which	resulted	in	three	discoveries,	the	Kneler	and	Boa	discoveries	in	the	Alvheim development	and	the	Vilje	(formerly	known	as	Klegg)	discovery.	In	December	2004	we	acquired	four	new	Norwegian	exploration	licenses,	three	of	which	we	are designated	as	operator.

								Angola		–		Offshore	Angola,	we	own	a	10	percent	interest	in	Block	31	and	a	30	percent	interest	in	Block	32.	During	2004,	we	participated	in	the	Venus-1	well,	the fourth	oil	discovery	on	Block	31.	The	Venus	well	is	located	near	the

Plutao,	Saturno	and	Marte	discoveries	in	the	northeast	portion	of	Block	31.	These	discoveries	are	the	basis	for	a	planned	development	of	the	northeast	area	of	Block	31. Development	options	are	currently	being	evaluated.

								During	late	2004,	we	participated	in	a	well	on	the	Palas	prospect	in	the	southern	portion	of	Block	31,	and	in	early	2005,	it	was	announced	as	a	discovery.	Also,	at the	end	of	2004,	operations	were	ongoing	at	the	Ceres	prospect,	located	in	the	central	portion	of	Block	31.

								During	2004,	we	announced	the	Canela	discovery	on	Block	32,	located	about	10	miles	south	of	the	2003	Gindungo	discovery.	Also	in	2004,	wells	on	the	Cola	and Gengibre	prospects,	both	on	Block	32,	reached	total	depth.	The	Cola	well	encountered	hydrocarbons,	but	additional	drilling	will	be	required	to	determine	commerciality. The	results	of	the	Gengibre	well	will	be	announced	following	government	approval.

								Equatorial	Guinea		–		During	2004,	we	participated	in	two	natural	gas	and	condensate	discoveries	on	the	Alba	Block	offshore	Equatorial	Guinea.	The	Deep	Luba discovery	well,	drilled	from	the	Alba	field	production	platform,	encountered	gas	and	condensate	in	several	pay	zones.	The	Gardenia	discovery	well	is	located approximately	11	miles	southwest	of	the	Alba	Field.	We	are	currently	evaluating	development	scenarios	for	both	the	Deep	Luba	and	Gardenia	discoveries.	These discoveries	reinforce	the	potential	of	the	Alba	Block,	in	which	we	own	a	63	percent	interest.

								In	2003,	we	announced	a	natural	gas	discovery	on	Block	D	offshore	Equatorial	Guinea,	where	we	are	the	operator	with	a	90	percent	interest.	The	discovery	well	is on	the	Bococo	prospect,	which	is	approximately	six	miles	west	of	the	Alba	field.	The	well	has	been	suspended	for	reentry	at	a	later	date.	Development	scenarios	for	the Bococo	gas	discovery	along	with	three	earlier	dry	gas	discoveries	on	Block	D	are	being	considered	for	further	development.

								Canada		–		In	2002,	we	announced	a	gas	discovery	at	the	Annapolis	G-24	deepwater	wildcat	well	approximately	215	miles	south	of	Halifax,	Nova	Scotia	in	5,504 feet	of	water.	The	G-24	encountered	gas	pay	over	several	zones.	The	Crimson	well,	six	miles	southeast	of	the	Annapolis	discovery,	was	drilled	in	2004	and	was	plugged and	abandoned.	We	are	the	operator	and	own	a	30	percent	interest	in	the	Annapolis	lease.	In	addition,	we	operate	the	adjacent	Cortland	lease	where	we	own	a	75	interest and	the	adjacent	Empire	lease	where	we	own	a	50	percent	interest.

# Production	(including	development	activities)

								United	States		–		Approximately	48	percent	of	our	2004	worldwide	liquid	hydrocarbon	production	and	63	percent	of	our	worldwide	natural	gas	production	was produced	from	U.S.	operations.

								During	2004,	our	production	in	the	Gulf	of	Mexico	averaged	35,700	bpd	of	liquid	hydrocarbons,	representing	44	percent	of	our	total	U.S.	liquid	hydrocarbon production,	and	100	mmcfd	of	natural	gas,	representing	16	percent	of	our	total	U.S.	natural	gas	production.	Liquid	hydrocarbon	production	decreased	by	17,800	net	bpd and	natural	gas	production	decreased	by	36	net	mmcfd	from	the	prior	year.	The	decrease	in	production	is	mainly	due	to	natural	field	declines	and	the	effects	of	hurricane activity.	Our	Petronius	platform	suffered	significant	damage	from	Hurricane	Ivan	and	was	out	of	service	part	of	September	and	the	entire	fourth	quarter	of	2004.	Repair activity	is	underway,	but	production	of	liquid	hydrocarbons	of	approximately	19,000	net	bpd	and	natural	gas	of	approximately	32	net	mmcfd	remains	shut	in.	Production is	not	expected	to	come	back	on	stream	until	the	second	quarter	of	2005.	At	year-end	2004,	we	held	interests	in	eight	producing	fields	and	11	platforms	in	the	Gulf	of Mexico,	of	which	seven	platforms	are	operated	by	Marathon.

								Our	natural	gas	production	from	Alaska	is	seasonal	in	nature,	trending	down	during	the	second	and	third	quarters	and	increasing	during	the	fourth	and	first	quarter. In	2004	our	Alaskan	natural	gas	production	averaged	174	net	mmcfd,	representing	28	percent	of	our	total	U.S.	gas	production.	The	increase	from	2003	production	of 166	net	mmcfd	is	primarily	due	to	a	full	year	of	production	from	the	Ninilchik	field.	Production	from	the	Ninilchik	field	began	in	2003	and	development	continues	on the	field.	Ninilchik	gas	is	transported	through	the	32-mile	portion	of	the	Kenai	Kachemak	Pipeline,	which	connects	Ninilchik	to	the	existing	natural	gas	pipeline infrastructure	serving	residential,	utility	and	industrial	markets	on	the	Kenai	Peninsula,	in	Anchorage	and	in	other	parts	of	south	central	Alaska.	We	operate	the	Ninilchik Unit	and	own	a	60	percent	interest	in	it	and	the	Kenai	Kachemak	Pipeline.

								Liquid	hydrocarbon	production	from	our	Wyoming	fields	averaged	21,200	net	bpd	in	2004	compared	to	21,400	net	bpd	in	2003.	Gas	production	from	our Wyoming	fields	averaged	108	net	mmcfd	in	2004	compared	to	127	net	mmcfd	in	2003.	The	decrease	in	our	Wyoming	gas	production	is	primarily	attributed	to	lower production	from	the	Powder	River	Basin,	which	averaged	69	net	mmcfd	in	2004	compared	to	82	net	mmcfd	in	2003.	This	decrease	is	primarily	attributed	to	natural	field decline.	Development	of	the	Powder	River	Basin	continued	in	2004	with	approximately	230	wells	drilled,	of	which	145	are	yet	to	be	completed,	compared	to approximately	320	wells	drilled	in	2003.	Additional	development	of	our	southwest	Wyoming	interests	continued	in	2004	where	we	participated	in	the	drilling	of	18 wells.	Gas	production	from	our	Oklahoma	fields	averaged	82	net	mmcfd	in	2004	compared	to	96	net	mmcfd	in	2003.	This

decrease	is	primarily	attributed	to	natural	field	decline.	Our	2004	development	program	continued	to	focus	in	the	Anadarko	Basin	where	we	participated	in	the	drilling	of 53	wells.

								Our	share	of	liquid	hydrocarbon	production	from	the	Permian	Basin	region,	which	extends	from	southeast	New	Mexico	to	west	Texas	averaged	18,900	bpd	in 2004,	compared	to	30,200	bpd	in	2003.	This	decrease	is	principally	due	to	natural	field	decline	and	the	sale	of	the	Yates	field	in	November	2003.	Gas	production	from our	New	Mexico	fields,	primarily	the	Indian	Basin	field,	averaged	85	net	mmcfd	in	2004	compared	to	122	net	mmcfd	in	2003.	The	decrease	in	natural	gas	production	is due	to	natural	field	decline.	Gas	production	from	our	Texas	fields,	primarily	located	in	East	Texas,	averaged	65	net	mmcfd	in	2004	compared	to	73	net	mmcfd	in	2003. This	decrease	is	mostly	due	to	natural	field	decline.	Active	development	of	the	Mimms	Creek	field	in	East	Texas	continued	in	2004	with	the	drilling	of	26	wells.

								United	Kingdom		–		Our	largest	asset	in	the	U.K.	North	Sea	is	the	Brae	area	complex	where	we	are	the	operator	and	own	a	42	percent	interest	in	the	South,	Central, North,	and	West	Brae	fields	and	a	38	percent	interest	in	the	East	Brae	field.	The	Brae	A	platform	and	facilities	host	the	underlying	South	Brae	field	and	the	adjacent Central	Brae	field	and	West	Brae/Sedgwick	fields.	The	North	Brae	field,	which	is	produced	via	the	Brae	B	platform,	and	the	East	Brae	field	are	gas-condensate	fields. Our	share	of	production	from	the	Brae	area	averaged	15,900	bpd	of	liquid	hydrocarbons	in	2004,	compared	with	17,500	bpd	in	2003.	The	decrease	primarily	resulted from	natural	field	decline.	Our	share	of	Brae	gas	sales	averaged	197	mmcfd	in	2004	compared	with	198	mmcfd	in	2003.

								The	strategic	location	of	the	Brae	platforms	along	with	pipeline	and	onshore	infrastructure	has	generated	third-party	processing	and	transportation	business	since 1986.	Currently,	there	are	22	agreements	with	third-party	fields	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	Beryl	group	owns	the	remaining 50	percent.	The	SAGE	pipeline	transports	gas	from	the	Brae	and	Beryl	areas	and	has	a	total	wet	gas	capacity	of	approximately	1,000	mmcfd.	The	SAGE	terminal	at	St. Fergus	in	northeast	Scotland	processes	gas	from	the	SAGE	pipeline	and	0.8	billion	cubic	feet	("bcf")	per	day	of	third	party	gas	from	the	Britannia	field.

								In	the	U.K.	Atlantic	Margin,	we	own	an	approximately	30	percent	interest	in	the	outside-operated	Foinaven	area	complex,	consisting	of	a	28	percent	interest	in	the main	Foinaven	field,	47	percent	of	East	Foinaven	and	20	percent	of	the	T35	and	T25	accumulations,	each	of	which	has	a	single	well.	Our	share	of	production	from	the Foinaven	fields	averaged	21,900	bpd	of	liquid	hydrocarbons	and	10	mmcfd	of	natural	gas	in	2004,	compared	to	22,400	net	bpd	and	10	mmcfd	in	2003.

								Norway		–		We	are	the	operator	and	own	a	65	percent	interest	in	the	Alvheim	complex	located	on	the	Norwegian	Continental	Shelf.	This	development	is	comprised of	the	Kneler	and	Boa	discoveries	and	the	previously	undeveloped	Kameleon	accumulation.	During	2004,	we	received	approval	from	the	Norwegian	authorities	for	our Alvheim	plan	of	development	and	operation	("PDO"),	which	will	consist	of	a	floating	production,	storage	and	offloading	vessel	("FPSO")	with	subsea	infrastructure	for five	drill	centers	and	associated	flow	lines.	The	PDO	also	outlines	transportation	of	produced	oil	by	shuttle	tanker	and	transportation	of	produced	natural	gas	to	the SAGE	system	using	a	new	14-inch,	24-mile	cross	border	pipeline.	Marathon	and	its	Alvheim	project	partners	signed	a	purchase	and	sale	agreement	in	2004	for	the	Odin multipurpose	shuttle	tanker,	which	will	be	modified	to	an	FPSO.	Also	during	2004,	the	Alvheim	partners	reached	agreement	to	tie-in	the	nearby	Vilje	discovery,	in which	we	own	a	47	percent	interest,	subject	to	the	approval	of	the	Vilje	PDO	which	was	submitted	to	the	Norwegian	government	in	December	2004.	Production	from	a combined	Alvheim/Vilje	development	is	expected	to	reach	more	than	50,000	net	boe	per	day	with	first	production	starting	in	2007.

								During	2004,	production	in	Norway	from	the	Heimdal,	Vale	and	Byggve/Skirne	fields	averaged	2,000	net	bpd	and	27	net	mmcfd.	We	own	a	24	percent	interest	in the	Heimdal	field,	a	47	percent	interest	in	the	Vale	field	and	a	20	percent	interest	in	the	Byggve/Skirne	field,	which	came	on	stream	during	2004.

								Ireland		–		We	own	a	100	percent	interest	in	the	Kinsale	Head,	Ballycotton	and	Southwest	Kinsale	fields	in	the	Celtic	Sea	offshore	Ireland.	Natural	gas	sales	were 58	mmcfd	in	2004,	compared	with	62	mmcfd	in	2003.	We	have	agreed	with	the	Seven	Heads	group	to	process	and	transport	gas,	as	well	as	to	provide	field	operating services,	through	our	existing	Kinsale	Head	facilities.	Production	from	Seven	Heads	commenced	in	December	2003.

								We	own	an	18.5	percent	interest	in	the	Corrib	gas	development	project,	located	approximately	40	miles	off	Ireland's	west	coast.	During	2004,	the	An	Bord	Pleanála upheld	the	Mayo	County	Council's	decision	to	grant	planning	approval	for	the	proposed	natural	gas	terminal	at	Bellanaboy	Bridge,	County	Mayo,	which	will	process gas	from	the

Corrib	field.	This	decision	represents	a	major	step	forward	for	the	outside-operated	Corrib	gas	project.	Development	work	on	the	Corrib	project	has	resumed	and	first gas	production	is	expected	in	mid-year	2007.

								Equatorial	Guinea		–		We	own	a	63	percent	interest	in	the	Alba	field	offshore	Equatorial	Guinea	and	a	52	percent	interest	in	an	onshore	liquefied	petroleum	gas processing	plant	held	through	an	equity	method	investee.	During	2004	liquid	hydrocarbon	production	averaged	18,900	bpd	and	natural	gas	production	averaged	76 mmcfd,	compared	to	12,400	bpd	and	66	mmcfd	in	2003.	The	condensate	expansion	project	was	completed	during	2004	and	began	its	production	ramp	up.	This expansion	project	is	expected	to	increase	total	liquids	production	from	approximately	20,000	gross	bpd	to	approximately	57,000	gross	bpd	(32,000	bpd	net	to	Marathon). By	the	end	of	2004	liquids	production	had	increased	to	approximately	45,800	gross	bpd.	The	liquefied	petroleum	gas	("LPG")	expansion	project	progressed	during	2004 and	is	expected	to	start-up	in	the	second	quarter	of	2005.	When	completed,	gross	liquids	production	is	expected	to	increase	from	approximately	57,000	gross	bpd	to 79,000	gross	bpd	(44,500	bpd	net	to	Marathon).

								Approximately	125	mmcfd	of	dry	gas	remaining	after	the	condensate	and	LPG	are	removed	is	supplied	to	Atlantic	Methanol	Production	Company	LLC ("AMPCO")	where	it	is	used	to	manufacture	methanol.	We	own	45	percent	of	AMPCO,	which	is	reported	in	the	Integrated	Gas	segment.	Remaining	dry	gas	is	returned offshore	and	reinjected	into	the	Alba	reservoir	for	later	production	when	the	LNG	project	on	Bioko	Island	is	completed.

								Gabon		–		We	are	the	operator	of	the	Tchatamba	South,	Tchatamba	West	and	Tchatamba	Marin	fields	offshore	Gabon	with	a	56	percent	working	interest. Production	in	Gabon	averaged	13,600	net	bpd	of	liquid	hydrocarbons	in	2004,	compared	with	14,700	net	bpd	in	2003.	Production	from	these	three	fields	is	processed	on a	single	facility	at	Tchatamba	Marin,	with	processed	oil	being	transported	through	an	offshore	and	onshore	pipeline	to	a	non-operated	storage	facility.	During	2004,	we extended	our	license	in	Gabon	for	10	years	which	will	now	expire	in	2018.

								Russia		–		During	2003	we	acquired	Khanty	Mansiysk	Oil	Corporation	("KMOC").	KMOC's	fields	are	located	in	the	Khanty	Mansiysk	region	of	western	Siberia. Production	from	these	assets	averaged	16,600	net	bpd	during	2004,	primarily	from	the	Potanay	and	East	Kamennoye	fields.	Development	activities	continued	in	these fields	in	2004,	with	35	wells	drilled	in	East	Kamennoye	and	17	wells	drilled	in	Potanay.	Additionally,	one	well	was	drilled	in	2004	on	the	Paitykhskoye	license.

								Libya		–		We	own	a	16.3	percent	interest	in	the	approximately	13	million	acre	Waha	concession	in	Libya.	In	1986,	we	ceased	active	participation	in	the	concessions following	the	imposition	of	trade	sanctions	by	the	U.S.	government.	In	2004	the	U.S.	government	lifted	the	sanctions,	allowing	us	to	advance	plans	to	return	to production	operations.	We	continue	to	work	with	our	partners,	including	the	Libyan	government,	to	finalize	the	terms	of	a	reentry	agreement.

								Gas-to-liquids		–		During	2004,	Marathon	and	Syntroleum	Corporation	("Syntroleum")	successfully	completed	the	construction	and	operation	of	a	gas-to-liquids ("GTL")	demonstration	plant	at	the	Port	of	Catoosa,	Oklahoma.	This	GTL	project	was	part	of	an	ultra-clean	fuels	production	and	demonstration	project	sponsored	by	the U.S.	Department	of	Energy's	National	Energy	Technology	Laboratory.	The	Catoosa	plant,	which	mirrors	a	commercial	scale	plant,	successfully	demonstrated	a	fully integrated	GTL	technology	that	converted	natural	gas	into	a	finished	fuel,	producing	more	than	5,500	barrels	of	synthetic	products,	including	ultra-clean	diesel	fuel, which	was	delivered	to	Integrated	Concepts	Research	Corporation,	a	project	partner,	for	fleet	vehicle	testing	in	Washington,	DC	and	Denali	National	Park,	Alaska.	The Catoosa	GTL	plant	supports	our	ongoing	efforts	to	explore	the	potential	of	GTL	technology,	and	demonstrates	how	such	technology	could	be	incorporated	into	the design	of	a	commercial	GTL	facility	such	as	our	proposed	gas	processing	project	in	Qatar.	Future	research	of	GTL	technology	as	well	as	other	gas	technologies	is	being conducted	in	our	integrated	gas	segment.

								In	connection	with	construction	of	the	Catoosa	GTL	plant,	we	advanced	Syntroleum	$21.3	million	under	a	secured	promissory	note.	The	note	bears	interest	at	a	rate of	eight	percent	per	year	and	matures	on	June	30,	2006.	If	Syntroleum	does	not	repay	the	note	by	June	30,	2006,	we	will	have	the	right	to	convert	the	note	into	credits against	future	license	fees	or	into	Syntroleum	common	stock	at	no	less	than	$6.00	per	share	and	no	more	than	$8.50	per	share.

								The	above	discussion	of	the	E&P	segment	includes	forward-looking	statements	with	respect	to	the	timing	of	resumption	of	production	from	the	Petronius	platform and	the	timing	and	levels	of	production	from	the	combined	Alvheim/Vilje	project,	the	Corrib	project,	the	LPG	expansion	project	and	other	expansion	projects.	Some factors	which	could	affect	the	timing	of	the	resumption	of	production	from	the	Petronius	platform	include	unforeseen	problems	arising	from	the	repair	work	or	further severe	weather	conditions.	Some	factors	which	could	affect	the	timing	and	production	levels	of	the	Alvheim/Vilje	project,	the	Corrib	project,	the	LPG	expansion	project and	other	expansion	projects	include	pricing,	supply	and	demand	for	petroleum	products,	amount	of	capital	available	for	exploration	and	development,	regulatory constraints,	drilling	rig	availability,	inability	or	delays	in	obtaining	necessary	government	or	third	party	approvals	or	permits,	including	Norwegian	regulatory	approval for	the	Vilje	PDO,	unforeseen	problems	arising	from	construction,	unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	the

governmental	or	military	response,	and	other	geological,	operating	and	economic	considerations.	The	foregoing	factors	(among	others)	could	cause	actual	results	to differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Reserves

								At	December	31,	2004,	our	net	proved	liquid	hydrocarbon	and	natural	gas	reserves	totaled	approximately	1.139	billion	boe,	of	which	37	percent	were	located	in	the United	States.	The	following	table	sets	forth	estimated	quantities	of	net	proved	oil	and	gas	reserves	at	the	end	of	each	of	the	last	three	years.

# Estimated	Quantities	of	Net	Proved	Oil	and	Gas	Reserves	at	December	31

|  |  | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Liquid\tHydrocarbons\t(Millions\tof\tBarrels) |  |  |  |  |  |  |  |
| United\tStates |  | 171 | 193 | 226 | 191 | 210 | 245 |
| Europe |  | 41 | 47 | 63 | 107 | 59 | 76 |
| West\tAfrica |  | 147 | 120 | 113 | 223 | 218 | 203 |
| Other\tInternational |  | 27 | 31 | 2 | 39 | 89 | 3 |
| Total\tConsolidated\tContinuing\tOperations | Total\tConsolidated\tContinuing\tOperations | 386 | 391 | 404 | 560 | 576 | 527 |
| (a)\nEquity\tInvestees |  | - | 2 | 177 | - | 2 | 183 |
| Worldwide\tContinuing\tOperations | Worldwide\tContinuing\tOperations | 386 | 393 | 581 | 560 | 578 | 710 |
| Discontinued\tOperations | (b) | - | - | 9 | - | - | 10 |
| WORLDWIDE |  | 386 | 393 | 590 | 560 | 578 | 720 |
| Developed\treserves\tas\t%\tof\ttotal\tnet\tproved\treserves | Developed\treserves\tas\t%\tof\ttotal\tnet\tproved\treserves | 69% | 68% | 82% |  |  |  |
| Natural\tGas\t(Billions\tof\tCubic\tFeet) |  |  |  |  |  |  |  |
| United\tStates |  | 992 | 1,067 | 1,206 | 1,364 | 1,635 | 1,724 |
| Europe |  | 376 | 421 | 408 | 544 | 484 | 562 |
| West\tAfrica |  | 570 | 528 | 552 | 1,564 | 665 | 653 |
| Total\tConsolidated\tContinuing\tOperations | Total\tConsolidated\tContinuing\tOperations | 1,938 | 2,016 | 2,166 | 3,472 | 2,784 | 2,939 |
| (c)\nEquity\tInvestee |  | - | - | 36 | - | - | 59 |
| Worldwide\tContinuing\tOperations | Worldwide\tContinuing\tOperations | 1,938 | 2,016 | 2,202 | 3,472 | 2,784 | 2,998 |
| Discontinued\tOperations | (b) | - | - | 290 | - | - | 379 |
| WORLDWIDE |  | 1,938 | 2,016 | 2,492 | 3,472 | 2,784 | 3,377 |
| Developed\treserves\tas\t%\tof\ttotal\tnet\tproved\treserves | Developed\treserves\tas\t%\tof\ttotal\tnet\tproved\treserves | 56% | 72% | 74% |  |  |  |
| Total\tBOE\t(Millions\tof\tBarrels) |  |  |  |  |  |  |  |
| United\tStates |  | 336 | 371 | 427 | 418 | 483 | 532 |
| Europe |  | 104 | 117 | 132 | 198 | 139 | 170 |
| West\tAfrica |  | 242 | 208 | 205 | 484 | 329 | 312 |
| Other\tInternational |  | 27 | 31 | 2 | 39 | 89 | 3 |
| Total\tConsolidated\tContinuing\tOperations | Total\tConsolidated\tContinuing\tOperations | 709 | 727 | 766 | 1,139 | 1,040 | 1,017 |
| (a)\nEquity\tInvestees |  | - | 2 | 183 | - | 2 | 193 |
| Worldwide\tContinuing\tOperations | Worldwide\tContinuing\tOperations | 709 | 729 | 949 | 1,139 | 1,042 | 1,210 |
| Discontinued\tOperations | (b) | - | - | 57 | - | - | 73 |
| WORLDWIDE |  | 709 | 729 | 1,006 | 1,139 | 1,042 | 1,283 |
| Developed\treserves\tas\t%\tof\ttotal\tnet\tproved\treserves | Developed\treserves\tas\t%\tof\ttotal\tnet\tproved\treserves | 62% | 70% | 78% |  |  |  |

(a) Represents	Marathon's	equity	interests	in	LLC	JV	Chernogorskoye	("Chernogorskoye"),	MKM	Partners	L.P.	("MKM")	and	CLAM	Petroleum	B.V.	("CLAM").	Our	interest	in	Chernogorskoye	was	sold	in 2004.	MKM	was	dissolved	and	the	Yates	interest	was	sold	in	2003.	Our	interest	in	CLAM	was	sold	in	2003.

(b) Represents	Marathon's	western	Canadian	assets,	which	were	sold	in	2003.

(c) Represents	Marathon's	equity	interest	in	CLAM,	which	was	sold	in	2003.

								Proved	developed	reserves	represented	62	percent	of	total	proved	reserves	as	of	December	31,	2004,	as	compared	to	70	percent	as	of	December	31,	2003.	Of	the 430	million	boe	of	proved	undeveloped	reserves	at	year-end	2004,	only	22	percent	have	been	included	as	proved	reserves	for	more	than	two	years	while	56	percent	were added	during	2004.

								During	2004,	we	added	net	proved	reserves	of	221	million	boe,	excluding	2	million	boe	of	dispositions,	while	producing	122	million	boe.	These	net	additions included	extensions,	discoveries	and	other	additions	of	136	million	boe	and	total	revisions	of	81	million	boe.	Of	the	total	net	reserve	additions,	25	million	boe	were proved	developed	and	194	million	boe	were	proved	undeveloped.	Additionally,	we	transferred	78	million	boe	from	proved	undeveloped	to	proved	developed	during 2004.	Costs	incurred	for	the	periods	ended	December	31,	2004,	2003	and	2002	relating	to	the	development	of	proved	undeveloped	oil	and	gas	reserves,	were $708	million,	$780	million	and	$404	million.	These	amounts	include	our	proportionate	share	of	equity	investees'	costs	incurred	as	these	were	costs	necessary	for	the development	of	proved	undeveloped	reserves.	As	of	December	31,	2004,	estimated	future	development	costs	relating	to	the	development	of	proved	undeveloped	oil	and gas	reserves	for	the	years	2005	through	2007	are	projected	to	be	$718	million,	$629	million,	and	$105	million.

								The	most	significant	extensions,	discoveries	and	other	additions	in	2004	are	related	to	the	Alvheim/Vilje	developments	in	Norway	and	the	Corrib	development	in Ireland.	Reserve	additions	for	the	Alvheim/Vilje	developments	totaled	63	million	boe,	or	46%	of	total	extensions,	discoveries	and	other	additions.	The	PDO	for	the Alvheim	development	was	approved	by	the	Norwegian	authorities	during	2004	and	approval	of	the	Vilje	PDO,	which	was	submitted	to	the	Norwegian	government	in December	2004,	is	expected	in	2005.	Production	from	the	Alvheim/Vilje	developments	is	expected	to	begin	in	2007.	Reserve	additions	for	the	Corrib	development totaled	16	million	boe,	or	12%	of	total	extensions,	discoveries	and	other	additions.	With	the	planning	permission	received	from	the	Irish	authorities	for	the	proposed natural	gas	terminal,	which	is	to	be	built	to	bring	gas	from	the	Corrib	field	ashore,	development	activities	are	underway.	First	gas	production	is	expected	in	2007.

								The	Alba	field	in	Equatorial	Guinea	had	the	most	significant	positive	revisions	–	162	million	boe.	Of	this	volume,	84	million	boe	was	added	due	to	the	final investment	decision	on	the	Equatorial	Guinea	LNG	project,	which	will	use	the	gas	from	the	Alba	field	to	produce	LNG.	Startup	of	the	LNG	plant	is	expected	in	2007. An	additional	66	million	boe	is	related	to	additional	compression	that	is	expected	to	be	installed	in	2010	and	will	be	necessary	for	the	LNG	plant	to	meet	its requirements.	At	the	end	of	2004,	our	total	proved	reserves	associated	with	the	Alba	field	offshore	Equatorial	Guinea	totaled	471	million	boe,	or	41	percent	of	our	total proved	reserves.

								We	had	negative	revisions	of	51	million	boe	in	Russia	and	40	million	boe	in	the	Powder	River	Basin	due	to	disappointing	results	from	development	activity.	These revisions,	combined	with	extensions,	discoveries	and	other	additions	and	a	small	disposition,	resulted	in	total	net	reductions	in	reserves	of	46	million	boe	for	Russia	and 35	million	boe	for	the	Powder	River	Basin.

								The	above	estimated	quantities	of	reserves,	estimated	future	development	costs	relating	to	the	development	of	proved	undeveloped	oil	and	gas	reserves,	timing	of production	from	development	projects	and	timing	of	the	LNG	plant	activities	are	forward-looking	statements,	are	based	on	a	number	of	assumptions,	including	(among others)	prices,	presently	known	physical	data	concerning	size	and	character	of	the	reservoirs,	economic	recoverability,	production	experience	and	other	operating considerations.	To	the	extent	these	assumptions	prove	inaccurate,	actual	recoveries	could	be	different	than	current	estimates.	With	respect	to	additional	factors	that	may affect	the	Alvheim/Vilje	developments,	the	Corrib	development	and	the	LNG	plant,	please	refer	to	page	6.

								For	additional	details	of	estimated	quantities	of	net	proved	oil	and	gas	reserves	at	the	end	of	each	of	the	last	three	years,	see	"Consolidated	Financial	Statements	and Supplementary	Data	–	Supplementary	Information	on	Oil	and	Gas	Producing	Activities	–	Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves"	on	pages	F-45	through F-46.	We	filed	reports	with	the	U.S.	Department	of	Energy	("DOE")	for	the	years	2003	and	2002	disclosing	the	year-end	estimated	oil	and	gas	reserves.	We	will	file	a similar	report	for	2004.	The	year-end	estimates	reported	to	the	DOE	are	the	same	as	the	estimates	reported	in	the	Supplementary	Information	on	Oil	and	Gas	Producing Activities.

# Delivery	Commitments

								We	have	committed	to	deliver	fixed	and	determinable	quantities	of	natural	gas	to	customers	under	a	variety	of	contractual	arrangements.

								In	Alaska,	we	have	two	long-term	sales	contracts	with	the	local	utility	companies,	which	obligate	us	to	supply	approximately	181	bcf	of	natural	gas	over	the remaining	life	of	these	contracts,	which	terminate	in	2012	and	2016.	In	addition,	we	own	a	30	percent	interest	in	a	Kenai,	Alaska	LNG	plant	and	a	proportionate	share	of the	long-term	LNG	sales	obligation	to	two	Japanese	utility	companies.	This	obligation	is	estimated	to	total	110	bcf	through	the	remaining	life	of	the	contract,	which terminates	March	31,	2009.	These	commitments	are	structured	with	variable-pricing	terms.	Our	production	from	various	gas	fields	in	the	Cook	Inlet	supply	the	natural gas	to	service	these	contracts.	Our	proved	reserves	and	estimated	production	rates	in	the	Cook	Inlet	sufficiently	meet	these	contractual	obligations.

								In	the	U.K.,	we	have	two	long-term	sales	contracts	with	utility	companies,	which	obligate	us	to	supply	approximately	210	bcf	of	natural	gas	through	the	remaining life	of	these	contracts,	which	terminate	in	September	2009.	Our	Brae	area	production,	together	with	natural	gas	acquired	for	injection	and	subsequent	resale,	will	supply the	natural	gas	to	service	these	contracts.	Our	Brae	area	proved	reserves,	acquired	natural	gas	contracts	and	estimated	production	rates	sufficiently	meet	these	contractual obligations.	Pricing	under	these	gas	sales	contracts	is	variable.

# Oil	and	Natural	Gas	Production

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

# Net	Liquid	Hydrocarbons	Production

# (Thousands	of	Barrels	per	Day)

# Net	Natural	Gas	Production

# (Millions	of	Cubic	Feet	per	Day)

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

(b) Amounts	represent	production	after	royalties,	excluding	the	U.K.,	Ireland	and	the	Netherlands	where	amounts	shown	are	before	royalties.

(c) Amounts	represent	production	from	leasehold	ownership,	after	royalties	and	interests	of	others.

(d) Amounts	represent	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.

(e) Represents	Marathon's	equity	interests	in	Chernogorskoye,	MKM	and	CLAM.

(f) Amounts	represent	Marathon's	western	Canadian	operations,	which	were	sold	in	2003.

(g) Amounts	exclude	volumes	purchased	from	third	parties	for	injection	and	subsequent	resale	of	19	mmcfd	in	2004,	23	mmcfd	in	2003	and	4	mmcfd	in	2002.

(h) Represents	Marathon's	equity	interests	in	CLAM.

# Productive	and	Drilling	Wells

								The	following	tables	set	forth	productive	wells	and	service	wells	for	each	of	the	last	three	years	and	drilling	wells	as	of	December	31,	2004.

# Gross	and	Net	Wells

(a) Includes	active	wells	and	wells	temporarily	shut-in.	Of	the	gross	productive	wells,	gross	wells	with	multiple	completions	operated	by	Marathon	totaled	273	in	2004,	273	in	2003,	and	357	in	2002.	Information on	wells	with	multiple	completions	operated	by	other	companies	is	unavailable	to	Marathon.

(b) Consist	of	injection,	water	supply	and	disposal	wells.

(c) Consists	of	exploratory	and	development	wells.

(d) Represents	Chernogorskoye	in	2003,	and	MKM	and	CLAM	in	2002.

# 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	(references	to	"net"	wells	or	production	indicate	our	ownership	interest	or	share,	as	the	context	requires):

# Net	Productive	and	Dry	Wells	Completed

| Development | Development | (c) | –	Oil | 13 | 4 | 8 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | –\tGas | 167 | 231 | 174 |
|  |  |  | –\tDry | – | – | 1 |
|  |  |  | Total | 180 | 235 | 183 |
| Exploratory | Exploratory |  | –\tOil | 1 | 1 | 2 |
|  |  |  | –\tGas | 8 | 7 | 5 |
|  |  |  | –\tDry | 6 | 2 | 6 |
|  |  |  | Total | 15 | 10 | 13 |
|  |  |  | Total\tUnited\tStates | 195 | 245 | 196 |
| International | (d) |  |  |  |  |  |
| Development | Development | (c) | –\tOil | 27 | 31 | 2 |
|  |  |  | –\tGas | 3 | 14 | 28 |
|  |  |  | –\tDry | 1 | 1 | 3 |
|  |  |  | Total | 31 | 46 | 33 |
| Exploratory | Exploratory |  | –\tOil | 2 | 2 | – |
|  |  |  | –\tGas | – | 21 | 20 |
|  |  |  | –\tDry | 7 | 5 | 3 |
|  |  |  | Total | 9 | 28 | 23 |
|  |  |  | Total\tInternational | 40 | 74 | 56 |
|  |  |  | Total\tWorldwide | 235 | 319 | 252 |

(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) Includes	Marathon's	equity	interest	in	MKM	in	2003	and	2002.

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

# Oil	and	Gas	Acreage

								The	following	table	sets	forth,	by	geographic	area,	the	developed	and	undeveloped	oil	and	gas	acreage	that	we	held	as	of	December	31,	2004:

# Gross	and	Net	Acreage

|  | Gross | Net | Gross | Net | Gross | Net |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| United\tStates | 1,825 | 764 | 2,320 | 1,426 | 4,145 | 2,190 |
| Europe | 395 | 305 | 1,315 | 602 | 1,710 | 907 |
| West\tAfrica | 68 | 42 | 2,973 | 799 | 3,041 | 841 |
| Other\tInternational | 599 | 599 | 2,541 | 1,997 | 3,140 | 2,596 |
| WORLDWIDE | 2,887 | 1,710 | 9,149 | 4,824 | 12,036 | 6,534 |

# Refining,	Marketing	and	Transportation

								Our	RM&T	operations	are	primarily	conducted	by	MAP	and	its	subsidiaries,	including	its	wholly-owned	subsidiaries,	Speedway	SuperAmerica	LLC	("SSA")	and Marathon	Ashland	Pipe	Line	LLC.

# Refining

								MAP	owns	and	operates	seven	refineries	with	an	aggregate	refining	capacity	of	948,000	barrels	of	crude	oil	per	day.	The	table	below	sets	forth	the	location	and daily	throughput	capacity	of	each	of	MAP's	refineries	as	of	December	31,	2004:

# Crude	Oil	Refining	Capacity

# (Barrels	per	Day)

| Garyville,	LA | 245,000 |
| :--- | :--- |
| Catlettsburg,\tKY | 222,000 |
| Robinson,\tIL | 192,000 |
| Detroit,\tMI | 74,000 |
| Canton,\tOH | 73,000 |
| Texas\tCity,\tTX | 72,000 |
| St.\tPaul\tPark,\tMN | 70,000 |
| TOTAL | 948,000 |

								MAP's	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	gasoline.	MAP's	refineries	are	integrated	via	pipelines and	barges	to	maximize	operating	efficiency.	The	transportation	links	that	connect	the	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;	gas	oil	may be	moved	from	Robinson	to	Detroit	where	excess	fluid	catalytic	cracking	unit	capacity	is	available;	and	light	cycle	oil	may	be	moved	from	Texas	City	to	Robinson where	excess	desulfurization	capacity	is	available.

								MAP	also	produces	asphalt	cements,	polymerized	asphalt,	asphalt	emulsions	and	industrial	asphalts.	MAP	manufactures	petroleum	pitch,	primarily	used	in	the graphite	electrode,	clay	target	and	refractory	industries.	Additionally,	MAP	manufactures	aromatics,	aliphatic	hydrocarbons,	cumene,	base	lube	oil,	polymer	grade propylene	and	slack	wax.

								During	2004,	MAP's	refineries	processed	939,000	bpd	of	crude	oil	and	171,000	bpd	of	other	charge	and	blend	stocks.	The	following	table	sets	forth	MAP's	refinery production	by	product	group	for	each	of	the	last	three	years:

# Refined	Product	Yields

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Gasoline | 608 | 567 | 581 |
| Distillates | 299 | 284 | 285 |
| Propane | 22 | 21 | 21 |
| Feedstocks\tand\tSpecial\tProducts | 94 | 93 | 80 |
| Heavy\tFuel\tOil | 25 | 24 | 20 |
| Asphalt | 77 | 72 | 72 |
| TOTAL | 1,125 | 1,061 | 1,059 |

								Planned	maintenance	activities	requiring	temporary	shutdown	of	certain	refinery	operating	units,	or	turnarounds,	are	periodically	performed	at	each	refinery.	MAP completed	major	turnarounds	at	its	Garyville,	Catlettsburg	and	Canton	refineries	during	2004.

								MAP	increased	its	overall	crude	oil	refining	capacity	during	2004	from	935,000	bpd	to	948,000	bpd	after	completing	the	planned	turnaround	and	expansion	project at	the	Garyville	refinery.	This	expansion	increased	crude	oil	capacity	at	Garyville	from	232,000	bpd	to	245,000	bpd.

								The	Catlettsburg	refinery	multi-year	improvement	project	was	completed	during	early	2004.	At	a	cost	of	approximately	$440	million,	the	project	improves	product yields	and	lowers	overall	refinery	costs	while	making	gasoline	with	less	than	30	parts	per	million	of	sulfur,	which	allows	MAP	to	meet	Tier	II	gasoline	regulations which	became	effective	on	January	1,	2004.

								MAP	is	constructing	approximately	$300	million	in	new	capital	projects	for	its	74,000	bpd	Detroit,	Michigan	refinery.	One	of	the	projects,	a	$110	million expansion	project,	is	expected	to	raise	the	crude	oil	capacity	at	the	refinery	by	35	percent	to	100,000	bpd.	Other	projects	are	expected	to	enable	the	refinery	to	produce new	clean	fuels	and	further	control	regulated	air	emissions.	Completion	of	the	projects	is	scheduled	for	the	fourth	quarter	of	2005.

# Marketing

								In	2004	MAP's	refined	product	sales	volumes	(excluding	matching	buy/sell	transactions)	totaled	20.4	billion	gallons	(1,329,000	bpd).	The	wholesale	distribution	of petroleum	products	to	private	brand	marketers	and	to	large	commercial	and	industrial	consumers,	primarily	located	in	the	Midwest,	the	upper	Great	Plains	and	the Southeast,	and	sales	in	the	spot	market,	accounted	for	approximately	70	percent	of	MAP's	refined	product	sales	volumes	in	2004,	excluding	sales	related	to	matching buy/sell	transactions.	Approximately	52	percent	of	MAP's	gasoline	sales	volumes	and	92	percent	of	its	distillate	sales	volumes	were	sold	on	a	wholesale	or	spot	market basis	to	independent	unbranded	customers	or	other	wholesalers	in	2004.

								Approximately	55	percent	of	MAP's	propane	is	sold	into	the	home	heating	markets	and	industrial	consumers	purchase	the	balance.	Propylene,	cumene,	aromatics, aliphatics,	and	sulfur	are	marketed	to	customers	in	the	chemical	industry.	Base	lube	oils	and	slack	wax	are	sold	throughout	the	United	States.	Pitch	is	also	sold domestically,	but	approximately	16	percent	of	pitch	products	are	exported	into	growing	markets	in	Canada,	Mexico,	India	and	South	America.

								MAP	markets	asphalt	through	owned	and	leased	terminals	throughout	the	Midwest,	the	upper	Great	Plains	and	the	Southeast.	The	MAP	customer	base	includes approximately	800	asphalt-paving	contractors,	government	entities	(states,	counties,	cities	and	townships)	and	asphalt	roofing	shingle	manufacturers.

								The	following	table	sets	forth	the	volume	of	MAP's	consolidated	refined	product	sales	by	product	group	for	each	of	the	last	three	years:

# Refined	Product	Sales

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Gasoline | 807 | 776 | 773 |
| Distillates | 373 | 365 | 346 |
| Propane | 22 | 21 | 22 |
| Feedstocks\tand\tSpecial\tProducts | 92 | 97 | 82 |
| Heavy\tFuel\tOil | 27 | 24 | 20 |
| Asphalt | 79 | 74 | 75 |
| TOTAL | 1,400 | 1,357 | 1,318 |
| Matching\tBuy/Sell\tVolumes\tincluded\tin\tabove | 71 | 64 | 71 |

								MAP	sells	reformulated	gasoline	in	parts	of	its	marketing	territory,	primarily	Chicago,	Illinois;	Louisville,	Kentucky;	northern	Kentucky;	and	Milwaukee, Wisconsin.	MAP	also	sells	low-vapor-pressure	gasoline	in	nine	states.

								As	of	December	31,	2004,	MAP	supplied	petroleum	products	to	about	3,900	Marathon	and	Ashland	branded	retail	outlets	located	primarily	in	Michigan,	Ohio, Indiana,	Kentucky	and	Illinois.	Branded	retail	outlets	are	also	located	in	Florida,	Georgia,	Wisconsin,	West	Virginia,	Tennessee,	Minnesota,	Virginia,	Pennsylvania, North	Carolina,	Alabama,	and	South	Carolina.

								SSA	sells	gasoline	and	diesel	fuel	through	company-operated	retail	outlets.	As	of	December	31,	2004,	SSA	had	1,669	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	$2.3	billion	in	2004,	compared	with	$2.2	billion	in	2003.	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.

								Pilot	Travel	Centers	LLC	("PTC"),	a	joint	venture	with	Pilot	Corporation	("Pilot"),	is	the	largest	operator	of	travel	centers	in	the	United	States	with	approximately 250	locations	in	35	states	at	December	31,	2004.	The	travel	centers

offer	diesel	fuel,	gasoline	and	a	variety	of	other	services,	including	on-premises	brand	name	restaurants.	Pilot	and	MAP	each	own	a	50	percent	interest	in	PTC.

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

# Supply	and	Transportation

								MAP	obtains	the	crude	oil	it	processes	from	negotiated	contracts	and	spot	purchases	or	exchanges.	In	2004,	MAP's	net	purchases	of	U.S.	produced	crude	oil	for refinery	input	averaged	416,000	bpd,	including	a	net	20,000	bpd	from	Marathon.	In	2004,	Canada	was	the	source	for	14	percent	or	130,000	bpd	of	crude	oil	processed and	other	foreign	sources	supplied	42	percent	or	393,000	bpd	of	the	crude	oil	processed	by	MAP's	refineries,	including	approximately	245,000	bpd	from	the	Middle East.	This	crude	was	acquired	from	various	foreign	national	oil	companies,	producing	companies	and	traders.

								MAP	operates	a	system	of	pipelines	and	terminals	to	provide	crude	oil	to	its	refineries	and	refined	products	to	its	marketing	areas.	At	December	31,	2004,	MAP owned,	leased,	or	had	an	ownership	interest	in	approximately	2,860	miles	of	crude	oil	trunk	lines	and	3,850	miles	of	product	trunk	lines.	At	December	31,	2004	MAP had	interests	in	the	following	pipelines:

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

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

•47	percent	interest	in	LOOP	LLC	("LOOP"),	which	is	the	owner	and	operator	of	the	only	U.S.	deepwater	oil	port,	located	18	miles	off	the	coast	of Louisiana;

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

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

•33	percent	interest	in	Minnesota	Pipe	Line	Company,	which	owns	a	crude	oil	pipeline	extending	from	Clearbrook,	Minnesota	to	Cottage	Grove, Minnesota,	which	is	in	the	vicinity	of	MAP's	St.	Paul	Park,	Minnesota	refinery.

								MAP's	84	light	product	and	asphalt	terminals	are	strategically	located	throughout	the	Midwest,	upper	Great	Plains	and	Southeast.	These	facilities	are	supplied	by	a combination	of	pipelines,	barges,	rail	cars	and/or	trucks.	MAP's	marine	transportation	operations	include	towboats	and	barges	that	transport	refined	products	on	the	Ohio, Mississippi	and	Illinois	rivers,	their	tributaries	and	the	Intercoastal	Waterway.	MAP	also	leases	and	owns	rail	cars	in	various	sizes	and	capacities	for	movement	and storage	of	petroleum	products	and	a	large	number	of	tractors,	tank	trailers	and	general	service	trucks.

								Marathon	also	has	interests	in	two	refined	product	pipelines	which	are	not	part	of	MAP:

•17	percent	interest	in	Explorer	Pipeline	Company,	which	is	a	light-product	pipeline	system	extending	from	the	Gulf	of	Mexico	to	the	Midwest;	and

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

								The	above	discussion	of	the	RM&T	segment	includes	forward-looking	statements	concerning	anticipated	completion	of	the	Detroit	refinery	capital	projects.	Some factors	that	could	affect	the	Detroit	projects	include	unforeseen	problems	arising	from	construction,	regulatory	approval	constraints,	availability	of	materials	and	labor, unforeseen	hazards	such	as	weather	conditions	and	other	risks	customarily	associated	with	construction	projects.	These	factors	(among	others)	could	cause	actual	results to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Integrated	Gas

								Our	integrated	gas	operations	include	natural	gas	liquefication	and	regasification	operations,	methanol	operations,	certain	other	gas	processing	facilities	and pipeline	operations,	and	marketing	and	transportation	of	natural	gas.	Also	included	are	the	costs	associated	with	ongoing	development	of	certain	integrated	gas	projects.

# Methanol

								We	own	a	45	percent	interest	in	AMPCO,	which	owns	a	methanol	plant	located	in	Malabo,	Equatorial	Guinea.	Feedstock	for	the	plant	is	supplied	from	a	portion	of our	natural	gas	production	in	the	Alba	field.	Methanol	sales	totaled	980,000	gross	metric	tons	(441,000	net	metric	tons)	in	2004.	Production	from	the	plant	is	used	to supply	customers	in	Europe	and	the	U.S.

# Natural	Gas	Marketing	and	Transportation	Activities

								In	addition	to	the	sale	of	our	own	natural	gas	production,	we	purchase	gas	from	third-party	producers	and	marketers	for	resale.

								We	own	a	24	percent	interest	in	Nautilus	Pipeline	Company,	LLC	and	a	24	percent	interest	in	Manta	Ray	Offshore	Gathering	Company,	LLC,	which	are	both	Gulf of	Mexico	natural	gas	pipeline	systems.	Additionally,	we	own	a	34	percent	interest	in	the	Neptune	natural	gas	processing	plant	located	in	St.	Mary	Parish,	Louisiana.	The plant	has	the	capacity	to	process	600	mmcfd	of	natural	gas,	which	is	supplied	by	the	Nautilus	pipeline	system.

# Alaska	LNG

								We	own	a	30	percent	interest	in	a	Kenai,	Alaska,	natural	gas	liquefication	plant	and	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,	the	LNG	has	been	sold	under	a long-term	contract	with	two	of	Japan's	largest	utility	companies.	LNG	deliveries	totaled	62	gross	bcf	(24	net	bcf)	in	2004.

# Equatorial	Guinea	LNG	Project

								During	2004,	Marathon	and	its	partner,	Compania	Nacional	de	Petroleos	de	Guinea	Ecuatorial	("GEPetrol"),	the	National	Oil	Company	of	Equatorial	Guinea, through	Equatorial	Guinea	LNG	Holdings	Limited	("EGHoldings"),	began	construction	of	an	LNG	plant	on	Bioko	Island	that	will	deliver	a	contracted	offtake	of 3.4	million	metric	tons	per	year	(approximately	460	mmcfd).	This	project	will	allow	us	to	monetize	our	gas	reserves	from	the	Alba	field,	as	natural	gas	for	the	plant	will be	purchased	from	the	Alba	field	participants	under	a	long-term	gas	supply	agreement.	Construction	of	the	plant	continues	to	progress	and	startup	is	projected	for	late 2007.

								At	the	end	of	2004,	we	held	a	75	percent	economic	interest	in	EGHoldings,	with	GEPetrol	holding	the	remaining	25	percent	economic	interest.	In	connection	with the	formation	of	EGHoldings,	GEPetrol	was	given	certain	contractual	rights	with	respect	to	the	purchase	and	resale	to	a	third	party	of	a	13	percent	interest	in EGHoldings	currently	held	by	Marathon.	These	rights	give	GEPetrol	the	option	to	purchase	this	13	percent	interest	and	resell	it	to	a	third	party.	These	rights	specify	that we	will	be	reimbursed	for	our	historical	costs	plus	an	additional	specified	rate	of	return,	which	escalates	depending	on	the	time	period	during	which	such	purchase	and resale	occurs,	and	a	right	to	share	in	additional	proceeds	above	those	amounts	under	certain	circumstances	of	resale.	If	GEPetrol's	rights	are	not	exercised	within	one year	from	date	of	project	sanction,	which	was	in	June	2004,	the	rights	expire.

								EGHoldings	has	signed	a	Sales	and	Purchase	Agreement	with	a	subsidiary	of	BG	Group	plc	("BGML")	under	which	BGML	would	purchase	the	LNG	plant's production	for	a	period	of	17	years	on	an	FOB	Bioko	Island	basis	with	pricing	linked	principally	to	the	Henry	Hub	index.	The	LNG	would	be	targeted	primarily	to	a receiving	terminal	in	Lake	Charles,	Louisiana,	where	it	would	be	regasified	and	delivered	into	the	Gulf	Coast	natural	gas	pipeline	grid.

# Elba	Island	LNG

								During	2004,	we	began	delivering	LNG	cargoes	as	part	of	our	Elba	Island,	Georgia	LNG	regasification	terminal	capacity	rights	agreement.	Under	the	terms	of	the agreement,	we	can	supply	up	to	58	billion	cubic	feet	of	natural	gas	(as	LNG)	per	year,	for	up	to	22	years.

								Also	during	2004,	we	signed	an	agreement	with	BP	Energy	Company	("BP")	under	which	BP	will	supply	us	with	58	bcf	of	natural	gas	per	year,	as	LNG,	for	a minimum	period	of	five	years	beginning	in	the	second	half	of	2005.	We	will

take	delivery	of	LNG	at	the	Elba	Island	LNG	regasification	terminal	with	pricing	linked	to	the	Henry	Hub	index.	This	supply	agreement	with	BP	enables	us	to	fully utilize	our	capacity	rights	at	Elba	Island	during	the	period	of	this	agreement,	while	affording	us	the	flexibility	to	access	this	capacity	to	commercialize	other	stranded	gas resources	beyond	the	term	of	the	BP	contract.	We	continue	to	actively	seek	additional	cargoes	prior	to	the	start	of	deliveries	from	BP.

								The	above	discussion	of	the	integrated	gas	segment	contains	forward	looking	statements	with	respect	to	the	estimated	construction	and	startup	dates	of	a	LNG liquefaction	plant	and	related	facilities.	Factors	that	could	affect	the	estimated	construction	and	startup	dates	of	the	LNG	plant	and	related	facilities	include,	without limitation,	unforeseen	problems	arising	from	construction,	inability	or	delay	in	obtaining	necessary	government	and	third-party	approvals,	unanticipated	changes	in market	demand	or	supply,	environmental	issues,	availability	or	construction	of	sufficient	LNG	vessels,	and	unforeseen	hazards	such	as	weather	conditions.	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	and	development	of	new	reserves.	We	compete	with	major integrated	and	independent	oil	and	gas	companies	for	the	acquisition	of	oil	and	gas	leases	and	other	properties,	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.	As	a	consequence,	we	may	be	at	a	competitive	disadvantage	in	bidding	for	the	rights	to	explore	for	oil	and	gas.	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	believe	we	currently	rank	eighth	among	U.S.-based	petroleum companies	on	the	basis	of	2003	worldwide	liquid	hydrocarbon	and	natural	gas	production.

								Marathon	through	MAP	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.	MAP	believes	it	ranks	fifth	among	U.S.	petroleum	companies	on	the	basis	of	crude	oil	refining	capacity	as	of December	31,	2004.	MAP	competes	in	four	distinct	markets	–	wholesale,	spot,	branded	and	retail	distribution	–	for	the	sale	of	refined	products	and	believes	it	competes 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;	8	refiner/marketers	in	the	supply	of	branded	petroleum	products	to	dealers	and	jobbers;	and approximately	220	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	crude	oil,	natural	gas	and	petroleum	products,	as	well	as	changes	in	competitive	conditions	in	the	markets	we serve.	Generally,	results	from	production	operations	benefit	from	higher	crude	oil	and	natural	gas	prices	while	refining	and	marketing	margins	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	("Reorganization	Agreement"),	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.	Thomas	J.	Usher	is	the non-executive	chairman	of	the	board	of	both	companies,	and,	as	of	December	31,	2004,	four	of	the	ten	remaining	members	of	Marathon's	board	of	directors	are	also directors	of	United	States	Steel.

								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	Marathon's	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	Marathon:

•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	the	lease	term	extending	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	Marathon's	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	Marathon	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.	$2	million	of	the	industrial	revenue	bonds	are	scheduled	to	mature	in	the	period	extending	through December	31,	2009.

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

								The	financial	matters	agreement	also	requires	United	States	Steel	to	use	commercially	reasonable	efforts	to	have	Marathon	released	from	its	obligations	under	a guarantee	Marathon	provided	with	respect	to	all	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	Marathon	to	use	commercially	reasonable	efforts	to	take	all	necessary	action	or	refrain	from	acting	so	as	to	assure compliance	with	all	covenants	and	other	obligations	under	the	documents	relating	to	the	assumed	obligations	to	avoid	the	occurrence	of	a	default	or	the	acceleration	of the	payment	obligations	under	the	assumed	obligations.	The	agreement	also	obligates	Marathon	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	Marathon	under	the	financial	matters	agreement	are	general	unsecured	obligations	that	rank	equal	to	United	States	Steel's accounts	payable	and	other	general	unsecured	obligations.	The	financial	matters	agreement	does	not	contain	any	financial	covenants,	and	United	States	Steel	is	free	to incur	additional	debt,	grant	mortgages	on	or	security	interests	in	its	property	and	sell	or	transfer	assets	without	our	consent.

# Tax	Sharing	Agreement

								Marathon	and	United	States	Steel	have	a	tax	sharing	agreement	that	applies	to	each	of	their	consolidated	tax	reporting	groups.	Provisions	of	this	agreement	include the	following:

•for	any	taxable	period,	or	any	portion	of	any	taxable	period,	ended	on	or	before	December	31,	2001,	unpaid	tax	sharing	payments	will	be	made	between Marathon	and	United	States	Steel	generally	in	accordance	with	the	general	tax	sharing	principles	in	effect	before	the	Separation;

•no	tax	sharing	payments	will	be	made	with	respect	to	taxable	periods,	or	portions	thereof,	beginning	after	December	31,	2001;	and

•provisions	relating	to	the	tax	and	related	liabilities,	if	any,	that	result	from	the	Separation	ceasing	to	qualify	as	a	tax-free	transaction	and	limitations	on post-Separation	activities	that	might	jeopardize	the	tax-free	status	of	the	Separation.

								Under	the	general	tax	sharing	principles	in	effect	before	the	Separation:

•the	taxes	payable	by	each	of	the	Marathon	Group	and	the	U.S.	Steel	Group	were	determined	as	if	each	of	them	had	filed	its	own	consolidated,	combined or	unitary	tax	return;	and

•the	U.S.	Steel	Group	would	receive	the	benefit,	in	the	form	of	tax	sharing	payments	by	the	parent	corporation,	of	the	tax	attributes,	consisting	principally of	net	operating	losses	and	various	credits,	that	its	business	generated	and	the	parent	used	on	a	consolidated	basis	to	reduce	its	taxes	otherwise	payable.

								In	accordance	with	the	tax	sharing	agreement,	at	the	time	of	the	Separation,	Marathon	made	a	preliminary	settlement	with	United	States	Steel	of	approximately $440	million	as	the	net	tax	sharing	payments	owed	to	it	for	the	year	ended	December	31,	2001	under	the	pre-Separation	tax	sharing	principles.

								The	tax	sharing	agreement	also	addresses	the	handling	of	tax	audits	and	contests	and	other	matters	respecting	taxable	periods,	or	portions	of	taxable	periods,	ended before	December	31,	2001.

								In	the	tax	sharing	agreement,	each	of	Marathon	and	United	States	Steel	promised	the	other	party	that	it:

•would	not,	before	January	1,	2004,	take	various	actions	or	enter	into	various	transactions	that	might,	under	section	355	of	the	Internal	Revenue	Code	of 1986,	jeopardize	the	tax-free	status	of	the	Separation;	and

•would	be	responsible	for,	and	indemnify	and	hold	the	other	party	harmless	from	and	against,	any	tax	and	related	liability,	such	as	interest	and	penalties, that	results	from	the	Separation	ceasing	to	qualify	as	tax-free	because	of	its	taking	of	any	such	action	or	entering	into	any	such	transaction.

								The	prescribed	actions	and	transactions	include:

•the	liquidation	of	Marathon	or	United	States	Steel;	and

•the	sale	by	Marathon	or	United	States	Steel	of	its	assets,	except	in	the	ordinary	course	of	business.

								In	case	a	taxing	authority	seeks	to	collect	a	tax	liability	from	one	party	that	the	tax	sharing	agreement	has	allocated	to	the	other	party,	the	other	party	has	agreed	in the	sharing	agreement	to	indemnify	the	first	party	against	that	liability.

								Even	if	the	Separation	otherwise	qualified	for	tax-free	treatment	under	section	355	of	the	Internal	Revenue	Code,	the	Separation	may	become	taxable	to	Marathon under	section	355(e)	of	the	Internal	Revenue	Code	if	capital	stock	representing	a	50	percent	or	greater	interest	in	either	Marathon	or	United	States	Steel	is	acquired, directly	or	indirectly,	as	part	of	a	plan	or	series	of	related	transactions	that	include	the	Separation.	For	this	purpose,	a	"50	percent	or	greater	interest"	means	capital	stock possessing	at	least	50	percent	of	the	total	combined	voting	power	of	all	classes	of	stock	entitled	to	vote	or	at	least	50	percent	of	the	total	value	of	shares	of	all	classes	of capital	stock.	To	minimize	this	risk,	both	Marathon	and	United	States	Steel	agreed	in	the	tax	sharing	agreement	that	they	would	not	enter	into	any	transactions	or	make any	change	in	their	equity	structures	that	could	cause	the	Separation	to	be	treated	as	part	of	a	plan	or	series	of	related	transactions	to	which	those	provisions	of section	355(e)	of	the	Internal	Revenue	Code	may	apply.	If	an	acquisition	occurs	that	results	in	the	Separation	being	taxable	under	section	355(e)	of	the	Internal	Revenue Code,	the	agreement	provides	that	the	resulting	corporate	tax	liability	will	be	borne	by	the	party	involved	in	that	acquisition	transaction.

								Although	the	tax	sharing	agreement	allocates	tax	liabilities	relating	to	taxable	periods	ending	on	or	prior	to	the	Separation,	each	of	Marathon	and	United	States Steel,	as	members	of	the	same	consolidated	tax	reporting	group	during	any	portion	of	a	taxable	period	ended	on	or	prior	to	the	date	of	the	Separation,	is	jointly	and severally	liable	under	the	Internal	Revenue	Code	for	the	federal	income	tax	liability	of	the	entire	consolidated	tax	reporting	group	for	that	year.	To	address	the possibility	that	the	taxing	authorities	may	seek	to	collect	all	or	part	of	a	tax	liability	from	one	party	where	the	tax	sharing	agreement	allocates	that	liability	to	the	other party,	the	agreement	includes	indemnification	provisions	that	would	entitle	the	party	from	whom	the	taxing	authorities	are	seeking	collection	to	obtain	indemnification from	the	other	party,	to	the	extent	the	agreement	allocates	that	liability	to	that	other	party.	Marathon	can	provide	no	assurance,	however,	that	United	States	Steel	will	be able	to	meet	its	indemnification	obligations,	if	any,	to	Marathon	that	may	arise	under	the	tax	sharing	agreement.

# Obligations	Associated	with	the	Separation	as	of	December	31,	2004

								See	"Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	–	Obligations	Associated	with	the	Separation	of	United	States	Steel" on	page	42	for	a	discussion	of	Marathon's	obligations	associated	with	the	Separation.

# Environmental	Matters

								We	maintain	a	comprehensive	environmental	policy	overseen	by	the	Corporate	Governance	and	Nominating	Committee	of	our	Board	of	Directors.	Our	Health, Environment	and	Safety	organization	has	the	responsibility	to	ensure	that	our	operating	organizations	maintain	environmental	compliance	systems	that	are	in	accordance with	applicable	laws	and	regulations.	The	Health,	Environment	and	Safety	Management	Committee,	which	is	comprised	of	our	officers,	is	charged	with	reviewing	its overall	performance	with	various	environmental	compliance	programs.	We	also	have	an	Emergency	Management	Team,	composed	of	senior	management,	which oversees	the	response	to	any	major	emergency	environmental	incident	involving	Marathon	or	any	of	our	properties.

								Our	businesses	are	subject	to	numerous	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.	These	laws	and	their	associated	regulations	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	Marathon	for	the	conduct	of	others	or	conditions	others	have	caused,	or	for	Marathon's	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	standards	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	"Management's	Discussion	and Analysis	of	Environmental	Matters,	Litigation	and	Contingencies"	on	page	44	and	"Legal	Proceedings"	on	page	21.

								Of	particular	significance	to	MAP	are	EPA	regulations	that	require	reduced	sulfur	levels	starting	in	2004	for	gasoline	and	2006	for	diesel	fuel.	MAP's	combined capital	costs	to	achieve	compliance	with	these	rules	are	expected	to	approximate	$900	million	over	the	period	between	2002	and	2006,	which	includes	costs	that	could be	incurred	as	part	of	other	refinery	upgrade	projects.	Costs	incurred	through	December	31,	2004	were	approximately	$520	million.	Some	factors	that	could	potentially affect	MAP's	gasoline	and	diesel	fuel	compliance	costs	include	completion	of	project	detailed	engineering,	construction	and	startup	activities.

								The	U.S.	EPA	has	finalized	new	and	revised	National	Ambient	Air	Quality	Standards	("NAAQS")	for	fine	particulate	emissions	(PM2.5)	and	ozone.	In	connection with	these	new	standards,	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	EPA	has	proposed	a	rule	called	the	Interstate	Air	Quality	Rule	("IAQR")	that	will	require	significant	reductions	of	SO 2	and	NOx	emissions	in numerous	states.	All	of	our	refinery	operations	are	located	in	these	affected	states.	If	this	rule	is	finalized,	it	could	have	a	significant	impact	on	our	operations	as	well	as the	operations	of	many	of	our	competitors.	At	this	time,	we	cannot	determine	whether	the	IAQR	will	be	finalized	or	whether	it	will	be	substantially	changed	before	it	is final.	As	a	result,	we	cannot	presently	reasonably	estimate	the	financial	impact	of	such	a	rule.

# 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.	As	of	December	31,	2004,	all	of	the	barges	used	in	MAP's	river	transportation	operations 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.

# Solid	Waste

								We	continue	to	seek	methods	to	minimize	the	generation	of	hazardous	wastes	in	our	operations.	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.	Since	the	EPA	has	not	yet	promulgated	implementing	regulations	for all	provisions	of	RCRA	and	has	not	yet	made	clear	the	practical	application	of	all	the	implementing	regulations	it	has	promulgated,	the	ultimate	cost	of	compliance	with this	statute	cannot	be	accurately	estimated.	In	addition,	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.

# 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	fund	once	the	applicable	deductible	has	been	satisfied.	Accruals	for	remediation	expenses	and	associated	reimbursements	are established	for	sites	where	contamination	has	been	determined	to	exist	and	the	amount	of	associated	costs	is	reasonably	determinable.

								As	a	general	rule,	Marathon	and	Ashland	retained	responsibility	for	certain	remediation	costs	arising	out	of	the	prior	ownership	and	operation	of	businesses transferred	to	MAP.	Such	continuing	responsibility,	in	certain	situations,	may	be	subject	to	threshold	or	sunset	agreements,	which	gradually	diminish	this	responsibility over	time.

# Properties

								The	location	and	general	character	of	the	principal	oil	and	gas	properties,	refineries	and	gas	plants,	pipeline	systems	and	other	important	physical	properties	of Marathon	have	been	described	previously.	Except	for	oil	and	gas	producing	properties,	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.

								The	basis	for	estimating	oil	and	gas	reserves	is	set	forth	in	"Consolidated	Financial	Statements	and	Supplementary	Data	–	Supplementary	Information	on	Oil	and Gas	Producing	Activities	–	Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves"	on	pages	F-45	through	F-46.

# Property,	Plant	and	Equipment	Additions

								For	property,	plant	and	equipment	additions,	see	"Management's	Discussion	and	Analysis	of	Financial	Condition,	Cash	Flows	and	Liquidity	–	Capital Expenditures"	on	page	39.

# Employees

								We	had	25,804	active	employees	as	of	December	31,	2004,	including	22,661	MAP	employees.	Of	the	total	number	of	MAP	employees,	16,413	were	employees	of Speedway	SuperAmerica	LLC,	most	of	which	were	employed	at	retail	marketing	outlets.

								Certain	hourly	employees	at	the	Catlettsburg	and	Canton	refineries	are	represented	by	the	Paper,	Allied-Industrial,	Chemical	and	Energy	Workers	International Union	under	labor	agreements	that	expire	on	January	31,	2006.	The	same	union	represents	certain	hourly	employees	at	the	Texas	City	refinery	under	a	labor	agreement that	expires	on	March	31,	2006.	The	International	Brotherhood	of	Teamsters	represents	certain	hourly	employees	under	labor	agreements	that	are	scheduled	to	expire	on May	31,	2006	at	the	St.	Paul	Park	refinery	and	January	31,	2007	at	the	Detroit	refinery.

# Available	Information

								General	information	about	Marathon,	including	the	Corporate	Governance	Principles	and	Charters	for	the	Audit	Committee,	Compensation	Committee,	Corporate Governance	and	Nominating	Committee,	and	Committee	on	Financial	Policy,	can	be	found	at	www.marathon.com.	In	addition,	our	Code	of	Business	Conduct	and	Code of	Ethics	for	Senior	Financial	Officers	are	available	on	the	website	at	www.marathon.com/Values/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	Form	10-K	or	other	securities	filings.

# 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	in	this	discussion.	The	ultimate	resolution	of	these	contingencies	could, individually	or	in	the	aggregate,	be	material.	However,	management	believes	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

								Marathon	was	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.	The	first	case,	U.S.	ex	rel	Jack	J.	Grynberg	v.	Alaska	Pipeline	Co.,	et	al.	is	primarily	a	gas	measurement	case,	and	the second	case,	U.S.	ex	rel	Harrold	E.	Wright	v.	Agip	Petroleum	Co.	et	al,	is	primarily	a	gas	valuation	case.	These	cases	assert	that	false	claims	have	been	filed	by	lessees and	that	penalties,	damages	and	interest	total	more	than	$25	billion.	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.	The matters	are	in	the	discovery	phase	and	Marathon	intends	to	vigorously	defend	these	cases.

# Powder	River	Basin	Litigation

								The	U.S.	Bureau	of	Land	Management	("BLM")	completed	a	multi-year	review	of	potential	environmental	impacts	from	coal	bed	methane	development	on	federal lands	in	the	Powder	River	Basin	in	Montana	and	Wyoming.	The	Agency's	Record	of	Decision	("ROD")	was	signed	on	April	30,	2003	supporting	increased	coal	bed methane	development.	Plaintiff	environmental	and	other	groups	filed	four	suits	in	May	2003	in	the	U.S.	District	Court	for	the	District	of	Montana	against	the	BLM alleging	the	Agency's	environmental	impact	review	was	not	adequate.	Plaintiffs	seek	a	court	order	enjoining	coal	bed	methane	development	on	federal	lands	in	the Powder	River	Basin	until	BLM	conducts	additional	studies	on	the	environmental	impact.	Marathon	has	been	allowed	to	intervene	as	a	party	in	all	four	of	the	cases.	As the	lawsuits	to	delay	energy	development	in	the	Powder	River	Basin	progress	through	the	courts,	BLM	continues	to	process	permits	to	drill	under	the	ROD.	In January	2004,	the	Court	over	protests	of	Plaintiffs,	transferred	to	the	District	Court	of	Wyoming,	portions	of	two	of	the	cases	dealing	with	the	sufficiency	of	the environmental	impact	review	as	to	lands	in	Wyoming.

								In	May	2004,	plaintiff	environmental	groups	Environmental	Defense	et	al,	filed	suit	against	the	U.S.	Bureau	of	Land	Management	("BLM")	in	Montana	Federal District	Court,	alleging	the	agency	did	not	adequately	consider	air

quality	impacts	of	coal	bed	methane	and	oil	and	gas	operations	in	the	Powder	River	Basin	in	Montana	and	Wyoming	when	preparing	its	environmental	impact statements.	Plaintiffs	request	that	BLM	be	ordered	to	cease	issuing	leases	and	permits	for	energy	development,	until	additional	analysis	of	predicted	air	impacts	is conducted.	Marathon	and	Pennaco	Energy,	Inc.	have	intervened	in	the	litigation.

# Environmental	Proceedings

								The	following	is	a	summary	of	proceedings	involving	Marathon	that	were	pending	or	contemplated	as	of	December	31,	2004,	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	Item	3.	"Legal	Proceedings"	above	takes	such	matters	into	account.

								Claims	under	the	Comprehensive	Environmental	Response,	Compensation	and	Liability	Act	("CERCLA")	and	related	state	acts	have	been	raised	with	respect	to	the cleanup	of	various	waste	disposal	and	other	sites.	CERCLA	is	intended	to	facilitate	the	cleanup	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	cleanup	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.

								Projections,	provided	in	the	following	paragraphs,	of	spending	for	and/or	timing	of	completion	of	specific	projects	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,	or	timing	of	completion	of	environmental	projects	may	differ	materially	from	those	stated	in	the	forward-looking	statements.

								At	December	31,	2004,	Marathon	had	been	identified	as	a	PRP	at	a	total	of	six	CERCLA	waste	sites.	Based	on	currently	available	information,	which	is	in	many cases	preliminary	and	incomplete,	Marathon	believes	that	its	liability	for	cleanup	and	remediation	costs	in	connection	with	all	but	one	of	these	sites	will	be	under $1	million	per	site,	and	most	will	be	under	$100,000.	Marathon	believes	that	its	liability	for	cleanup	and	remediation	costs	in	connection	with	the	one	remaining	site	will be	under	$4	million.

								In	addition,	there	is	one	site	where	Marathon	has	received	information	requests	or	other	indications	that	it	may	be	a	PRP	under	CERCLA	but	where	sufficient information	is	not	presently	available	to	confirm	the	existence	of	liability.

								There	are	also	131	additional	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.	Of	these	sites,	14	were	associated	with	properties	conveyed	to MAP	by	Ashland	which	has	retained	liability	for	all	costs	associated	with	remediation.	Based	on	currently	available	information,	which	is	in	many	cases	preliminary	and incomplete,	Marathon	believes	that	its	liability	for	cleanup	and	remediation	costs	in	connection	with	25	of	these	sites	will	be	under	$100,000	per	site,	53	sites	have potential	costs	between	$100,000	and	$1	million	per	site,	19	sites	may	involve	remediation	costs	between	$1	million	and	$5	million	per	site	and	8	sites	have	incurred remediation	costs	of	more	than	$5	million	per	site.	There	are	11	sites	with	insufficient	information	to	estimate	future	remediation	costs.

								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	five	years,	Marathon	anticipates	spending	less	than	$7	million	at	this	site.	Expenditures	in	2004	were approximately	$391,000,	and	expenditures	in	2005	are	expected	to	be	$600,000	as	technical	evaluation	continues,	and	could	be	as	much	as	$3,900,000	if	soil	remediation is	commenced	in	the	second	half	of	the	year.	Ongoing	work	at	this	site	is	subject	to	approval	by	the	MDEQ,	and	a	risk-based	closure	strategy	is	being	developed	for approval	by	the	MDEQ.

								MAP	has	had	a	pending	enforcement	matter	with	the	Illinois	Environmental	Protection	Agency	and	the	Illinois	Attorney	General's	Office	since	2002	concerning MAP's	self-reporting	of	possible	emission	exceedences	and	permitting	issues	related	to	storage	tanks	at	its	Robinson,	Illinois	refinery.	MAP	has	had	periodic	discussions with	Illinois	officials	regarding	this	matter	and	more	discussions	may	occur	in	2005.

								In	July,	2002,	Marathon	received	a	Notice	of	Enforcement	from	the	State	of	Texas	for	alleged	excess	air	emissions	from	its	Yates	Gas	Plant	and	production operations	on	its	Kloh	lease.	A	settlement	of	this	matter	was	finalized	in	2004,	with	Marathon	and	its	co-owners	paying	a	civil	penalty	of	$74,000	and	the	donation	of land	as	a	Supplemental	Environmental	Project	in	lieu	of	a	further	penalty	of	$74,000.	Marathon	is	owner	of	a	38%	interest	in	the	facilities.

								In	May,	2003,	Marathon	received	a	Consolidated	Compliance	Order	&	Notice	or	Potential	Penalty	from	the	State	of	Louisiana	for	alleged	various	air	permit regulatory	violations.	This	matter	was	settled	for	a	civil	penalty	of	$148,628	and	awaits	formal	closure	with	the	State.

								In	August	of	2004,	the	West	Virginia	Department	of	Environmental	Protection	("WVDEP")	submitted	a	draft	consent	order	to	MAP	regarding	MAP's	handling	of alleged	hazardous	waste	generated	from	tank	cleanings	in	the	State	of	West	Virginia.	The	proposed	order	seeks	a	civil	penalty	of	$337,900.	MAP	has	met	with	the WVDEP	and	discussions	are	ongoing	in	an	attempt	to	resolve	this	matter.

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

# PART	II

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

								The	principal	market	on	which	the	Company's	common	stock	is	traded	is	the	New	York	Stock	Exchange.	The	Company's	common	stock	is	also	traded	on	the Chicago	Stock	Exchange	and	the	Pacific	Exchange.	Information	concerning	the	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	"Selected	Quarterly	Financial	Data	(Unaudited)"	on page	F-41.

								The	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	financial	statements	of	Marathon.	Dividends	on	Marathon	common	stock	are	limited	to	legally	available	funds	of Marathon.

								The	following	table	provides	information	about	purchases	by	Marathon	and	its	affiliated	purchaser	during	the	fourth	quarter	ended	December	31,	2004	of	equity securities	that	are	registered	by	Marathon	pursuant	to	Section	12	of	the	Exchange	Act:

# ISSUER	PURCHASES	OF	EQUITY	SECURITIES

|  |  |  |  |  |  |  | Maximum |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  |  | Total\tNumber | Total\tNumber |  | Number\tof |  |
|  |  |  |  | of\tShares |  |  | Shares\tthat |  |
|  |  |  |  | Purchased\tas | Purchased\tas |  | May\tYet\tBe |  |
|  | Total\tNumber |  |  | Part\tof\tPublicly | Part\tof\tPublicly |  | Purchased\tUnder |  |
|  | of\tShares |  | Average\tPrice | Announced\tPlans | Announced\tPlans |  | the\tPlans\tor |  |
| Period | Purchased | (1)(2) | Paid\tper\tShare | or\tPrograms | (1) |  | Programs |  |
| 10/01/04\t–\t10/31/04 |  | 6,015 | $40.51 |  |  | N/A |  | N/A |
| 11/01/04\t–\t11/30/04 |  | 5,145 | $38.94 |  |  | N/A |  | N/A |
| 12/01/04\t–\t12/31/04 |  | 34,526 | $37.07 |  |  | N/A |  | N/A |
| Total: |  | 45,686 | $37.73 |  |  | N/A |  | N/A |

(1) 42,749	shares	were	repurchased	in	open-market	transactions	under	the	Marathon	Oil	Corporation	Dividend	Reinvestment	and	Direct	Stock	Purchase	Plan	(the	"Plan")	by	the	administrator	of	the	Plan.	Stock needed	to	meet	the	requirements	of	the	Plan	are	either	purchased	in	the	open	market	or	issued	directly	by	Marathon.

(2) 2,936	shares	of	restricted	stock	were	delivered	by	employees	to	Marathon,	upon	vesting,	to	satisfy	tax	withholding	requirements.

# Item	6.	Selected	Financial	Data

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

								Marathon	Oil	Corporation	is	engaged	in	worldwide	exploration	and	production	of	crude	oil	and	natural	gas;	domestic	refining,	marketing	and	transportation	of crude	oil	and	petroleum	products	primarily	through	our	62	percent	owned	subsidiary,	Marathon	Ashland	Petroleum	LLC	("MAP");	and	integrated	gas.	Management's Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	should	be	read	in	conjunction	with	Items	1.	and	2.	Business	and	Properties,	Item	6.	Selected Financial	Data	and	Item	8.	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	businesses.	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.

								Unless	specifically	noted,	amounts	for	MAP	include	the	38	percent	interest	held	by	Ashland	Inc.	("Ashland"),	and	amounts	for	Equatorial	Guinea	LNG	Holdings Limited	("EGHoldings")	include	the	25	percent	interest	held	by	Compania	Nacional	de	Petroleos	de	Guinea	Ecuatorial	("GEPetrol").

# Overview

								Exploration	and	production	("E&P")	segment	revenues	correlate	closely	with	prevailing	prices	for	the	various	qualities	of	crude	oil	and	natural	gas	produced.	The increase	in	our	E&P	segment	revenues	during	2004	tracked	the	increase	in	prices	for	these	commodities.	The	robust	prices	for	crude	oil	during	2004	were	caused	in	part by	increased	demand	in	strengthening	economies,	particularly	in	the	United	States	and	China,	weather	related	damages	and	disruptions,	the	influence	of	OPEC,	as	well as	civil	and	political	unrest	and	military	actions	in	various	oil	exporting	countries.	The	average	spot	price	during	2004	for	West	Texas	Intermediate	("WTI"),	a benchmark	crude	oil,	was	$41.47	per	barrel	–	up	from	an	average	of	$30.99	in	2003	–	and	ended	the	year	at	$43.45.	The	differential	between	WTI	and	Brent	(an international	benchmark	crude	oil)	widened	to	$3.20	in	2004	from	$2.16	in	2003,	primarily	because	shipping	freight	rates	were	much	higher	in	2004	and	it	cost	more	to transport	a	Brent-based	international	barrel	to	the	U.S.	Marathon's	domestic	crude	production	is	on	average	heavier	and	higher	in	sulfur	content	than	light	sweet	WTI. Heavier	and	higher	sulfur	crude	oil	(commonly	referred	to	as	sour	crude)	sells	at	a	discount	to	light	sweet	crude	oil.	The	majority	of	OPEC	spare	capacity	and	new production	worldwide	is	medium	sour	or	heavy	sour,	so	the	discount	for	medium	and	heavy	sour	crudes	has	increased	relative	to	light	sweet	crude	and	thus	reduced	the relative	profitability	of	sour	crude	production.	Marathon's	international	crude	production	is	relatively	sweet	and	is	generally	sold	in	relation	to	the	Brent	crude benchmark.

								Natural	gas	prices	were	higher	in	2004	as	compared	to	2003.	A	significant	portion	of	our	United	States	lower	48	natural	gas	production	is	sold	at	bid	week	prices, making	this	indicator	particularly	important.	The	average	quarterly	bid	week	prices	for	2004	were	$5.69,	$6.00,	$5.75	and	$7.07	for	the	first	to	fourth	quarter.	Natural gas	prices	in	Alaska	are	largely	contractual,	while	natural	gas	production	there	is	seasonal	in	nature,	trending	down	during	the	second	and	third	quarters	and	increasing during	the	fourth	and	first	quarters.	Our	other	major	gas-producing	regions	are	Europe	and	Equatorial	Guinea,	where	large	portions	of	our	gas	are	sold	at	contractual prices,	making	realized	prices	in	these	areas	less	volatile.

								For	additional	information	on	price	risk	management,	see	"Item	7A.	Quantitative	and	Qualitative	Disclosures	About	Market	Risk"	on	page	50.

								E&P	segment	income	during	2004	was	impacted	by	lower	production	(on	an	equivalent	barrel	basis)	–	down	approximately	13	percent	from	2003	levels.	We estimate	that	our	2005	production	will	average	approximately	325,000	to	350,000	barrels	of	oil	equivalent	per	day	("BOEPD"),	excluding	the	impact	of	acquisitions, dispositions	or	potential	reentry	into	Libya.	Our	continued	exploration	success	coupled	with	ongoing	development	of	our	base	businesses	and	new	core	areas,	provides defined	production	growth	that	is	expected	to	increase	our	average	daily	production	by	an	estimated	compounded	average	growth	rate	of	five	to	nine	percent	between 2005	and	2008.

								Projected	production	levels	for	liquid	hydrocarbons	and	natural	gas	are	based	on	a	number	of	assumptions,	including	(among	others)	prices,	supply	and	demand, regulatory	constraints,	reserve	estimates,	production	decline

rates	for	mature	fields,	reserve	replacement	rates,	drilling	rig	availability	and	geological	and	operating	considerations.	These	assumptions	may	prove	to	be	inaccurate. Prices	have	historically	been	volatile	and	have	frequently	been	driven	by	unpredictable	changes	in	supply	and	demand	resulting	from	fluctuations	in	economic	activity and	political	developments	in	the	world's	major	oil	and	gas	producing	areas,	including	OPEC	member	countries.	Any	substantial	decline	in	such	prices	could	have	a material	adverse	effect	on	our	results	of	operations.	A	decline	in	such	prices	could	also	adversely	affect	the	quantity	of	liquid	hydrocarbons	and	natural	gas	that	can	be economically	produced	and	the	amount	of	capital	available	for	exploration	and	development.

								E&P	operations	are	subject	to	various	hazards,	including	acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response	thereto,	explosions,	fires	and uncontrollable	flows	of	oil	and	gas.	Offshore	production	and	marine	operations	in	areas	such	as	the	Gulf	of	Mexico,	the	North	Sea,	the	U.K.	Atlantic	Margin,	the	Celtic Sea,	offshore	Nova	Scotia	and	offshore	West	Africa	are	also	subject	to	severe	weather	conditions	such	as	hurricanes	or	violent	storms	or	other	hazards.	Development	of new	production	properties	in	countries	outside	the	United	States	may	require	protracted	negotiations	with	host	governments	and	are	frequently	subject	to	political considerations,	such	as	tax	regulations,	which	could	adversely	affect	the	economics	of	projects.

								MAP	refines,	markets	and	transports	crude	oil	and	petroleum	products,	primarily	in	the	Midwest,	the	upper	Great	Plains	and	southeastern	United	States.	Refining, marketing	and	transportation	("RM&T")	segment	income	primarily	represents	MAP's	income	from	operations	which	depends	largely	on	the	refining	and	wholesale marketing	margin,	refinery	throughputs,	retail	marketing	margins	for	gasoline,	distillates	and	merchandise,	and	the	profitability	of	its	pipeline	transportation	operations.

								The	refining	and	wholesale	marketing	margin	is	the	difference	between	the	wholesale	prices	of	refined	products	sold	and	the	cost	of	crude	oil	and	other	feedstocks refined,	the	cost	of	purchased	products	and	manufacturing	costs.	MAP	purchases	crude	oil	to	satisfy	the	throughput	requirements	of	its	refineries.	As	a	result,	its	refining and	wholesale	marketing	margin	could	be	adversely	affected	by	rising	crude	oil	and	other	feedstock	prices	that	are	not	recovered	in	the	marketplace.	The	crack	spread, which	is	a	measure	of	the	difference	between	spot	market	gasoline	and	distillate	prices	and	spot	market	crude	costs,	is	an	industry	indicator	of	refining	margins.	In addition	to	changes	in	the	crack	spread,	MAP's	refining	and	wholesale	marketing	margin	is	impacted	by	the	types	of	crude	oil	processed,	the	wholesale	selling	prices realized	for	all	the	products	sold	and	the	level	of	manufacturing	costs.	MAP	processes	significant	amounts	of	sour	crude	oil	which	enhances	its	competitive	position	in the	industry	as	sour	crude	oil	typically	can	be	purchased	at	a	discount	to	sweet	crude	oil.	As	crude	oil	production	increases	in	the	coming	years,	heavy	sour	crude	oil production	growth	is	expected	to	outpace	sweet	crude	oil	production	growth,	which	may	translate	into	higher	sour	crude	oil	discounts	going	forward.	Over	the	last	three years,	approximately	60	percent	of	the	crude	oil	throughput	at	MAP's	refineries	has	been	sour	crude	oil.	Sales	of	asphalt	increase	during	the	highway	construction	season in	MAP's	market	area	which	is	primarily	in	the	second	and	third	calendar	quarters.	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.	Changes	in	manufacturing	costs	from	period	to	period	are primarily	dependent	on	the	level	of	maintenance	activities	at	the	refineries	and	the	price	of	purchased	natural	gas.	The	refining	and	wholesale	marketing	margin	has	been historically	volatile	and	varies	with	the	level	of	economic	activity	in	the	various	marketing	areas,	the	regulatory	climate,	logistical	capabilities	and	the	expectations regarding	the	adequacy	of	the	supply	of	refined	products	and	raw	materials.

								For	information	on	price	risk	management,	see	"Item	7A.	Quantitative	and	Qualitative	Disclosures	About	Market	Risk"	on	page	50.

								Additionally,	the	retail	marketing	gasoline	and	distillate	margin,	which	is	the	difference	between	the	ultimate	price	paid	by	consumers	and	the	wholesale	cost	of	the refined	products,	including	secondary	transportation,	plays	an	important	part	in	downstream	profitability.	The	retail	gasoline	and	distillate	margin	has	been	historically volatile,	but	tends	to	be	countercyclical	to	the	refining	and	wholesale	marketing	margin.	Factors	affecting	the	retail	gasoline	and	distillate	margin	include	competition, seasonal	demand	fluctuations,	the	available	wholesale	supply,	the	level	of	economic	activity	in	the	marketing	areas	and	weather	situations	that	impact	driving	conditions. Gross	margins	on	merchandise	sold	at	retail	outlets	tend	to	be	less	volatile	than	the	gross	margin	from	the	retail	sale	of	gasoline	and	diesel	fuel.	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	the	marketing areas.	The	profitability	of	MAP's	pipeline	transportation	operations	is	primarily	dependent	on	the	volumes	shipped	through	the	pipelines.	The	volume	of	crude	oil	that MAP	transports	is	directly	affected	by	the	supply	of,	and	refiner	demand	for,	crude	oil	in	the	markets	served	directly	by	MAP's	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	transportation	modes,	and	the	refinery	and

transportation	system	maintenance	levels.	The	throughput	of	the	refined	products	that	MAP	transports	is	directly	affected	by	the	production	level	of,	and	user	demand for,	refined	products	in	the	markets	served	by	MAP's	refined	product	pipelines.	In	most	of	MAP's	markets,	demand	for	gasoline	peaks	during	the	summer	driving	season, which	extends	from	May	through	September,	and	declines	during	the	fall	and	winter	months.	The	seasonal	pattern	for	distillates	is	the	reverse	of	this,	helping	to	level overall	movements	on	an	annual	basis.	As	with	crude	oil,	other	transportation	alternatives	and	maintenance	levels	influence	refined	product	movements.

								Environmental	regulations,	particularly	the	1990	amendments	to	the	Clean	Air	Act,	have	imposed	(and	are	expected	to	continue	to	impose)	increasingly	stringent and	costly	requirements	on	refining	and	marketing	operations	that	may	have	an	adverse	effect	on	margins	and	financial	condition.	Refining,	marketing	and transportation	operations	are	subject	to	business	interruptions	due	to	unforeseen	events	such	as	explosions,	fires,	crude	oil	or	refined	product	spills,	inclement	weather	or labor	disputes.	They	are	also	subject	to	the	additional	hazards	of	marine	operations,	such	as	capsizing,	collision	and	damage	or	loss	from	severe	weather	conditions.

								Our	integrated	gas	("IG")	operations	include	marketing	and	transporting	natural	gas	and	products	manufactured	from	natural	gas,	such	as	liquefied	natural	gas ("LNG")	and	methanol,	primarily	in	the	United	States,	Europe	and	West	Africa.	Also	included	are	the	costs	associated	with	ongoing	development	of	certain	integrated gas	projects,	such	as	the	LNG	project	in	Equatorial	Guinea.	The	profitability	of	these	operations	depends	largely	on	commodity	prices,	volume	deliveries,	margins	on resale	gas,	and	demand.	Methanol	spot	pricing	is	volatile	largely	because	global	methanol	demand	is	only	33	million	tons	and	any	major	unplanned	shutdown	or	addition in	production	capacity	can	have	a	significant	impact	on	the	supply-demand	balance.	IG	operations	could	be	impacted	by	unforeseen	events	such	as	explosions,	fires, product	spills,	inclement	weather	or	availability	of	LNG	vessels.	They	are	also	subject	to	the	additional	hazards	of	marine	operations,	such	as	capsizing,	collision	and damage	or	loss	from	severe	weather	conditions.

# 2004	Operating	Highlights

•We	realized	continued	exploration	success	with	six	discoveries	including	the	Deep	Luba	and	Gardenia	wells	in	Equatorial	Guinea,	the	Venus	and	Canela wells	in	Angola,	the	Hamsun	well	in	Norway	and	the	Neptune	7	well	in	the	Gulf	of	Mexico.

•We	strengthened	core	areas	by:

•Receiving	approval	of	the	plan	of	development	and	operation	("PDO")	for	the	Alvheim	project	in	Norway	and	reaching	agreement	to	develop Vilje	through	the	Alvheim	infrastructure;

•Completing	the	Equatorial	Guinea	condensate	expansion	project	and	advancing	the	liquefied	petroleum	gas	("LPG")	expansion	project;	and

•Receiving	planning	permission	from	the	Irish	authorities	for	the	Corrib	development.

•We	added	net	proved	reserves	of	221	million	barrels	of	oil	equivalent	("BOE"),	excluding	2	million	BOE	of	dispositions,	while	producing	122	million BOE	of	production	during	2004.	Over	the	past	three	years,	we	have	added	net	proved	reserves	of	782	million	BOE,	excluding	dispositions	of	280	million, while	producing	411	million	BOE.	Three-year	amounts	include	7	million	BOE	of	net	proved	reserve	additions,	19	million	BOE	of	dispositions	and 7	million	BOE	of	production	related	to	equity	investees.

# •We	strengthened	MAP	assets	by:

•Completing	the	Catlettsburg,	Kentucky	refinery	repositioning	project,	which	has	improved	product	yields,	lowered	overall	refinery	costs	and allowed	MAP	to	meet	the	Tier	II	gasoline	regulations;

•Increasing	crude	oil	capacity	at	our	Garyville,	Louisiana	refinery	from	232,000	barrels	per	day	("bpd")	to	245,000	bpd,	which	allowed	us	to achieve	record	crude	oil	and	other	feedstock	refinery	throughputs	of	1,110,000	bpd;

•Progressing	an	expansion	project	to	increase	the	capacity	of	the	Detroit,	Michigan	refinery;	and

•Increasing	same	store	merchandise	sales	by	11	percent	at	Speedway	SuperAmerica	LLC	("SSA").

•We	advanced	our	integrated	gas	strategy	by:

•Reaching	final	investment	decision	and	beginning	construction	on	a	3.4	million	metric	tonnes	per	year	LNG	plant	in	Equatorial	Guinea;

•Signing	an	agreement	with	BP	Energy	Company	under	which	BP	will	supply	us	with	58	billion	cubic	feet	("bcf")	of	natural	gas	per	year,	as	LNG, for	a	minimum	period	of	5	years,	beginning	in	the	second	half	of	2005;

•Securing	six	cargos	of	LNG	utilizing	our	Elba	Island,	Georgia	LNG	regasification	terminal	delivery	rights;	and

•Completing	the	construction	and	operation	of	a	gas-to-liquids	("GTL")	demonstration	plant	at	the	Port	of	Catoosa,	Oklahoma.

•We	signed	an	agreement	to	acquire	Ashland's	38	percent	interest	in	MAP	and	continue	to	pursue	completion	of	the	transaction.

•We	continued	our	business	transformation	programs,	including	implementation	of	two	outsourcing	agreements,	to	achieve	further	business	process improvements	and	cost	reductions.

•We	increased	the	quarterly	dividend	to	28	cents	per	share.

# Management's	Discussion	and	Analysis	of	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,	the	disclosure	of	contingent	assets	and	liabilities	at	year	end	and	the	reported	amounts	of	revenues	and	expenses	during	the year.	Actual	results	could	differ	from	the	estimates	and	assumptions	used.

								Certain	accounting	estimates	are	considered	to	be	critical	if	a)	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	b)	the	impact	of	the	estimates	and	assumptions	on	financial condition	or	operating	performance	is	material.

# Estimated	Net	Recoverable	Quantities	of	Oil	and	Gas

								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	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	depleted	or	amortized	into	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	for	impairment	of	such	properties	and	the	expected future	taxable	income	available	to	realize	the	value	of	deferred	tax	assets	also	rely	in	part	on	estimates	of	net	recoverable	quantities	of	oil	and	gas.

								Proved	reserves	are	the	estimated	quantities	of	oil	and	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	and	negatively,	as	additional information	becomes	available	and	as	contractual,	economic	and	political	conditions	change.	During	2004,	net	revisions	of	previous	estimates	increased	total	proved reserves	by	81	million	BOE	as	a	result	of	190	million	BOE	in	positive	revisions	which	were	partially	offset	by	109	million	BOE	in	negative	revisions.

								Our	estimation	of	net	recoverable	quantities	of	oil	and	gas	is	a	highly	technical	process	performed	primarily	by	internal	teams	of	in-house	reservoir	engineers	and geoscience	professionals.	All	estimates	prepared	by	these	internal	teams	are	approved	by	members	of	the	Corporate	Reserve	Group	upon	input	into	Marathon's	Reserve System.	Any	change	to	proved	reserves	in	excess	of	2.5	million	BOE,	on	a	field-total	basis	for	a	single	month,	must	be	approved	by	the	Director	of	Corporate	Reserves. In	2003,	we	implemented	a	process	to	have	third	party	consultants	audit	the	top	80	percent	of	our	reserves	over	a	3	year	period.	Those	third	party	audits	have	been completed	on	roughly	50	percent	of	our	year-end	2004	reserves	and	have	not	resulted	in	any	reserve	changes.	In	addition	to	third	party	audits,	the	Corporate	Reserve Group	routinely	audits	properties	with	problematic	indicators	such	as	excessively	long	reserves	life,	sudden	changes	in	performance,	changes	in	economic	or	operating conditions,	or	recent	acquisitions	of	material	fields.

								The	reserves	of	the	Alba	field	offshore	Equatorial	Guinea	comprise	approximately	40	percent	of	our	total	proved	oil	and	gas	reserves.	The	next	five	largest	oil	and gas	producing	asset	groups	–	the	Brae	Area	Complex	offshore	the	United	Kingdom,	the	Alvheim/Vilje	development	offshore	Norway,	the	Kenai	field	in	Alaska,	the Petronius

development	in	the	Gulf	of	Mexico	and	the	Foinaven	area	complex	offshore	the	United	Kingdom	–	comprise	a	total	of	approximately	20	percent	of	our	total	proved	oil and	gas	reserves.

# Impairment	of	Long-lived	Assets

								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 is	generally	on	a	field-by-field	basis	for	E&P	assets,	at	the	refinery	and	associated	distribution	system	level	or	at	the	pipeline	system	level	for	downstream	assets,	or	at	a site	level	for	retail	stores.	If	the	sum	of	the	undiscounted	pretax	cash	flows	is	less	than	the	carrying	value	of	an	asset	group,	the	carrying	value	is	written	down	to estimated	fair	value.

								The	expected	future	cash	flows	from	our	oil	and	gas	producing	asset	groups	require	assumptions	about	matters	such	as	future	oil	and	gas	prices,	estimated recoverable	quantities	of	oil	and	gas,	expected	field	performance	and	the	political	environment	in	the	host	country.	An	impairment	of	any	of	our	large	oil	and	gas producing	property	asset	groups	could	have	a	material	impact	on	the	presentation	of	financial	condition,	changes	in	financial	condition	or	results	of	operations.

								Marathon	evaluates	its	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	or	future	plans	to	develop	acreage	are	also	considered.

								The	expected	future	cash	flows	from	our	downstream	assets	require	assumptions	about	matters	such	as	future	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.

								During	the	fourth	quarter	of	2004,	we	recorded	an	impairment	of	$32	million	related	to	unproved	properties	and	$12	million	related	to	producing	properties primarily	due	to	unsuccessful	developmental	drilling	activity	in	Russia.	During	the	years	ended	December	31,	2003	and	2002,	we	did	not	have	significant	impairment charges.

# Suspended	Exploratory	Well	Costs

								We	use	the	successful	efforts	method	of	accounting	for	oil	and	gas	producing	activities.	Costs	to	acquire	mineral	interests	in	oil	and	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	on	our	balance	sheet	if	(a)	the	well	has	found	a	sufficient	quantity	of	reserves	to	justify	its	completion	as	a	producing well	and	(b)	we	are	making	sufficient	progress	assessing	the	reserves	and	the	economic	and	operating	viability	of	the	project.	Otherwise,	well	costs	are	expensed	if	a determination	as	to	whether	proved	reserves	were	found	cannot	be	made	within	one	year	following	the	completion	of	drilling	and	these	criteria	are	not	met.	It	is	not unusual	for	costs	associated	with	complex	deepwater	or	international	discoveries	to	be	suspended	on	our	balance	sheet	for	more	than	a	year	while	we	are	performing additional	appraisal	work,	determining	an	optimal	plan	of	development	or	awaiting	project	sanction	by	our	Board	of	Directors,	our	co-venturers	and	the	government entity	having	jurisdiction	over	the	area	under	development.	However,	we	continually	monitor	the	progress	being	made	towards	the	ultimate	development	of	projects	to ensure	that	continued	capitalization	is	appropriate.	At	December	31,	2004,	total	costs	capitalized	attributable	to	suspended	exploratory	well	costs	were	$339	million.	Of the	$339	million,	$309	million	relates	to	wells	in	areas	where	additional	exploratory	wells	are	underway	or	firmly	planned.	$23	million	relates	to	wells	in	areas	where additional	wells	are	not	firmly	planned;	however,	less	than	a	year	has	elapsed	since	the	rig	release	for	these	wells.	The	remaining	$7	million	relates	to	single	well projects	that	were	drilling	over	year	end	and	completion	costs.

								Exploration	expense	was	$202	million,	$180	million	and	$192	million	in	2004,	2003	and	2002.	Costs	incurred	for	exploration	as	reported	on	page	F-42	was $291	million,	$231	million	and	$258	million	for	2004,	2003	and	2002.	Exploration	expense	differs	from	exploration	costs	incurred	due	to	timing	differences	between when	costs	are	incurred	and	when	those	costs	are	ultimately	recognized	as	expense.	For	example,	costs	may	be	incurred	and	suspended	as	exploratory	well	costs	in	one year	and	recorded	in	exploration	expense	in	a	subsequent	year	if	it	is	ultimately	determined	that	proved	reserves	cannot	be	recognized.	Additionally,	exploration	costs incurred	for	wells	that	find	proved	reserves	are	transferred	to	proved	property	and	remain	capitalized,	and	therefore	will	not	be	recorded	as	exploration	expense.	Instead these	costs	will	be	expensed	in	depreciation,	depletion	and	amortization	on	a	units-of-production	basis	once	production	begins.	Exploration	expense	also	includes	non- cash	charges	for	unproved	property	impairments.	For	2004,	2003	and	2002	exploration	expense	included	$52	million,	$31	million	and	$25	million

of	unproved	property	impairment	charges.	Dry	well	expense	included	in	exploration	expense	for	2004,	2003	and	2002	totaled	$54	million,	$55	million	and	$91	million. The	remaining	costs	included	in	exploration	expense	of	$96	million,	$94	million	and	$76	million	for	2004,	2003	and	2002	represent	geological	and	geophysical	costs, administrative	expenses	and	other	expenses.

								In	February	2005,	the	Financial	Accounting	Standards	Board	("FASB")	proposed	FASB	Staff	Position	FAS	19-a,	"Accounting	for	Suspended	Well	Costs"	("FSP FAS	19-a"),	which	would	amend	the	guidance	for	suspended	well	costs	in	Statement	of	Financial	Accounting	Standard	No.	19,	"Financial	Accounting	and	Reporting	by Oil	and	Gas	Producing	Companies"	("SFAS	No.	19").	SFAS	No.	19	requires	costs	of	drilling	exploratory	wells	to	be	capitalized	pending	determination	of	whether	the well	has	found	proved	reserves.	If	classification	of	proved	reserves	cannot	be	made	at	the	completion	of	the	drilling	in	an	area	requiring	a	major	capital	expenditure, paragraph	31(a)	of	SFAS	No.	19	provides	that	the	cost	should	continue	to	be	carried	as	an	asset	provided	that	(1)	there	have	been	sufficient	reserves	found	to	justify completion	as	a	producing	well	if	the	required	capital	expenditure	is	made	and	(2)	drilling	of	the	additional	exploratory	well	is	underway	or	firmly	planned	for	the	near future.	If	either	of	those	two	criteria	is	not	met,	SFAS	No.	19	indicates	the	entity	should	expense	the	exploratory	well	costs.	For	all	other	exploratory	wells	not	addressed in	paragraph	31(a),	paragraph	31(b)	provides	that	the	capitalized	costs	should	be	charged	to	expense	if	the	reserves	cannot	be	classified	as	proved	after	a	year	following the	completion	of	exploratory	drilling.	Questions	have	arisen	in	practice	about	the	application	of	this	guidance	due	to	changes	in	oil	and	gas	exploration	processes	and lifecycles.	The	issue	is	whether	there	are	circumstances	that	would	permit	the	continued	capitalization	of	exploratory	well	costs	beyond	one	year	other	than	when additional	exploration	wells	are	necessary	to	justify	major	capital	expenditures	and	those	wells	are	underway	or	firmly	planned	for	the	near	future.	The	proposed	FSP FAS	19-a	would	allow	exploratory	well	costs	to	continue	to	be	capitalized	when	(a)	the	well	has	found	a	sufficient	quantity	of	reserves	to	justify	completion	as	a producing	well	and	(b)	the	enterprise	is	making	sufficient	progress	assessing	the	reserves	and	the	economic	and	operating	viability	of	the	project.	Our	current	policy	as described	above	is	in	accordance	with	the	proposed	FSP	FAS	19-a.

# Depreciation,	Depletion	and	Amortization	of	Property,	Plant	and	Equipment

								Depreciation	and	depletion	of	producing	oil	and	gas	properties	is	determined	by	the	units-of-production	method	and	could	change	with	revisions	to	estimated proved	developed	recoverable	reserves.	The	change	in	the	depreciation	and	depletion	rate	over	the	past	three	years	due	to	revisions	of	previous	reserve	estimates	has been	immaterial.	A	five	percent	increase	in	the	amount	of	oil	and	gas	reserves	would	change	the	depreciation	and	depletion	rate	from	$5.55	per	barrel	to	$5.29	per barrel,	which	would	increase	pre-tax	income	by	$32	million	annually.	A	five	percent	decrease	in	the	amount	of	oil	and	gas	reserves	would	change	the	depreciation	and depletion	rate	from	$5.55	per	barrel	to	$5.84	per	barrel	and	would	result	in	a	decrease	in	pre-tax	income	of	$35	million	annually.

								Property,	plant	and	equipment	in	our	RM&T	segment	are	depreciated	using	the	straight-line	method	over	their	estimated	useful	lives,	which	range	from	3	to 42	years.	Useful	lives	are	based	on	historical	experience	and	the	assumption	that	we	will	provide	an	appropriate	level	of	annual	expenditures	to	maintain	the	assets	in good	operating	condition.	Factors	which	could	affect	the	estimated	useful	lives	of	our	RM&T	property,	plant	and	equipment	include	changes	in	planned	use, environmental	regulations,	competition	and	technological	advances.	There	have	been	no	significant	changes	in	the	useful	lives	of	our	RM&T	property,	plant	and equipment	during	the	2002-2004	period.

# 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,	2004,	we	reported	net deferred	tax	assets	of	$1.360	billion,	which	represented	gross	assets	of	$1.853	billion	net	of	valuation	allowances	of	$493	million.

								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	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	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	if	the	forecasted conditions	actually	occurred.	The	principal	tax	planning	strategy	available	to	us	relates	to	the	permanent	reinvestment	of	the	earnings	of	foreign	subsidiaries. Assumptions	related	to	the	permanent	reinvestment	of	the	earnings	of	foreign	subsidiaries	are	reconsidered	quarterly	to	give	effect	to	changes	in	our	portfolio	of producing	properties	and	in	our	tax	profile.

# Net	Realizable	Value	of	Receivables	from	United	States	Steel

								As	described	further	in	"Management's	Discussion	and	Analysis	of	Financial	Condition,	Cash	Flows	and	Liquidity	–	Obligations	Associated	with	the	Separation	of United	States	Steel"	on	page	42,	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.	As	of	December	31,	2004,	we	have	reported	receivables	from	United	States	Steel	of $602	million,	representing	the	amount	of	principal	and	accrued	interest	on	Marathon	debt	for	which	United	States	Steel	has	assumed	responsibility	for	repayment.	We must	assess	the	realizability	of	these	receivables,	based	on	our	expectations	of	United	States	Steel's	ability	to	satisfy	its	obligations.	To	make	this	assessment,	we	must rely	on	public	information	about	United	States	Steel.	As	of	December	31,	2004,	we	have	judged	the	entire	receivable	to	be	realizable.

								We	may	continue	to	be	exposed	to	the	risk	of	nonpayment	by	United	States	Steel	on	a	significant	portion	of	this	receivable	until	December	31,	2011.	Of	the $602	million,	$472	million,	or	78	percent,	relates	to	industrial	revenue	bonds	that	are	due	in	2011	or	later.	The	Financial	Matters	Agreement	between	Marathon	and United	States	Steel	provides	that,	on	or	before	the	tenth	anniversary	of	the	Separation,	which	is	December	31,	2011,	United	States	Steel	will	provide	for	our	discharge from	any	remaining	liability	under	any	of	the	assumed	industrial	revenue	bonds.

								As	of	December	31,	2004,	our	cash-adjusted	debt-to-capital	ratio	(which	includes	debt	for	which	United	States	Steel	has	assumed	responsibility	for	repayment	and suspended	cash	distributions	to	Ashland)	was	8	percent.	The	assessment	of	our	liquidity	and	capital	resources	may	be	impacted	by	expectations	concerning	United	States Steel's	ability	to	satisfy	its	obligations.

								If	the	debt	for	which	United	States	Steel	has	assumed	responsibility	for	repayment	were	excluded	from	the	computation,	our	cash-adjusted	debt-to-capital	ratio	as	of December	31,	2004	would	have	been	approximately	1	percent.	On	the	other	hand,	if	the	receivable	from	United	States	Steel	had	been	written	off	as	unrealizable,	the cash-adjusted	debt-to-capital	ratio	as	of	December	31,	2004	would	have	been	approximately	8	percent.	(If	United	States	Steel	were	unable	to	satisfy	its	obligations,	other adjustments	in	addition	to	the	write-off	of	the	receivable	may	be	necessary.)

# Contingent	Liabilities

								We	accrue	contingent	liabilities	for	income	and	other	tax	deficiencies,	environmental	remediation,	product	liability	claims	and	litigation	claims	when	such contingencies	are	probable	and	estimable.	Actual	costs	can	differ	from	estimates	for	multiple	reasons.	For	instance,	the	costs	from	settlement	of	claims	and	litigation	can vary	from	estimates	based	on	differing	interpretations	of	laws,	opinions	on	responsibility	and	assessments	on	the	amount	of	damages.	Similarly,	liabilities	for environmental	remediation	may	change	because	of	changes	in	laws,	regulations	and	their	interpretation;	the	determination	of	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.

								Under	the	accounting	rules,	a	liability	is	recorded	for	these	types	of	contingencies	if	we	determine	the	loss	to	be	both	probable	and	estimable.	We	generally	record these	losses	as	"Costs	of	revenues"	or	"Selling,	general	and	administrative	expenses"	on	the	Consolidated	Statement	of	Income,	except	for	tax	contingencies,	which	are recorded	as	"Other	taxes"	or	"Provision	for	income	taxes."	For	additional	information	on	contingent	liabilities,	see	"Management's	Discussion	and	Analysis	of Environmental	Matters,	Litigation	and	Contingencies"	on	page	44.

								An	estimate	as	to	the	sensitivity	to	earnings	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.

# Pensions	and	Other	Postretirement	Benefit	Obligations

								Accounting	for	pension	and	other	postretirement	benefit	obligations	involves	assumptions	related	to:

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

•expected	long-term	rates	of	return	on	plan	assets

•rate	of	future	increases	in	compensation	levels

•health	care	cost	projections

								We	develop	our	demographics	and	utilize	the	work	of	outside	actuaries	to	assist	in	the	measurement	of	these	obligations.	In	determining	the	discount	rate,	we review	market	yields	on	high-quality	corporate	debt	and	perform	an	in-depth	analysis	of	projected	pension	plan	cash	flows	relating	to	the	duration	of	pension	plan liabilities.

								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),	past	performance	and	other	factors.	Certain	components	of	the	asset	mix	are	modeled	with	various	assumptions	regarding	inflation,	debt	returns	and	stock yields.	Peer	data	and	historical	returns	are	reviewed	to	check	for	reasonableness.

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

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

								Note	23	to	the	Consolidated	Financial	Statements,	beginning	on	page	F-30,	includes	detailed	information	for	the	three	years	ended	December	31,	2004,	on	the components	of	pension	and	other	postretirement	expense	and	the	underlying	assumptions	as	well	as	the	funded	status	for	the	company's	pension	plans	for	the	years ended	2004	and	2003.

								Of	the	assumptions	used	to	measure	the	December	31,	2004	obligations	and	estimated	2005	net	periodic	benefit	cost,	the	discount	rate	has	the	most	significant effect	on	the	periodic	benefit	costs	reported	for	the	plans.	A	.25	percent	decrease	in	the	discount	rate	of	5.75	percent	for	domestic	and	5.30	percent	for	international would	increase	pension	and	other	postretirement	plan	expense	by	approximately	$13	million	and	$2	million,	respectively.

# Estimated	Fair	Value	of	Derivative	Contracts

								We	record	all	derivative	instruments	at	fair	value.	Derivative	instruments	are	used	to	manage	risk	throughout	our	different	businesses.	These	risks	relate	to commodities,	interest	rates	and	our	exposure	to	foreign	currency	fluctuations.	We	use	derivative	instruments	that	are	exchange	traded	and	non-exchange	traded.	Non- exchange	traded	instruments	are	referred	to	as	over-the-counter	("OTC")	instruments.

								For	commodities,	the	fair	value	of	exchange	traded	instruments	is	based	on	existing	market	quotes.	Fair	value	for	OTC	instruments	such	as	options	and	swap agreements	is	developed	through	the	use	of	option-pricing	models	or	third	party	market	quotes.	Forward	contracts	are	valued	based	on	quotes	from	the	counterparties	of the	forward	contracts.

								We	also	have	two	long-term	contracts	for	the	sale	of	natural	gas	in	the	United	Kingdom	("U.K.").	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.	Contract	prices	are	linked	to	a	basket	of	energy	and	other indices.	The	contract	price	is	reset	annually	in	October	based	on	the	previous	twelve-month	changes	in	the	basket	of	indices.	Consequently,	the	prices	under	these contracts	do	not	track	forward	gas	prices.

								These	U.K.	gas	contracts	are	accounted	for	as	derivative	instruments.	The	fair	value	of	these	contracts	is	determined	by	applying	the	difference	between	the	contract price	and	the	U.K.	forward	gas	strip	price	to	the	expected	sales	volumes	for	the	next	eighteen	months	under	these	contracts.	Adjustments	to	the	fair	value	of	these contracts	result	in	noncash	charges	or	credits	to	income	from	operations.	The	difference	between	the	contract	price	and	the	U.K.	forward	gas	strip	price	may	fluctuate widely	from	time	to	time	and	may	significantly	affect	income	from	operations.

								The	noncash	change	in	fair	value	recognized	in	earnings	was	a	loss	of	$99	million	in	2004,	a	loss	of	$66	million	in	2003	and	a	gain	of	$18	million	in	2002.	These effects	are	primarily	due	to	the	U.K.	18-month	forward	gas	price	curve	strengthening	36	and	26	percent	during	2004	and	2003	and	weakening	12	percent	during	2002.

								For	additional	information	on	market	risk	sensitivity,	see	"Item	7A.	Quantitative	and	Qualitative	Disclosures	About	Market	Risk"	on	page	50.

# Matching	buy/sell	transactions

								Matching	buy/sell	transactions	are	arrangements	in	which	we	agree	to	buy	a	specific	quantity	and	quality	of	crude	oil	or	refined	petroleum	products	to	be	delivered at	a	specific	location	while	simultaneously	agreeing	to	sell	a	specified	quantity	and	quality	of	crude	oil	or	refined	petroleum	products	at	a	different	location,	usually	with the	same	counterparty.	All	matching	buy/sell	transactions	are	settled	in	cash	and	are	recorded	in	both	revenues	and	costs	of	revenues	as	separate	sales	and	purchase transactions,	or	on	a	"gross"	basis.

								In	a	typical	buy/sell	transaction,	we	enter	into	a	contract	to	sell	a	particular	grade	of	crude	oil	or	refined	product	at	a	specified	location	and	date	to	a	particular counterparty,	and	simultaneously	agree	to	buy	a	particular	grade	of	crude	oil	or	refined	product	at	a	different	location	on	the	same	or	another	specified	date,	typically from	the	same	counterparty.	The	value	of	the	purchased	volumes	rarely	equals	the	sales	value	of	the	sold	volumes.	The	value	difference	between	purchases	and	sales	are primarily	due	to	1)	grade/quality	differentials,	2)	location	differentials	or	3)	timing	differences,	in	those	instances	when	the	purchase	and	sale	do	not	occur	in	the	same month.

								For	the	E&P	segment,	we	enter	into	matching	buy/sell	transactions	to	reposition	crude	oil	from	one	market	center	to	another	in	order	to	maximize	the	value	received for	our	crude	oil	production.	For	the	RM&T	segment,	we	enter	into	crude	oil	matching	buy/sell	transactions	to	secure	the	most	profitable	refinery	supply	and	refined product	matching	buy/sell	transactions	to	meet	projected	customer	demands	and	to	secure	the	required	volumes	in	the	most	cost-effective	manner.

								The	characteristics	of	our	matching	buy/sell	transactions	include	gross	invoicing	between	Marathon	and	its	counterparties	and	cash	settlement	of	the	transactions. Nonperformance	by	one	party	to	deliver	generally	does	not	relieve	the	other	party's	obligation	to	perform.	Both	transactions	require	physical	delivery	of	the	product.	The risks	and	rewards	of	ownership	are	evidenced	by	title	transfer,	assumption	of	environmental	risk,	transportation	scheduling,	credit	risk,	counterparty	nonperformance	risk and	the	fact	that	we	have	the	primary	obligation	to	perform.

								We	believe	matching	buy/sell	transactions	are	monetary	in	nature	and	thus	outside	the	scope	of	APB	Opinion	No.	29,	"Accounting	for	Nonmonetary	Transactions" ("APB	No.	29").	Additionally,	we	have	evaluated	EITF	No.	99-19,	"Reporting	Revenue	Gross	as	a	Principal	versus	Net	as	an	Agent"	("EITF	No.	99-19")	and,	based	on that	evaluation,	management	believes	that	the	recording	these	transactions	on	a	gross	basis	is	appropriate.

								The	Emerging	Issues	Task	Force	("EITF")	is	currently	considering	Issue	No.	04-13,	"Accounting	for	Purchases	and	Sales	of	Inventory	with	the	Same Counterparty,"	("EITF	No.	04-13"),	which	relates	to	transactions	in	which	an	entity	sells	inventory	to	another	entity	in	the	same	line	of	business	from	which	it	also purchases	inventory.	The	following	questions	have	been	raised	regarding	the	accounting	for	these	types	of	transactions	and	are	expected	to	be	addressed	by	the	EITF:

(a) Under	what	circumstances	should	two	or	more	transactions	with	the	same	counterparty	(counterparties)	be	viewed	as	a	single	nonmonetary	transaction within	the	scope	of	APB	No.	29?

(b) If	nonmonetary	transactions	within	the	scope	of	APB	No.	29	involve	inventory,	are	there	any	circumstances	under	which	the	transactions	should	be recognized	at	fair	value?

								The	EITF	has	not	yet	addressed	the	first	question.	The	EITF	discussed	the	second	question	at	its	November	2004	meeting	without	reaching	any	consensus.	If	the EITF	were	to	determine	that	these	transactions	should	be	accounted	for	as	monetary	transactions	on	a	gross	basis,	no	change	in	our	accounting	policy	for	matching buy/sell	transactions	would	be	necessary.	If	the	EITF	were	to	determine	that	these	transactions	should	be	accounted	for	as	nonmonetary	transactions	qualifying	for	fair value	recognition	and	require	a	net	presentation	of	such	transactions,	the	amounts	of	revenues	and	cost	of	revenues	associated	with	matching	buy/sell	transactions	would be	netted	in	our	consolidated	statement	of	income,	but	there	would	be	no	effect	on	income	from	operations,	net	income	or	cash	flows	from	operations.	If	the	EITF	were to	determine	that	these	transactions	should	be	accounted	for	as	nonmonetary	transactions	not	qualifying	for	fair	value	recognition,	these	amounts	of	revenues	and	cost	of revenues	would	be	netted	in	our	consolidated	statement	of	income	and	there	could	be	an	impact	on	income	from	operations	and	net	income	related	to	the	timing	of	the ultimate	sale	of	product	purchased	in	the	"buy"	side	of	the	matching	buy/sell	transaction.	However,	management	does	not	believe	any	impact	would	be	material.	There would	be	no	impact	on	cash	flows	from	operations	as	a	result	of	this	accounting	treatment.

# Management's	Discussion	and	Analysis	of	Income	and	Operations

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| E&P | $4,897 | $4,811 | $4,477 |
| RM&T | 43,630 | 34,514 | 26,399 |
| IG | 1,739 | 2,248 | 1,217 |
| Segment\trevenues | 50,266 | 41,573 | 32,093 |
| Elimination\tof\tintersegment\trevenues | (668) | (610) | (798) |
| Total\trevenues | $49,598 | $40,963 | $31,295 |
| Items\tincluded\tin\tboth\trevenues\tand\tcosts\tand\texpenses: |  |  |  |
| Consumer\texcise\ttaxes\ton\tpetroleum\tproducts\tand\tmerchandise | $4,463 | $4,285 | $4,250 |
| Matching\tcrude\toil\tand\trefined\tproduct\tbuy/sell\ttransactions\tsettled\tin\tcash: |  |  |  |
| E&P | $167 | $222 | $289 |
| RM&T | 8,997 | 6,936 | 4,191 |
| Total\tbuy/sell\ttransactions | $9,164 | $7,158 | $4,480 |

								E&P	segment	revenues	increased	by	$86	million	in	2004	from	2003	and	by	$334	million	in	2003	from	2002.	The	2004	increase	was	primarily	due	to	higher worldwide	liquid	hydrocarbon	and	natural	gas	prices.	This	increase	was	partially	offset	by	lower	liquid	hydrocarbon	and	natural	gas	volumes	and	decreased	crude	oil marketing	activities.	The	2003	increase	was	primarily	due	to	higher	worldwide	natural	gas	and	liquid	hydrocarbon	prices	and	increased	crude	oil	marketing	activities. This	increase	was	partially	offset	by	lower	liquid	hydrocarbon	and	natural	gas	volumes.	Derivative	losses	totaled	$268	million	in	2004,	compared	to	losses	of $176	million	in	2003	and	gains	of	$52	million	in	2002.	These	results	included	losses	of	$99	million	in	2004	compared	to	losses	of	$66	million	in	2003	and	gains	of $18	million	in	2002	related	to	long-term	natural	gas	contracts	in	the	United	Kingdom	that	are	accounted	for	as	derivative	instruments.	See	"Quantitative	and	Qualitative Disclosures	About	Market	Risk"	on	page	50	for	discussion	of	derivative	instruments	and	associated	market	risk.	Matching	buy/sell	transactions	decreased	by	$55	million in	2004	from	2003	and	by	$67	million	in	2003	from	2002.	The	2004	and	2003	decreases	were	primarily	due	to	decreased	crude	oil	buy/sell	transactions,	partially	offset by	higher	domestic	liquid	hydrocarbon	prices.

								RM&T	segment	revenues	increased	by	$9.116	billion	in	2004	from	2003	and	by	$8.115	billion	in	2003	from	2002.	The	increases	primarily	resulted	from	higher refined	product	selling	prices	and	volumes	and	increased	crude	oil	sales	volumes	and	prices.	Matching	buy/sell	transactions	increased	by	$2.061	billion	in	2004	from 2003	and	by	$2.745	billion	in	2003	from	2002.	The	2004	increase	was	primarily	due	to	higher	liquid	hydrocarbon	and	refined	product	prices	and	increased	crude	oil	and refined	products	buy/sell	transaction	volumes.	The	2003	increase	was	primarily	due	to	increased	crude	oil	buy/sell	transactions	and	higher	liquid	hydrocarbon	and refined	product	prices,	partially	offset	by	lower	refined	product	buy/sell	transaction	volumes.

								IG	segment	revenues	decreased	by	$509	million	in	2004	from	2003	and	increased	by	$1.031	billion	in	2003	from	2002.	The	decrease	in	2004	is	due	to	a	decrease	in natural	gas	marketing	activities,	partially	offset	by	higher	natural	gas	prices.	The	increase	in	2003	is	a	result	of	higher	natural	gas	prices	and	increased	natural	gas marketing	activity.	Derivative	gains	totaled	$17	million	in	2004,	compared	to	gains	of	$19	million	in	2003	and	losses	of	$8	million	in	2002.

								For	additional	information	on	segment	results,	see	the	discussion	on	income	from	operations	on	page	35.

								Income	from	equity	method	investments	increased	by	$141	million	in	2004	from	2003	and	decreased	by	$108	million	in	2003	from	2002.	The	increase	in	2004	and decrease	in	2003	is	due	to	a	$124	million	loss	on	the	dissolution	of	MKM	Partners	L.P.	("MKM")	recorded	in	2003.	Results	for	2004	also	include	increased	earnings	of other	equity	method	investments,	primarily	Atlantic	Methanol	Production	Company	("AMPCO").	The	loss	on	the	dissolution	of	MKM	in	2003	was	partially	offset	by increased	earnings	of	other	equity	method	investments	due	to	higher	natural	gas	and	liquid	hydrocarbons	prices.	For	further	discussion	of	the	dissolution	of	MKM,	see Note	13	to	the	Consolidated	Financial	Statements.

								Net	gains	on	disposal	of	assets	decreased	by	$130	million	in	2004	from	2003	and	increased	by	$99	million	in	2003	from	2002.	Results	from	2004	include	the	sale of	various	SSA	stores.	During	2003,	we	sold	our	interest	in	CLAM	Petroleum	B.V.	("CLAM"),	interests	in	several	pipeline	companies,	Yates	field	and	gathering system,	SSA	stores	primarily	in	Florida,	South	Carolina,	North	Carolina	and	Georgia,	and	certain	fields	in	the	Big	Horn	Basin	of	Wyoming.	Results	from	2002	include the	sale	of	various	SSA	stores	and	the	sale	of	San	Juan	Basin	assets.

								Gain	or	loss	on	ownership	change	in	MAP	results	from	contributions	to	MAP	of	certain	environmental	capital	expenditures	and	leased	property	acquisitions	funded by	Marathon	and	Ashland.	In	accordance	with	MAP's	limited	liability	company	agreement,	in	certain	instances,	environmental	capital	expenditures	and	acquisitions	of leased	properties	are	funded	by	the	original	contributor	of	the	assets,	but	no	change	in	ownership	interest	may	result	from	these	contributions.	An	excess	of	Ashland funded	improvements	over	Marathon	funded	improvements	results	in	a	net	gain	and	an	excess	of	Marathon	funded	improvements	over	Ashland	funded	improvements results	in	a	net	loss.

								Cost	of	revenues	increased	by	$5.822	billion	in	2004	from	2003	and	by	$6.040	billion	in	2003	from	2002.	The	increases	are	primarily	in	the	RM&T	segment	and result	from	higher	acquisition	costs	for	crude	oil,	refined	products,	refinery	charge	and	blend	feedstocks	and	increased	manufacturing	expenses.

								Selling,	general	and	administrative	expenses	increased	by	$105	million	in	2004	from	2003	and	by	$97	million	in	2003	from	2002.	The	increase	in	2004	was primarily	due	to	increased	stock-based	compensation	and	higher	costs	associated	with	business	transformation	and	outsourcing.	Our	2004	results	were	also	impacted	by start-up	costs	associated	with	the	LNG	project	in	Equatorial	Guinea	and	the	increased	cost	of	complying	with	governmental	regulations.	The	increase	in	2003	was primarily	due	to	increased	employee	benefit	expenses	(caused	by	increased	pension	expense	resulting	from	changes	in	actuarial	assumptions	and	a	decrease	in	realized returns	on	plan	assets)	and	other	employee	related	costs.	Additionally,	during	2003,	we	recorded	a	charge	of	$24	million	related	to	organizational	and	business	process changes.

								Inventory	market	valuation	reserve	("IMV")	is	established	to	reduce	the	cost	basis	of	inventories	to	current	market	value.	Generally,	we	will	establish	an	IMV reserve	when	crude	oil	prices	fall	below	$22	per	barrel.	The	2002	results	of	operations	include	credits	to	income	from	operations	of	$71	million,	reversing	the	IMV reserve	at	December	31,	2001.

								Net	interest	and	other	financial	costs	decreased	by	$25	million	in	2004	from	2003	and	by	$82	million	in	2003	from	2002.	The	decrease	in	2004	is	primarily	due to	an	increase	in	interest	income.	The	decrease	in	2003	is	primarily	due	to	an	increase	in	capitalized	interest	related	to	increased	long-term	construction	projects,	the favorable	effect	of	interest	rate	swaps,	the	favorable	effect	of	a	reduction	in	interest	on	tax	deficiencies	and	increased	interest	income	on	investments.	Additionally, included	in	net	interest	and	other	financing	costs	are	foreign	currency	gains	of	$9	million,	$13	million	and	$8	million	for	2004,	2003	and	2002.

								Loss	from	early	extinguishment	of	debt	in	2002	was	attributable	to	the	retirement	of	$337	million	aggregate	principal	amount	of	debt,	resulting	in	a	loss	of $53	million.

								Minority	interest	in	loss	of	Equatorial	Guinea	LNG	Holdings	Limited,	which	represents	GEPetrol's	25	percent	ownership	interest,	was	$7	million	in	2004, primarily	resulting	from	GEPetrol's	share	of	start-up	costs	associated	with	the	LNG	project	in	Equatorial	Guinea.

								Provision	for	income	taxes	increased	by	$143	million	in	2004	from	2003	and	by	$215	million	in	2003	from	2002,	primarily	due	to	$388	million	and	$720	million increases	in	income	before	income	taxes.	The	effective	tax	rate	for	2004	was	36.6	percent	compared	to	36.6	percent	and	42.1	percent	for	2003	and	2002.	The	higher	rate in	2002	was	due	to	the	United	Kingdom	enactment	of	a	supplementary	10	percent	tax	on	profits	from	the	North	Sea	oil	and	gas	production,	retroactively	effective	to April	17,	2002.	In	2002,	we	recognized	a	one-time	noncash	deferred	tax	adjustment	of	$61	million	as	a	result	of	the	rate	increase.

								The	following	is	an	analysis	of	the	effective	tax	rate	for	the	periods	presented:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Statutory\ttax\trate | 35.0% | 35.0% | 35.0% |
| (a)\nEffects\tof\tforeign\toperations | 1.3 | (0.4) | 5.6 |
| State\tand\tlocal\tincome\ttaxes\tafter\tfederal\tincome\ttax\teffects | 1.6 | 2.2 | 3.9 |
| Other\tfederal\ttax\teffects | (1.3) | (0.2) | (2.4) |
| Effective\ttax\trate | 36.6% | 36.6% | 42.1% |

(a) The	deferred	tax	effect	related	to	the	enactment	of	a	supplemental	tax	in	the	U.K.	increased	the	effective	tax	rate	7.0	percent	in	2002.

								Discontinued	operations	in	2003	primarily	relates	to	our	E&P	operations	in	western	Canada,	which	were	sold	in	2003	for	a	gain	of	$278	million,	including	a	tax benefit	of	$8	million.	Also,	included	in	2003	results	is	an	$8	million	adjustment	to	a	tax	liability	due	to	United	States	Steel	Corporation.	Results	for	2002	report	the western	Canadian	operations	as	discontinued.

								Cumulative	effect	of	changes	in	accounting	principles	of	$4	million,	net	of	a	tax	provision	of	$4	million,	in	2003	represents	the	adoption	of	Statement	of Financial	Accounting	Standards	No.	143	"Accounting	for	Asset	Retirement	Obligations"	("SFAS	No.	143"),	in	which	we	recognized	in	income	the	cumulative	effect	of recording	the	fair	value	of	asset	retirement	obligations.	The	$13	million	gain,	net	of	a	tax	provision	of	$7	million,	in	2002	represents	the	adoption	of	subsequently	issued interpretations	by	the	Financial	Accounting	Standards	Board	("FASB")	of	Statement	of	Financial	Accounting	Standards	No.	133	"Accounting	for	Derivative	Instruments and	Hedging	Activities"	("SFAS	No.	133")	in	which	we	must	recognize	in	income	the	effect	of	changes	in	the	fair	value	of	two	long-term	natural	gas	sales	contracts	in the	United	Kingdom.

								Income	from	operations	for	each	of	the	last	three	years	is	summarized	in	the	following	table:

| E&P |  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- | :--- |
| Domestic |  | $1,073 | $1,155 | $726 |
| International |  | 623 | 425 | 333 |
| E&P\tsegment\tincome |  | 1,696 | 1,580 | 1,059 |
| RM&T |  | 1,406 | 819 | 372 |
| IG |  | 48 | (3) | 23 |
| Segment\tincome |  | 3,150 | 2,396 | 1,454 |
| Items\tnot\tallocated\tto\tsegments: |  |  |  |  |
| Administrative\texpenses |  | (307) | (227) | (194) |
| Gain\t(loss)\ton\tU.K.\tlong-term\tgas\tcontracts | (a) | (99) | (66) | 18 |
| Impairment\tof\tcertain\toil\tand\tgas\tproperties | (b) | (44) | – | – |
| (c)\nCorporate\tinsurance\tadjustment |  | (32) | – | – |
| (d)\nInventory\tmarket\tvaluation\tadjustments |  | – | – | 71 |
| Gain\t(loss)\ton\townership\tchange\tin\tMAP |  | 2 | (1) | 12 |
| (e)\nGain\ton\tasset\tdispositions |  | – | 106 | 24 |
| Loss\ton\tdissolution\tof\tMKM\tPartners\tL.P. | (f) | – | (124) | – |
| (g)\nContract\tsettlement |  | – | – | (15) |
| Total\tincome\tfrom\toperations |  | $2,670 | $2,084 | $1,370 |

(a) Amounts	relate	to	long-term	gas	contracts	in	the	United	Kingdom	that	are	accounted	for	as	derivative	instruments	and	recorded	at	fair	value.	See	"Estimated	Fair	Value	of	Derivative	Contracts"	on	page	31	for further	discussion.

(b) Amount	includes	$32	million	related	to	unproved	properties	and	$12	million	related	to	producing	properties	primarily	due	to	unsuccessful	developmental	drilling	activity	in	Russia.

(c) Insurance	expense	related	to	estimated	future	obligations	to	make	certain	insurance	premium	payments	related	to	past	loss	experience.

(d) The	IMV	reserve	results	when	the	recorded	LIFO	cost	basis	of	inventories	of	liquid	hydrocarbons	and	refined	petroleum	products	exceeds	net	realizable	value.

(e) The	net	gain	in	2003	represents	a	gain	on	the	disposition	of	interest	in	CLAM	and	certain	fields	in	the	Big	Horn	Basin	of	Wyoming	and	SSA	stores	in	Florida,	North	Carolina,	South	Carolina	and	Georgia.	The 2002	amount	represents	gain	on	exchange	of	certain	oil	and	gas	properties	with	XTO	Energy,	Inc.

(f) See	Note	13	to	the	Consolidated	Financial	Statements	for	a	discussion	of	the	dissolution	of	MKM.

(g) Represents	a	settlement	arising	from	the	cancellation	of	the	Cajun	Express	rig	contract	on	July	5,	2001.

# Average	Volumes	and	Selling	Prices

| Net	Liquid	Hydrocarbon	Production	(mbpd) | (a)(b) |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| United\tStates |  | 81.2 | 106.5 | 116.0 |
| Equity\tInvestee\t(MKM) |  | – | 4.4 | 8.5 |
| Total\tUnited\tStates |  | 81.2 | 110.9 | 124.5 |
| Europe |  | 39.8 | 41.5 | 51.9 |
| Other\tInternational |  | 15.6 | 10.0 | 1.0 |
| West\tAfrica |  | 32.5 | 27.1 | 25.3 |
| Equity\tInvestee\t(Chernogorskoye) |  | 1.0 | 1.2 | – |
| (c) |  |  |  |  |
| Total\tInternational |  | 88.9 | 79.8 | 78.2 |
| Worldwide\tcontinuing\toperations |  | 170.1 | 190.7 | 202.7 |
| Discontinued\toperations |  | – | 3.1 | 4.4 |
| Worldwide |  | 170.1 | 193.8 | 207.1 |
| (b)(d) |  |  |  |  |
| Net\tNatural\tGas\tProduction\t(mmcfd)\nUnited\tStates |  | 631.2 | 731.6 | 744.8 |
| Europe |  | 291.8 | 285.9 | 303.5 |
| West\tAfrica |  | 76.4 | 65.9 | 53.3 |
| Equity\tInvestee\t(CLAM) |  | – | 12.4 | 24.8 |
| Total\tInternational |  | 368.2 | 364.2 | 381.6 |
| Worldwide\tcontinuing\toperations |  | 999.4 | 1,095.8 | 1,126.4 |
| Discontinued\toperations |  | – | 74.1 | 103.9 |
| Worldwide |  | 999.4 | 1,169.9 | 1,230.3 |
| Total\tproduction\t(mboepd) |  | 336.7 | 388.8 | 412.2 |
| Average\tSales\tPrices\t(excluding\tderivative\tgains\tand\tlosses) |  |  |  |  |
| (a) |  |  |  |  |
| Liquid\tHydrocarbons\t($per\tbbl) |  |  |  |  |
| United\tStates |  | $32.76 | $26.92 | $22.18 |
| Equity\tInvestee\t(MKM) |  | – | 29.45 | 24.65 |
| Total\tUnited\tStates |  | 32.76 | 27.02 | 22.35 |
| Europe |  | 37.16 | 28.50 | 24.40 |
| Other\tInternational |  | 22.65 | 18.33 | 26.98 |
| West\tAfrica |  | 35.11 | 26.29 | 22.62 |
| Equity\tInvestee\t(Chernogorskoye) |  | 21.10 | 13.72 | – |
| Total\tInternational |  | 33.68 | 26.24 | 23.85 |
| Worldwide\tcontinuing\toperations |  | 33.24 | 26.70 | 22.93 |
| Discontinued\toperations |  | – | 28.96 | 23.29 |
| Worldwide |  | $33.24 | $26.73 | $22.94 |
| Natural\tGas\t($per\tmcf)\nUnited\tStates |  | $4.89 | $4.53 | $2.87 |
| Europe |  | 4.13 | 3.35 | 2.67 |
| West\tAfrica |  | .25 | .25 | .24 |
| Equity\tInvestee\t(CLAM) |  | – | 3.69 | 3.05 |
| Total\tInternational |  | 3.33 | 2.80 | 2.35 |
| Worldwide\tcontinuing\toperations |  | 4.31 | 3.95 | 2.70 |
| Discontinued\toperations |  | – | 5.43 | 3.30 |
| Worldwide |  | $4.31 | $4.05 | $2.75 |
| MAP: |  |  |  |  |
| (e) |  |  |  |  |
| Refined\tProducts\tSales\tVolumes\t(mbpd) |  | 1,400 | 1,357 | 1,318 |
| Matching\tbuy/sell\tvolumes\tincluded\tin\trefined\tproduct\tsales\tvolumes\t(mbpd) | Matching\tbuy/sell\tvolumes\tincluded\tin\trefined\tproduct\tsales\tvolumes\t(mbpd) | 71 | 64 | 71 |
| Refining\tand\tWholesale\tMarketing\tMargin | (f)(g) | $0.0877 | $0.0603 | $0.0387 |

(b) Amounts	represent	production	after	royalties,	excluding	the	U.K.,	Ireland	and	the	Netherlands	where	amounts	are	before	royalties.

(c) Represents	equity	tanker	liftings	and	direct	deliveries.

(e) Total	average	daily	volumes	of	all	refined	product	sales	to	MAP's	wholesale,	branded	and	retail	(SSA)	customers.

(f) Per	gallon.

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

								Domestic	E&P	income	decreased	by	$82	million	in	2004	from	2003	following	an	increase	of	$429	million	in	2003	from	2002.	The	decrease	in	2004	was	due	to lower	liquid	hydrocarbon	and	natural	gas	volumes	primarily	resulting	from	natural	declines	in	field	production	rates,	weather-related	downtime	in	the	Gulf	of	Mexico and	the	sale	of	the	Yates	field,	partially	offset	by	higher	liquid	hydrocarbon	and	natural	gas	prices.	The	increase	in	2003	was	primarily	due	to	higher	natural	gas	and liquid	hydrocarbon	prices,	lower	dry	well	expense	and	a	$25	million	favorable	contract	settlement,	partially	offset	by	lower	liquid	hydrocarbon	and	natural	gas	volumes and	derivative	losses.	Derivative	losses	totaled	$118	million	in	2004,	compared	to	losses	of	$91	million	in	2003	and	gains	of	$32	million	in	2002.

								In	late	September	2004,	certain	production	platforms	in	the	Gulf	of	Mexico	were	evacuated	due	to	hurricane	activity	resulting	in	shut-in	of	approximately	40 thousand	barrels	per	day	("mbpd")	of	liquid	hydrocarbon	and	95	million	cubic	feet	per	day	("mmcfd")	of	natural	gas	production.	Restoration	of	production	began following	the	hurricanes	and	all	facilities	were	back	on	line	by	October	1,	2004	with	the	exception	of	the	Petronius	platform	which	is	expected	to	be	back	on	line	by	the end	of	the	second	quarter	2005.	At	the	time	of	shut-in,	the	Petronius	field	was	producing	approximately	23.4	thousand	barrels	of	oil	equivalent	per	day	("mboepd")	net	to Marathon.	As	a	result	of	the	damage	to	the	Petronius	platform,	we	recorded	expense	of	$11	million	representing	repair	costs	incurred,	partially	offset	by	the	net	effects of	the	property	damage	insurance	recoveries	and	the	related	retrospective	insurance	premiums.	We	also	recorded	income	of	$34	million	for	business	interruption insurance	recoveries.

								Domestic	net	liquid	hydrocarbons	production	decreased	27	percent	to	81	mbpd	in	2004,	as	a	result	of	natural	declines	mainly	in	the	Gulf	of	Mexico,	hurricane damage	to	the	Petronius	platform	and	the	sale	of	Yates	field	in	November	2003.	Net	natural	gas	production	averaged	631	mmcfd,	down	14	percent	from	2003,	as	a	result of	hurricane	damage	to	the	Petronius	platform	and	natural	declines	in	the	Permian	Basin	and	the	Gulf	of	Mexico.

								Domestic	net	liquid	hydrocarbons	production	decreased	11	percent	to	111	mbpd	in	2003,	as	a	result	of	natural	declines	mainly	in	the	Gulf	of	Mexico	and dispositions.	Net	natural	gas	production	averaged	732	mmcfd,	down	2	percent	from	2002.

								International	E&P	income	increased	by	$198	million	in	2004	from	2003	and	by	$92	million	in	2003	from	2002.	The	increase	in	2004	was	primarily	due	to	higher liquid	hydrocarbon	and	natural	gas	prices	and	volumes	partially	offset	by	higher	derivative	losses.	The	increase	in	2003	was	due	to	higher	natural	gas	and	liquid hydrocarbon	prices	and	higher	liquid	hydrocarbon	volumes	partially	offset	by	lower	natural	gas	volumes	and	derivative	losses.	Derivative	losses	totaled	$51	million	in 2004,	compared	to	losses	of	$19	million	in	2003	and	gains	of	$2	million	in	2002.

								International	net	liquid	hydrocarbons	production	increased	11	percent	to	89	mbpd	in	2004	primarily	due	to	increased	production	in	Equatorial	Guinea	and	a	full year	of	production	from	Khanty	Mansiysk	Oil	Corporation	("KMOC")	which	was	acquired	in	2003.	Net	natural	gas	production	averaged	368	mmcfd,	up	1	percent	from 2003	due	to	increased	production	from	the	condensate	expansion	project	in	Equatorial	Guinea,	offset	by	the	disposition	in	2003	of	our	interest	in	CLAM.

								International	net	liquid	hydrocarbons	production	increased	2	percent	to	80	mbpd	in	2003	primarily	due	to	the	acquisition	of	KMOC,	partially	offset	by	lower production	in	the	U.K.	Net	natural	gas	production	averaged	364	mmcfd,	down	5	percent	from	2002,	primarily	from	lower	production	in	Ireland	and	the	disposition	of our	interest	in	CLAM.	This	decrease	was	partially	offset	by	increased	production	in	Equatorial	Guinea.

								RM&T	segment	income	increased	by	$587	million	in	2004	from	2003	and	by	$447	million	in	2003	from	2002.	The	2004	increase	primarily	results	from	a	higher refining	and	wholesale	marketing	margin,	which	averaged	8.8	cents	per	gallon	versus	6.0	cents	in	2003.	Margins	improved	initially	due	to	the	market's	concerns	about refiners'	ability	to	supply	the	new	Tier	II	low	sulfur	gasolines	which	were	required	effective	January	1,	2004	and,	more	recently,	due	to	concerns	about	the	adequacy	of distillate	supplies	heading	into	winter.	In	addition,	the	widening	of	price	differentials	between	sweet	and	sour	crude	positively	affected	the	2004	results.	For	the	full	year 2004	MAP	averaged	939,000	barrels	of	crude	oil	throughput	per	day	or	99	percent	of	average	system	capacity.	The	2003	increase	was	primarily	due	to	an	improved refining	and	wholesale	marketing	margin,	as	well	as	a	higher	gasoline	and

distillate	retail	gross	margin	partially	offset	by	higher	administrative	expenses.	The	refining	and	wholesale	marketing	margin	in	2003	averaged	6.0	cents	per	gallon, versus	2002	level	of	3.9	cents.	The	gasoline	and	distillate	gross	margin	for	its	retail	business	was	12.3	cents	per	gallon	in	2003,	as	compared	to	10.1	cents	per	gallon	in 2002.	The	higher	administrative	expenses	were	due	primarily	to	higher	employee	related	costs.	Results	for	2003	also	included	$34	million	of	gains	from	the	sale	of certain	interests	in	refined	product	pipelines.

								Derivative	losses,	which	are	included	in	the	refining	and	wholesale	marketing	margin,	were	$272	million	in	2004	compared	to	$158	million	in	2003	and $124	million	in	2002.	These	derivative	losses	were	generally	incurred	to	mitigate	the	price	risk	of	certain	crude	oil	and	other	feedstock	purchases,	to	protect	carrying values	of	excess	inventories	and	to	protect	crack	spread	values.

								IG	segment	income	increased	by	$51	million	in	2004	from	2003,	following	a	decrease	of	$26	million	in	2003	from	2002.	The	increase	in	2004	was	primarily	due to	increased	earnings	from	our	investment	in	AMPCO	and	higher	income	from	LNG	operations,	partially	offset	by	costs	associated	with	ongoing	development	of	certain integrated	gas	projects	and	lower	margins	from	gas	marketing	activities,	including	recognized	changes	in	the	fair	value	of	derivatives	used	to	support	those	activities.	The AMPCO	methanol	plant	in	Equatorial	Guinea	operated	at	a	95	percent	on-stream	factor	in	2004	and	prices	were	strong,	averaging	nearly	$227	per	ton	for	the	year. Additionally,	the	2003	results	included	an	impairment	charge	of	$22	million	on	an	equity	method	investment	and	a	loss	of	$17	million	on	the	termination	of	two	tanker operating	leases.	The	decrease	in	2003	is	due	to	the	impairment	charge	of	$22	million	and	the	loss	of	$17	million	on	leases	as	discussed	above	and	higher	expenses related	to	the	development	of	an	integrated	gas	business,	partially	offset	by	higher	AMPCO	earnings.

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

# Financial	Condition

								Current	assets	increased	$2.823	billion	from	year-end	2003,	primarily	due	to	an	increase	in	cash	and	cash	equivalents	and	receivables.	The	increase	in	cash	and cash	equivalents	was	mainly	due	to	the	issuance	on	March	31,	2004,	of	34,500,000	shares	of	common	stock	resulting	in	net	proceeds	of	$1.004	billion	and	the suspension	of	cash	distributions	to	Ashland.	The	increase	in	receivables	was	mainly	due	to	higher	year-end	commodity	prices.

								Current	liabilities	increased	$1.046	billion	from	year-end	2003,	primarily	due	to	an	increase	in	accounts	payable	as	a	result	of	higher	priced	year-end	crude	oil purchases	at	MAP.

								Investments	and	long-term	receivables	increased	$223	million	from	year-end	2003,	primarily	due	to	contributions	to	an	equity	investee	to	fund	the	LPG expansion	project	in	Equatorial	Guinea	and	restricted	cash	of	$66	million	at	EGHoldings.

								Net	property,	plant	and	equipment	increased	$980	million	from	year-end	2003.	Net	property,	plant	and	equipment	for	each	of	the	last	two	years	is	summarized	in the	following	table:

| (In	millions) | 2004 | 2003 |
| :--- | :--- | :--- |
| E&P |  |  |
| Domestic | $2,644 | $2,636 |
| International | 3,530 | 3,351 |
| Total\tE&P | 6,174 | 5,987 |
| RM&T | 4,842 | 4,492 |
| IG | 621 | 153 |
| Corporate | 173 | 198 |
| Total | $11,810 | $10,830 |

								The	increase	in	international	E&P	is	due	to	the	construction	of	the	Alba	field	condensate	expansion	project	in	Equatorial	Guinea.	The	increase	in	RM&T	is primarily	due	to	refinery	upgrade	projects	to	enable	the	production	of	low	sulfur	gasoline	and	diesel	fuel	and	the	Detroit,	Michigan	refinery	expansion	project,	partially offset	by	sales	of	SSA	stores.	The	increase	in	IG	is	primarily	due	to	costs	associated	with	the	LNG	project	in	Equatorial	Guinea.

								Asset	retirement	obligations	increased	$87	million	from	year-end	2003	primarily	due	to	revisions	of	previous	estimates	caused	by	the	impact	of	a	weakening	U.S. dollar	on	foreign	asset	retirement	obligations,	as	well	as	drilling	activity	during	2004.

# Cash	Flows

								Net	cash	provided	from	operating	activities	(for	continuing	operations)	totaled	$3.730	billion	in	2004,	compared	with	$2.665	billion	in	2003	and	$2.331	billion in	2002.	The	increases	mainly	resulted	from	the	effects	of	higher	worldwide	natural	gas	and	liquid	hydrocarbons	prices	and	a	higher	refining	and	wholesale	marketing margin.

								Net	cash	provided	from	operating	activities	(for	discontinued	operations)	totaled	$83	million	in	2003,	compared	with	$69	million	in	2002	related	to	our	E&P operations	in	western	Canada	sold	in	2003.

								Capital	expenditures	for	each	of	the	last	three	years	are	summarized	in	the	following	table:

# (In	millions)

|  |  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- | :--- |
| E&P | (a) |  |  |  |
| Domestic | Domestic | $402 | $344 | $417 |
| International | International | 542 | 629 | 403 |
|  | Total\tE&P | 944 | 973 | 820 |
| RM&T | RM&T | 784 | 772 | 621 |
| IG | IG | 490 | 131 | 48 |
| Corporate | Corporate | 19 | 16 | 31 |
|  | Total | $2,237 | $1,892 | $1,520 |

(a) Amounts	exclude	the	acquisitions	of	KMOC	in	2003	and	the	Equatorial	Guinea	interests	in	2002.

								Capital	expenditures	in	2004	totaled	$2.237	billion	compared	with	$1.892	billion	and	$1.520	billion	in	2003	and	2002,	excluding	the	acquisitions	of	KMOC	in	2003 and	Equatorial	Guinea	interests	in	2002.	The	$345	million	increase	in	2004	mainly	resulted	from	increased	spending	in	the	IG	segment	associated	with	the	LNG	project in	Equatorial	Guinea.	The	$372	million	increase	in	2003	mainly	resulted	from	increased	spending	in	the	RM&T	segment	at	the	Catlettsburg	refinery	and	on	the	Cardinal Products	Pipeline	and	in	the	E&P	segment	in	West	Africa	and	Norway.	The	increase	in	IG	in	2003	was	due	to	the	purchase	of	a	30	percent	interest	in	two	LNG	tankers which	we	previously	leased	and	project	development	costs	associated	with	the	LNG	project	in	Equatorial	Guinea.	The	decrease	in	corporate	capital	expenditures	in	2003 was	primarily	due	to	the	implementation	of	SAP	financial	and	operations	software	in	prior	years.

								Acquisitions	included	cash	payments	of	$252	million	in	2003	for	the	acquisition	of	KMOC	and	$1.160	billion	in	2002	for	the	acquisition	of	the	interests	in Equatorial	Guinea.	For	further	discussion	of	acquisitions,	see	Note	5	to	the	Consolidated	Financial	Statements.

								Cash	from	disposal	of	assets	was	$76	million	in	2004,	compared	with	$1.256	billion	including	the	disposal	of	discontinued	operations,	in	2003	and	$146	million	in 2002.	In	2004,	proceeds	were	primarily	from	the	sale	of	certain	SSA	stores	and	various	domestic	producing	properties.	In	2003,	proceeds	were	primarily	from	the disposition	of	our	E&P	properties	in	western	Canada,	the	Yates	field	and	gathering	system,	our	interest	in	CLAM,	various	SSA	stores,	our	interest	in	several	pipeline companies	and	certain	fields	in	the	Big	Horn	Basin	of	Wyoming.	In	2002,	proceeds	were	primarily	from	the	disposition	of	various	SSA	stores	and	the	sale	of	our	San Juan	Basin	assets.

								Net	cash	provided	from	financing	activities	totaled	$527	million	in	2004,	compared	with	net	cash	used	of	$888	million	in	2003	and	net	cash	provided	of $88	million	in	2002.	The	increase	in	2004	was	due	to	$1.004	billion	in	net	proceeds	from	the	March	31,	2004,	issuance	of	34,500,000	shares	of	common	stock	as	well	as the	suspension	of	distributions	to	the	minority	shareholder	of	MAP.	This	was	partially	offset	by	an	increase	in	dividends	paid	to	stockholders.	The	decrease	in	2003	was due	to	activity	in	2002	primarily	associated	with	financing	the	acquisitions	of	Equatorial	Guinea	interests	of	$1.160	billion.	This	was	partially	offset	by	the	$295	million repayment	of	preferred	securities	in	2002	that	became	redeemable	or	were	converted	to	a	right	to	receive	cash	upon	the	Separation.	In	early	January	2002,	we	paid $185	million	to	retire	the	6.75%	Convertible	Quarterly	Income	Preferred	Securities	and	$110	million	to	retire	the	6.50%	Cumulative	Convertible	Preferred	Stock.

# Derivative	Instruments

								See	"Quantitative	and	Qualitative	Disclosures	About	Market	Risk"	on	page	50,	for	a	discussion	of	derivative	instruments	and	associated	market	risk.

# Dividends	to	Stockholders

								On	January	23,	2005,	our	Board	of	Directors	declared	a	dividend	of	28	cents	per	share	on	our	common	stock,	payable	March	10,	2005,	to	stockholders	of	record	at the	close	of	business	on	February	16,	2005.

# Liquidity	and	Capital	Resources

								Our	main	sources	of	liquidity	and	capital	resources	are	internally	generated	cash	flow	from	operations,	committed	and	uncommitted	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.	Because	of	the	liquidity	and capital	resource	alternatives	available	to	us,	including	internally	generated	cash	flow,	we	believe	that	our	short-term	and	long-term	liquidity	is	adequate	to	fund operations,	including	our	capital	spending	program,	repayment	of	debt	maturities	for	the	years	2005,	2006	and	2007,	and	any	amounts	that	may	ultimately	be	paid	in connection	with	contingencies.

								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+,	respectively.	Our	investment-grade	credit	ratings	were	affirmed	by	these	agencies	following	the	announcement	of	the	proposed	acquisition	of Ashland's	38	percent	ownership	interest	in	MAP.

								We	have	a	committed	$1.5	billion	five-year	revolving	credit	facility	that	terminates	in	May	2009.	At	December	31,	2004,	there	were	no	borrowings	against	this facility.	At	December	31,	2004,	we	had	no	commercial	paper	outstanding	under	the	U.S.	commercial	paper	program	that	is	backed	by	the	five-year	revolving	credit facility.	Additionally,	we	have	other	uncommitted	short-term	lines	of	credit	totaling	$200	million,	of	which	no	amounts	were	drawn	at	December	31,	2004.

								MAP	has	a	committed	$500	million	five-year	revolving	credit	facility	with	third-party	financial	institutions	that	terminates	in	May	2009.	MAP	also	has	a $190	million	revolving	credit	agreement	with	Ashland	that	expires	in	March	2005.	At	December	31,	2004,	there	were	no	borrowings	against	these	facilities.	Pursuant	to the	terms	of	our	agreement	to	acquire	the	38	percent	ownership	interest	in	MAP	currently	held	by	Ashland	(see	Note	29	to	the	Consolidated	Financial	Statements), MAP's	use	of	its	credit	agreement	with	Ashland	was	restricted	after	September	30,	2004	and	we	anticipate	the	credit	agreement	will	be	terminated	if	the	transaction	is completed.

								The	Marathon	and	MAP	revolving	credit	facilities	each	require	a	representation	at	an	initial	borrowing	that	there	has	been	no	change	in	the	respective	borrower's consolidated	financial	position	or	operations,	considered	as	a	whole,	that	would	materially	and	adversely	affect	such	borrower's	ability	to	perform	its	obligations	under its	revolving	credit	facility.

								On	March	31,	2004,	we	completed	the	sale	of	34,500,000	shares	of	common	stock	at	the	offering	price	of	$30	per	share	from	the	$2.7	billion	universal	shelf registration	statement	filed	with	the	Securities	and	Exchange	Commission	in	2002.	We	recorded	net	proceeds	of	$1.004	billion	related	to	this	issuance.	As	of December	31,	2004	there	was	$1.7	billion	aggregate	amount	of	common	stock,	preferred	stock	and	other	equity	securities,	debt	securities,	trust	preferred	securities and/or	other	securities,	including	securities	convertible	into	or	exchangeable	for	other	equity	or	debt	securities	available	to	be	issued	under	this	shelf	registration statement.

								Cash	and	cash	equivalents	totaled	$3.369	billion	at	December	31,	2004,	as	compared	to	$1.396	billion	at	December	31,	2003.	We	expect	to	utilize	a	substantial portion	of	this	cash	to	repay	debt	assumed	in	connection	with	the	proposed	acquisition	of	Ashland's	interest	in	MAP	and	related	businesses,	to	retire	other	outstanding long-term	debt	or	for	other	general	corporate	purposes.

								Cash	distributions	from	MAP	have	been	suspended	pending	consummation	of	the	agreement	to	acquire	the	38	percent	ownership	interest	in	MAP	currently	held	by Ashland.	If	the	proposed	transaction	closes,	Ashland	would	receive	additional	proceeds	equal	to	38	percent	of	MAP's	distributable	cash	at	the	time	of	closing.	If	the transaction	does	not	close,	Ashland	would	receive	its	share	of	these	funds	as	part	of	MAP's	normal	distributions.	Ashland's	share	on	December	31,	2004	was $574	million.

								Our	cash-adjusted	debt-to-capital	ratio	(total-debt-minus-cash	to	total-debt-plus-equity-minus-cash)	was	8	percent	at	December	31,	2004,	compared	to	33	percent	at year-end	2003	as	shown	below.	This	includes	approximately	$594	million	of	debt	that	is	serviced	by	United	States	Steel	Corporation	("United	States	Steel")	and	the above	suspended	distributions	to	Ashland.	We	continually	monitor	our	spending	levels,	market	conditions	and	related	interest	rates	to	maintain	what	we	perceive	to	be reasonable	debt	levels.

| (Dollars	in	millions) | December	31<br>2004 | December	31<br>2003 |
| :--- | :--- | :--- |
| Long-term\tdebt\tdue\twithin\tone\tyear | $16 | $272 |
| Long-term\tdebt | 4,057 | 4,085 |
| Total\tdebt | $4,073 | $4,357 |
| Cash\t(includes\t$574\tmillion\tin\tsuspended\tdistributions\tto\tAshland\tfor\t2004) | $3,369 | $1,396 |
| Equity | $8,111 | $6,075 |
| Calculation |  |  |
| Total\tdebt | $4,073 | $4,357 |
| Minus\tcash | 3,369 | 1,396 |
| Total\tdebt\tminus\tcash | 704 | 2,961 |
| Total\tdebt | 4,073 | 4,357 |
| Plus\tequity | 8,111 | 6,075 |
| Minus\tcash | 3,369 | 1,396 |
| Total\tdebt\tplus\tequity\tminus\tcash | $8,815 | $9,036 |
| Cash-adjusted\tdebt-to-capital\tratio | 8% | 33% |

								The	table	below	provides	aggregated	information	on	our	obligations	to	make	future	payments	under	existing	contracts	as	of	December	31,	2004:

# Summary	of	Contractual	Cash	Obligations

| (Dollars	in	millions) |  |  |  | Total | 2005 | 2006-<br>2007 | 2008-<br>2009 | Later<br>Years |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Short\tand\tlong-term\tdebt\t(excludes\tinterest) | (a)(b) |  |  | $3,925 | $7 | $752 | $402 | $2,764 |
| Sale-leaseback\tfinancing\t(includes\timputed\tinterest) | Sale-leaseback\tfinancing\t(includes\timputed\tinterest) | (a) |  | 96 | 11 | 30 | 22 | 33 |
| Capital\tlease\tobligations | (a) |  |  | 137 | 9 | 30 | 30 | 68 |
| Operating\tlease\tobligations | (a) |  |  | 363 | 83 | 118 | 58 | 104 |
| Operating\tlease\tobligations\tunder\tsublease\nPurchase\tobligations: | (a) |  |  | 54 | 12 | 15 | 11 | 16 |
| Crude,\trefinery\tfeedstock\tand\trefined\tproducts\tcontracts | Crude,\trefinery\tfeedstock\tand\trefined\tproducts\tcontracts | Crude,\trefinery\tfeedstock\tand\trefined\tproducts\tcontracts | (c) | 11,482 | 10,094 | 1,388 | – | – |
| Transportation\tand\trelated\tcontracts |  |  |  | 852 | 142 | 207 | 106 | 397 |
| Contracts\tto\tacquire\tproperty,\tplant\tand\tequipment | Contracts\tto\tacquire\tproperty,\tplant\tand\tequipment | Contracts\tto\tacquire\tproperty,\tplant\tand\tequipment |  | 1,094 | 906 | 186 | 2 | – |
| LNG\tfacility\toperating\tcosts | (d) |  |  | 217 | 13 | 27 | 27 | 150 |
| Service\tand\tmaterials\tcontracts | (e) |  |  | 156 | 78 | 40 | 20 | 18 |
| Unconditional\tpurchase\tobligations | (f) |  |  | 67 | 5 | 11 | 11 | 40 |
| Commitments\tfor\toil\tand\tgas\texploration\t(non-capital) | Commitments\tfor\toil\tand\tgas\texploration\t(non-capital) | Commitments\tfor\toil\tand\tgas\texploration\t(non-capital) | (g) | 23 | 23 | – | – | – |
| Total\tpurchase\tobligations | Total\tpurchase\tobligations |  |  | 13,891 | 11,261 | 1,859 | 166 | 605 |
| Other\tlong-term\tliabilities\treported\tin\tthe\tConsolidated\tBalance\tSheet: |  |  |  |  |  |  |  |  |
| Accrued\tLNG\tfacility\toperating\tcosts | (d) |  |  | 22 | 3 | 5 | 5 | 9 |
| Employee\tbenefit\tobligations | (h) |  |  | 1,609 | 204 | 195 | 323 | 887 |
| Total\tother\tlong-term\tliabilities | Total\tother\tlong-term\tliabilities |  |  | 1,631 | 207 | 200 | 328 | 896 |
| Total\tcontractual\tcash\tobligations | (i) |  |  | $20,097 | $11,590 | $3,004 | $1,017 | $4,486 |

(a) Upon	the	Separation,	United	States	Steel	assumed	certain	debt	and	lease	obligations.	Such	amounts	have	been	included	in	the	above	table	because	Marathon	remains	primarily	liable.

(c) The	majority	of	2005's	contractual	obligations	to	purchase	crude	oil,	refinery	feedstock	and	refined	products	relate	to	contracts	to	be	satisfied	within	the	first	180	days	of	the	year.

(d) We	have	acquired	the	right	to	deliver	to	the	Elba	Island	LNG	re-gasification	terminal	58	bcf	of	natural	gas	per	year.	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	LNG	re-gasification	terminal.

Services	and	materials	contracts	include	contracts	to	purchase	services	such	as	utilities,	supplies	and	various	other	maintenance	and	operating	services. 42

(e) Services	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.	See	Note	28	to	the	Consolidated	Financial	Statements	for	a	complete	discussion	of	our	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) We	have	employee	benefit	obligations	consisting	of	pensions	and	other	postretirement	benefits	including	medical	and	life	insurance.	We	have	estimated	projected	funding	requirements	through	2014.

(i) Includes	$694	million	of	contractual	cash	obligations	that	have	been	assumed	by	United	States	Steel.	For	additional	information,	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"	on	page	43.

								Contractual	cash	obligations	for	which	the	ultimate	settlement	amounts	are	not	fixed	and	determinable	have	been	excluded	from	the	above	table.	These	include derivative	contracts	that	are	sensitive	to	future	changes	in	commodity	prices	and	other	factors.

								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.

# 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	forms	of	guarantees	to	unconsolidated	affiliates,	United	States	Steel	and	certain	lease	contracts.	These	arrangements	are	described	in Note	28	to	the	Consolidated	Financial	Statements.

								We	are	a	party	to	agreements	that	would	require	us	to	purchase,	under	certain	circumstances,	the	interests	in	MAP	and	in	Pilot	Travel	Centers	LLC	("PTC")	not currently	owned.	These	put/call	agreements	are	described	in	Note	28	to	the	Consolidated	Financial	Statements.

								We	are	party	to	an	agreement	that	would	require	us	to	sell,	under	certain	circumstances,	a	13	percent	interest	in	EGHoldings	to	GEPetrol	at	historical	cost	plus	an additional	specified	rate	of	return	for	a	period	of	one	year	from	the	date	of	project	sanction.	This	agreement	is	described	in	Note	28	to	the	Consolidated	Financial Statements.

# Nonrecourse	Indebtedness	of	Investees

								Certain	of	our	equity	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	approximately	$299	million	as	of	December	31,	2004.	Of	this	amount,	$170	million	relates	to	PTC.	If	any	of	these equity	investees	default,	we	have	no	obligation	to	support	the	debt.	Our	partner	in	PTC	has	guaranteed	$157	million	of	the	total	PTC	debt.

# Obligations	Associated	with	the	Separation	of	United	States	Steel

								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, to	holders	of	its	USX	–	U.	S.	Steel	Group	class	of	common	stock	("Steel	Stock")	in	exchange	for	all	outstanding	shares	of	Steel	Stock	on	a	one-for-one	basis	(the "Separation").

								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	Marathon	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	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	the	assumed	leases.

								As	of	December	31,	2004,	we	have	identified	the	following	obligations	totaling	$671	million	that	have	been	assumed	by	United	States	Steel:

•$472	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	$8	million	at	December	31,	2004.

•$71	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,	2004.

•$51	million	of	obligations	under	a	lease	for	equipment	at	United	States	Steel's	Clairton	cokemaking	facility,	with	a	term	extending	to	2012.	There	was	no accrued	interest	payable	on	this	financing	at	December	31,	2004.

•$55	million	of	operating	lease	obligations,	of	which	$42	million	was	in	turn	assumed	by	purchasers	of	major	equipment	used	in	plants	and	operations divested	by	United	States	Steel.

•A	guarantee	of	United	States	Steel's	$14	million	contingent	obligation	to	repay	certain	distributions	from	its	50	percent	owned	joint	venture	PRO-TEC Coating	Company.

•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.	For	further	discussion	of	the	Clairton	1314B	guarantee,	see	Note	3 to	the	Consolidated	Financial	Statements.

								Of	the	total	$671	million,	obligations	of	$602	million	and	corresponding	receivables	from	United	States	Steel	were	recorded	on	our	consolidated	balance	sheet (current	portion	–	$15	million;	long-term	portion	–	$587	million).	The	remaining	$69	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	obligations	to	make	future	payments	under	existing	contracts	that	have	been	assumed	by United	States	Steel	as	of	December	31,	2004:

# Summary	of	Contractual	Cash	Obligations	Assumed	by	United	States	Steel

| (Dollars	in	millions) |  | Total | 2005 | 2006-<br>2007 | 2008-<br>2009 | Later<br>Years |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Contractual\tobligations\tassumed\tby\tUnited\tStates\tSteel |  |  |  |  |  |  |
| Long-term\tdebt | (a) | $472 | $– | $– | $– | $472 |
| Sale-leaseback\tfinancing\t(includes\timputed\tinterest) | Sale-leaseback\tfinancing\t(includes\timputed\tinterest) | 96 | 11 | 30 | 22 | 33 |
| Capital\tlease\tobligations | Capital\tlease\tobligations | 71 | 4 | 19 | 19 | 29 |
| Operating\tlease\tobligations | Operating\tlease\tobligations | 13 | 5 | 8 | – | – |
| Operating\tlease\tobligations\tunder\tsublease | Operating\tlease\tobligations\tunder\tsublease | 42 | 5 | 10 | 11 | 16 |
| Total\tcontractual\tobligations\tassumed\tby\tUnited\tStates\tSteel | Total\tcontractual\tobligations\tassumed\tby\tUnited\tStates\tSteel | $694 | $25 | $67 | $52 | $550 |

								Each	of	Marathon	and	United	States	Steel,	as	members	of	the	same	consolidated	tax	reporting	group	during	taxable	periods	ended	on	or	before	December	31,	2001, is	jointly	and	severally	liable	for	the	federal	income	tax	liability	of	the	entire	consolidated	tax	reporting	group	for	those	periods.	Marathon	and	United	States	Steel	have entered	into	a	tax	sharing	agreement	that	allocates	tax	liabilities	relating	to	taxable	periods	ended	on	or	before	December	31,	2001.

The	agreement	includes	indemnification	provisions	to	address	the	possibility	that	the	taxing	authorities	may	seek	to	collect	a	tax	liability	from	one	party	where	the	tax sharing	agreement	allocates	that	liability	to	the	other	party.	In	2003,	in	accordance	with	the	terms	of	the	tax	sharing	agreement,	we	paid	$16	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	1992	through 1994.

								United	States	Steel	reported	in	its	Form	10-K	for	the	year	ended	December	31,	2004,	that	it	has	significant	restrictive	covenants	related	to	its	indebtedness	including cross-default	and	cross-acceleration	clauses	on	selected	debt	that	could	have	an	adverse	effect	on	its	financial	position	and	liquidity.	However,	United	States	Steel management	believes	that	its	liquidity	will	be	adequate	to	satisfy	its	obligations	for	the	foreseeable	future.	During	periods	of	weakness	in	the	manufacturing	sector	of	the U.S.	economy,	United	States	Steel	believes	that	it	can	maintain	adequate	liquidity	through	a	combination	of	deferral	of	nonessential	capital	spending,	sale	of	non- strategic	assets	and	other	cash	conservation	measures.

# Transactions	with	Related	Parties

								We	own	a	combined	63	percent	working	interest	in	the	Alba	field.	We	own	a	net	52	percent	interest	in	an	onshore	LPG	processing	plant	through	an	equity	method investee,	Alba	Plant	LLC.	Additionally,	we	own	a	45	percent	interest	in	an	onshore	methanol	production	plant	through	AMPCO,	an	equity	method	investee.	We	sell	our marketed	natural	gas	from	the	Alba	field	to	Alba	Plant	LLC	and	AMPCO.	AMPCO	uses	the	natural	gas	to	manufacture	methanol	and	sells	the	methanol	through	another equity	method	investee,	AMPCO	Marketing	LLC.

								MAP's	related	party	sales	to	its	50	percent	equity	method	investee,	PTC,	consists	primarily	of	refined	petroleum	products	which	accounted	for	approximately 2	percent	of	its	total	sales	revenue	for	2004	and	2003.	PTC	is	the	largest	travel	center	network	in	the	United	States	and	operates	approximately	250	travel	centers nationwide.	MAP	also	sells	refined	petroleum	products	consisting	mainly	of	petrochemicals,	base	lube	oils,	and	asphalt	to	Ashland	which	owns	a	38	percent	interest	in MAP.	MAP's	sales	to	Ashland	accounted	for	approximately	1	percent	of	its	total	sales	revenue	for	2004	and	2003.	We	believe	that	these	transactions	were	conducted under	terms	comparable	to	those	with	unrelated	parties.

								In	2004,	Marathon	and	GEPetrol	announced	that	all	of	the	necessary	agreements	had	been	finalized	for	a	LNG	plant,	including	the	formation	of	the	jointly-owned holding	company	EGHoldings.	Marathon	holds	a	75	percent	economic	interest	and	GEPetrol	holds	a	25	percent	economic	interest	in	EGHoldings.	As	of	December	31, 2004,	total	expenditures	of	$551	million,	including	$524	million	of	capital	expenditures,	related	to	the	LNG	project	have	been	incurred.	Cash	held	in	escrow	of $66	million	to	fund	future	contributions	from	GEPetrol	is	classified	as	restricted	cash	and	is	included	in	investments	and	long-term	receivables.	Payables	to	related parties	include	$23	million	payable	to	GEPetrol.

# 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	recovered	in	the	prices	of	our	products	and	services,	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)

|  |  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- | :--- |
| Capital |  | $433 | $331 | $128 |
| Compliance |  |  |  |  |
| Operating\t&amp;\tmaintenance | Operating\t&amp;\tmaintenance | 215 | 243 | 205 |
| Remediation | (b) | 32 | 44 | 45 |
| Total |  | $680 | $618 | $378 |

(a) Amounts	are	determined	based	on	American	Petroleum	Institute	survey	guidelines	and	include	100	percent	of	MAP.

(b) These	amounts	include	spending	charged	against	remediation	reserves,	where	permissible,	but	exclude	noncash	provisions	recorded	for	environmental	remediation.

								Our	environmental	capital	expenditures	accounted	for	19	percent	of	total	capital	expenditures	in	2004,	17	percent	in	2003,	and	eight	percent	in	2002.

								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.

								We	have	been	notified	that	we	are	a	potentially	responsible	party	("PRP")	at	six	waste	sites	under	the	Comprehensive	Environmental	Response,	Compensation	and Liability	Act	("CERCLA")	as	of	December	31,	2004.	In	addition,	there	is	one	site	where	we	have	received	information	requests	or	other	indications	that	we	may	be	a PRP	under	CERCLA	but	where	sufficient	information	is	presently	unavailable	to	confirm	the	existence	of	liability.	At	many	of	these	sites,	we	are	one	of	a	number	of parties	involved	and	the	total	cost	of	remediation,	as	well	as	our	share	thereof,	is	frequently	dependent	on	the	outcome	of	investigations	and	remedial	studies.

								There	are	also	131	additional	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.	Of	these	sites,	14	were	associated	with	properties	conveyed	to MAP	by	Ashland	for	which	Ashland	has	retained	liability	for	all	costs	associated	with	remediation.

								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	$438	million	or	15	percent	of	capital	expenditures	in	2005.	Predictions	beyond	2005	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	$200	million	in	2006;	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.

								New	Tier	II	gasoline	and	on-road	diesel	fuel	rules	require	substantially	reduced	sulfur	levels	for	gasoline	and	diesel	starting	in	2004	and	2006,	respectively.	The combined	capital	costs	to	achieve	compliance	with	the	gasoline	and	diesel	regulations	could	amount	to	approximately	$900	million	over	the	period	between	2002	and 2006	and	includes	costs	that	could	be	incurred	as	part	of	other	refinery	upgrade	projects.	This	is	a	forward-looking	statement.	Costs	incurred	through	December	31, 2004,	were	approximately	$520	million.	Some	factors	(among	others)	that	could	potentially	affect	gasoline	and	diesel	fuel	compliance	costs	include	completion	of project	detailed	engineering,	construction	and	start-up	activities.

								During	2001,	MAP	entered	into	a	New	Source	Review	consent	decree	and	settlement	of	alleged	Clean	Air	Act	("CAA")	and	other	violations	with	the	U.	S. Environmental	Protection	Agency	covering	all	of	MAP's	refineries.	The	settlement	committed	MAP	to	specific	control	technologies	and	implementation	schedules	for environmental	expenditures	and	improvements	to	MAP's	refineries	over	approximately	an	eight-year	period.	The	total	one-time	expenditures	for	these	environmental projects	is	approximately	$370	million	over	the	eight-year	period,	with	about	$240	million	incurred	through	December	31,	2004.	The	impact	of	the	settlement	on ongoing	operating	expenses	is	expected	to	be	immaterial.	In	addition,	MAP	has	nearly	completed	certain	agreed	upon	supplemental	environmental	projects	as	part	of	this settlement	of	an	enforcement	action	for	alleged	CAA	violations,	at	a	cost	of	$9	million.	We	believe	this	settlement	will	provide	MAP	with	increased	permitting	and operating	flexibility	while	achieving	significant	emission	reductions.

# Other	Contingencies

								We	are	a	defendant	along	with	many	other	refining	companies	in	over	forty	cases	in	eleven	states	alleging	methyl	tertiary-butyl	ether	("MTBE")	contamination	in groundwater.	The	plaintiffs	generally	are	water	providers	or	governmental	authorities	and	they	allege	that	refiners,	manufacturers	and	sellers	of	gasoline	containing MTBE	are	liable	for	manufacturing	a	defective	product	and	that	owners	and	operators	of	retail	gasoline	sites	have	allowed	MTBE	to	be	discharged	into	the	groundwater. Several	of	these	lawsuits	allege	contamination	that	is	outside	of	our	marketing	area.	A	few	of	the	cases	seek	approval	as	class	actions.	Many	of	the	cases	seek	punitive damages	or	treble	damages	under	a	variety	of	statutes	and	theories.	We	stopped	producing	MTBE	at	our	refineries	in	October	2002.	The	potential	impact	of	these	recent cases	and	future	potential	similar	cases	is	uncertain.	We	will	defend	these	cases	vigorously.

								We	are	the	subject	of,	or	a	party	to,	a	number	of	pending	or	threatened	legal	actions,	contingencies	and	commitments	involving	a	variety	of	matters,	including	laws and	regulations	relating	to	the	environment.	The	ultimate	resolution	of	these	contingencies	could,	individually	or	in	the	aggregate,	be	material	to	us.	However,	we	believe that	we	will	remain	a	viable	and	competitive	enterprise	even	though	it	is	possible	that	these	contingencies	could	be	resolved	unfavorably	to	us.	See	"Management's Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	–	Liquidity	and	Capital	Resources."

# SEC	Inquiry	Relating	to	Equatorial	Guinea

								By	letter	dated	July	15,	2004,	the	United	States	Securities	and	Exchange	Commission	("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	follows	an investigation	and	public	hearing	conducted	by	the	United	States	Senate	Permanent	Subcommittee	on	Investigations,	which	reviewed	the	transactions	of	various	foreign governments,	including	that	of	Equatorial	Guinea,	with	Riggs	Bank.	The	investigation	and	hearing	also	reviewed	the	operations	of	U.S.	oil	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.	The	investigation	is	ongoing	and	Marathon	is	cooperating	fully	with	the	SEC	inquiry.

# Outlook

# Capital,	Investment	and	Exploration	Budget

								We	approved	a	capital,	investment	and	exploration	budget	of	$2.98	billion	for	2005.	The	primary	focus	of	the	2005	budget	is	to	find	additional	oil	and	gas	reserves, develop	existing	fields,	strengthen	RM&T	assets	and	continue	implementation	of	the	integrated	gas	strategy.	The	budget	includes	worldwide	production	capital spending	of	$1.219	billion	primarily	in	U.S,	Norway,	Russia,	Equatorial	Guinea,	Ireland,	and	the	U.K.	The	worldwide	exploration	budget	of	$364	million	includes	plans to	drill	15	significant	exploration	wells	in	the	Gulf	of	Mexico,	Angola,	Norway	and	other	areas.	Other	activities	will	focus	on	projects	primarily	in	the	United	States.	The budget	includes	$804	million	for	RM&T	projects,	primarily	for	refinery	expansion	and	upgrading	projects,	as	well	as	investments	necessary	to	meet	required	low	sulfur (Tier	II)	gasoline	and	ultra-low	sulfur	diesel	fuel	specifications.	The	integrated	gas	budget	of	$481	million	is	primarily	for	the	ongoing	construction	of	the	LNG	plant	in Equatorial	Guinea.	The	remaining	$111	million	balance	is	designated	for	corporate	activities	and	capitalized	interest.

								Our	six	discoveries	in	2004	result	from	our	balanced	exploration	strategy	which	places	greater	emphasis	on	near-term	production	and	lower	risk	opportunities, while	retaining	an	appropriate	exposure	to	longer-term	options.	Major	exploration	activities,	which	are	currently	underway	or	under	evaluation,	include	those	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	and	the	future	LNG	facility	under	construction	on	Bioko	Island.	We	own	a	63	percent	interest	in the	Alba	Block	and	serve	as	operator.	We	plan	to	drill	one	additional	exploration	well	in	2005	in	Equatorial	Guinea.

•Norway,	where	Hamsun	well	results	are	being	analyzed	and	development	scenarios	are	being	examined	including	a	possible	tie-back	to	the	Alvheim development.	We	own	a	65	percent	interest	in	Hamsun	and	serve	as	operator.	In	addition,	we	acquired	four	new	Norwegian	exploration	licenses	(three operated)	in	the	December	2004	APA	License	Round.	We	now	own	interests	in	sixteen	licenses	in	the	Norwegian	sector	of	the	North	Sea	and	plan	to	drill two	to	three	exploration	wells	during	2005.

•Offshore	Angola,	where	development	options	for	the	northeast	development	area	of	Block	31,	which	includes	the	Plutao,	Saturno,	Marte	and	Venus discoveries,	are	currently	being	evaluated.	Also	on	Block	31,	the	Palas	well	in	the	southern	portion	was	recently	announced	as	a	discovery	and	the	Ceres well	in	the	central	portion	has	reached	total	depth	and	results	will	be	announced	when	government	approval	is	received.	We	own	a	10	percent	interest	in Block	31.	On	Angola	Block	32,	in	which	we	own	a	30	percent	interest,	additional	drilling	will	be	required	to	determine	commerciality	of	the	Cola prospect	and	the	results	of	the	Gengibre	well	will	be	announced	following	government	approval.	We	plan	to	participate	in	six	exploration	wells	offshore Angola	during	2005.

•Gulf	of	Mexico,	where	development	options	for	the	Neptune	unit	are	being	assessed	and	front	end	engineering	and	design	is	anticipated	to	result	in project	sanction	in	2005.	We	own	a	30	percent	interest	in	the	Neptune	unit.	We	plan	to	participate	in	three	to	four	wells	in	the	Gulf	of	Mexico	during 2005.

								During	2004,	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:

•Norway,	where	our	approved	Alvheim	PDO	will	consist	of	a	floating	production,	storage	and	offloading	("FPSO")	vessel	with	subsea	infrastructure	for five	drill	centers	and	associated	flow	lines.	Tendering	for	all	major	construction	contracts	was	completed	in	early	2005,	including	contracts	for	FPSO topsides	construction	and	hull	modifications.	The	approved	Alvheim	PDO	includes	the	Kneler,	Boa	and	Kameleon	fields	in	which	we	own	a	65	percent interest	and	serve	as	operator.	A	PDO	for	the	nearby	Vilje	discovery,	in	which	we	own	a	47	percent	interest,	was	submitted	by	the	operator,	to	the Norwegian	Government	in	December	2004	and	approval	is	expected	in	2005.	The	combined	Alvheim/Vilje	developments	are	expected	to	ramp	up production	to	more	than	50,000	boepd	during	2007.

•Equatorial	Guinea,	where	we	continued	our	expansion	programs	with	the	completion	and	continued	ramp-up	of	production	from	the	condensate expansion	project.	As	of	year-end	2004,	gross	condensate	production	averaged	approximately	45,800	bpd.	At	full	capacity,	the	condensate	expansion will	increase	total	liquids	production	to	approximately	57,000	gross	bpd	(32,000	bpd	net	to	Marathon).	Our	LPG	expansion	project	is	on	schedule	for start-up	during	the	second	quarter	of	2005.	The	project	is	mechanically	complete	and	commissioning	is	in	progress.	When	the	LPG	expansion	is completed,	gross	liquids	production	will	increase	to	approximately	79,000	bpd	(44,500	bpd	net)	during	the	second	half	of	2005.

•Ireland,	where	the	An	Bord	Pleanála	announced	that	it	has	upheld	the	Mayo	County	Council's	decision	to	grant	planning	permission	for	the	proposed natural	gas	terminal	at	Bellanaboy	Bridge,	County	Mayo,	which	is	to	be	built	to	bring	gas	from	the	Corrib	field	ashore.	This	decision	represents	a	major step	forward	for	the	Corrib	gas	project,	in	which	we	own	an	18.5	percent	interest.	Construction	began	in	December	and	first	gas	production	is	targeted	for 2007.

•Russia,	where	we	expect	to	drill	approximately	70	wells	in	2005.

•Wyoming's	Powder	River	Basin,	where	we	plan	to	drill	approximately	500	coal	bed	natural	gas	wells	in	2005.

•Libya,	where	we	continue	to	work	with	our	partners,	including	the	Libyan	Government,	to	finalize	the	terms	of	the	group's	reentry	agreement	following the	lifting	of	U.S.	sanctions	in	early	2004.	The	parties	continue	to	make	progress	toward	a	final	agreement	and	we	are	optimistic	that	it	will	be	finalized	in the	near	future.	We	own	a	16.33	percent	interest	in	the	approximately	13	million	acre	Waha	Concession.

								The	above	discussion	includes	forward-looking	statements	with	respect	to	the	timing	and	levels	of	our	worldwide	liquid	hydrocarbon	and	natural	gas	production, future	exploration	and	drilling	activity,	the	Alvheim/Vilje	developments,	the	LPG	expansion	project	and	the	Corrib	gas	project.	Some	factors	that	could	potentially affect	worldwide	liquid	hydrocarbon	and	natural	gas	and	condensate	production,	the	exploration	and	drilling	activities	and	the	Alvheim	development	include	pricing, supply	and	demand	for	petroleum	products,	amount	of	capital	available	for	exploration	and	development,	occurrence	of	acquisitions/dispositions	of	oil	and	gas properties,	regulatory	constraints,	timing	of	commencing	production	from	new	wells,	drilling	rig	availability,	unforeseen	hazards	such	as	weather	conditions,	acts	of	war or	terrorist	acts	and	the	governmental	or	military	response	thereto,	and	other	geological,	operating	and	economic	considerations.	In	addition	to	the	foregoing	factors,	the plan	for	development	and	operation	of	the	Vilje	Field	may	be	affected	by	delays	in	obtaining	Norwegian	regulatory	approval.	Some	factors	that	could	affect	the	LPG expansion	project	and	the	Corrib	gas	project	include	unforeseen	problems	arising	from	construction	and	unforeseen	hazards	such	as	weather	conditions.	The	forward- looking	information	related	to	production	is	based	on	certain	assumptions,	including,	among	others,	presently	known	physical	data	concerning	size	and	character	of reservoirs,	economic	recoverability,	technology	development,	future	drilling	success,	production	experience,	industry	economic	conditions,	levels	of	cash	flow	from operations	and	operating	conditions.	The	foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking statements.

								Throughout	2004,	MAP	remained	focused	on	its	strategy	of	leveraging	refining	and	marketing	investments	in	core	markets,	as	well	as	expanding	and	enhancing	its asset	base	while	controlling	costs.	The	record	refinery	throughput	performance	was	achieved	even	though	the	company	had	undertaken	a	significant	number	of	planned turnarounds	during	the	first	quarter	of	2004	at	the	Garyville,	Louisiana;	Catlettsburg,	Kentucky;	and	Canton,	Ohio,	refineries.	Assuming	refining	margins	remain	strong in	2005,	we	expect	MAP's	2005	average	crude	oil	throughput	to	exceed	that	achieved	in	2004.

								The	Detroit	refinery	expansion	project	remains	on	schedule	for	completion	in	late	2005.	This	project	will	increase	the	refinery's	crude	processing	capacity	from 74,000	bpd	to	100,000	bpd	as	well	as	enable	the	refinery	to	produce	new	clean	fuels	and	further	control	regulated	air	emissions.	Marathon	is	loaning	MAP	the	funds necessary	for	these	upgrade	and	expansion	projects.

								On	March	18,	2004,	we	entered	into	an	agreement	with	Ashland	Inc.	to	acquire	its	38	percent	interest	in	MAP,	along	with	a	portion	of	its	Valvoline	Instant	Oil Change	business	and	its	maleic	anhydride	business.	The	proposed	transaction	is	subject	to	a	number	of	conditions,	including	favorable	private	letter	rulings	from	the Internal	Revenue	Service	("IRS"),	opinions	of	outside	tax	counsel,	Ashland	shareholder	approval,	Ashland	public	debt	holder	consents,	and	updated	Ashland	solvency opinions.	With	respect	to	the	tax	treatment	of	the	transaction,	Marathon	and	Ashland	are	discussing	with	the	IRS	possible	modifications	of	the	transaction	that	would allow	a	tax	efficient	transfer	of	the	MAP	interest.	Any	such	modifications	would	require	Marathon	and	Ashland	to	amend	the	Master	Agreement	executed	by	the	parties on	March	18,	2004.	However,	there	can	be	no	assurance	that	an	agreement	on	a	modified	transaction	will	be	reached.	If	an	agreement	is	reached	on	a	modified transaction,	it	is	likely	the	transaction	would	close	in	the	second	quarter	of	2005.	For	additional	information,	see	Note	29	to	the	Consolidated	Financial	Statements.

								The	above	discussion	includes	forward-looking	statements	with	respect	to	projections	of	crude	oil	throughput,	the	Detroit	refinery	expansion	project,	the	proposed acquisition	of	Ashland's	38	percent	interest	in	MAP	and	other	related	businesses	and	the	anticipated	effects	of	private	letter	rulings	from	the	IRS	with	respect	to	the	tax treatment	of	the	MAP	transaction.	Some	factors	that	could	affect	crude	oil	throughput	include	planned	and	unplanned	refinery	maintenance	projects,	the	level	of	refining margins,	and	other	operating	considerations.	The	Detroit	refinery	expansion	project	may	be	affected	by	the	availability	of	materials	and	labor,	unforeseen	hazards	such as	weather	conditions,	and	other	risks	customarily	associated	with	construction	projects.	Some	factors	that	could	affect	the	completion	of	the	acquisition	of	Ashland's 38	percent	interest	in	MAP	and	other	related	businesses	include	modifications	to	the	transaction,	an	adverse	ruling	from	the	IRS	regarding	certain	tax	basis	issues, opinions	of	outside	tax	counsel,	Ashland	shareholder	approval,	Ashland	public	debt	holder	consents	and	updated	Ashland	solvency	opinions.	The	foregoing	factors (among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

								We	continued	to	progress	our	integrated	gas	strategy	throughout	the	year.	This	strategy	is	designed	to	complement	our	exploration	and	production	operations focusing	on	accessing	low	cost	stranded	natural	gas	resources	and	adding	value	by	applying	technology	and	commercial	skills	to	connect	those	resources	to	the	major consuming	markets.

								Construction	of	the	Equatorial	Guinea	LNG	project	is	on	schedule	for	shipment	of	first	cargoes	of	LNG	in	late	2007.	This	project	is	expected	to	be	one	of	the	lowest cost	LNG	operations	in	the	Atlantic	basin	with	an	all-in	LNG	operating,	capital	and	feedstock	cost	of	approximately	$1	per	million	British	thermal	units	("mmbtu")	at the	loading	flange	of	the	LNG	plant.	Efforts	are	underway	to	acquire	additional	gas	supply	and	expand	the	utilization	of	this	LNG	facility	above	and	beyond	the	contract to	supply	3.4	million	metric	tons	per	year	to	BG	Gas	Marketing	Ltd.	for	17	years.	We	also	are	seeking	additional	natural	gas	supplies	in	the	area	to	expand	the	capacity and	life	of	this	plant	and	that	could	lead	to	the	development	of	a	second	LNG	train.

								Under	the	five	year	BP	supply	agreement,	we	will	begin	taking	delivery	of	LNG	at	the	Elba	Island,	Georgia,	LNG	regasification	terminal	during	the	second	half	of 2005.	At	the	Elba	Island	terminal,	we	hold	rights	to	deliver	and	sell	up	to	58	bcf	of	natural	gas	per	year	through	2021,	with	an	option	to	extend	for	five	years.	This	supply agreement	with	BP	enables	us	to	fully	utilize	our	capacity	rights	at	Elba	Island	during	the	period	of	this	agreement,	while	affording	us	the	flexibility	to	access	this capacity	to	commercialize	other	stranded	gas	resources	beyond	the	term	of	the	BP	contract.	We	continue	to	actively	seek	LNG	cargoes	before	the	start	of	deliveries	from BP.

								In	2005,	we	plan	to	continue	exploring	and	investing	in	gas	technology	research,	including	GTL	technology,	which	was	successfully	applied	in	the	Catoosa	GTL demonstration	plant	in	2004.	In	addition	to	GTL,	we	are	researching	and	developing	expertise	in	methanol	to	power,	gas	to	gasoline	and	compressed	natural	gas technologies.

								The	above	discussion	contains	forward-looking	statements	with	respect	to	the	estimated	construction	of	a	LNG	project.	Factors	that	could	affect	the	proposed	LNG project	and	related	facilities	include	unforeseen	problems	arising	from	construction,	inability	or	delay	in	obtaining	necessary	government	and	third-party	approvals, unanticipated	changes	in	market	demand	or	supply,	environmental	issues,	availability	or	construction	of	sufficient	LNG	vessels,	and	unforeseen	hazards	such	as	weather conditions.	The	foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Corporate	Matters

								In	2004,	as	part	of	ongoing	business	transformation	programs,	we	implemented	two	outsourcing	agreements	to	achieve	further	business	process	improvements	and cost	reductions.	It	is	anticipated	that	these	programs	will	result	in	total	pretax	charges	of	approximately	$70	million.	Of	these	charges,	$24	million	was	recorded	in	2003 and	$43	million	was	recorded	in	2004,	including	net	settlement	and	curtailment	gains	of	$10	million	in	2003	and	losses	of	$20	million	in	2004,	on	employee	benefit plans.	Projected	savings	from	the	business	transformation	programs	are	expected	to	benefit	all	business	segments.

# Accounting	Standards	Not	Yet	Adopted

								During	December	2004,	the	FASB	issued	Statement	of	Financial	Accounting	Standard	No.	123	(revised	2004)	"Share-Based	Payment"	("SFAS	No.	123R")	as	a revision	of	Statement	of	Financial	Accounting	Standard	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	will	be	recognized	over	the period	during	which	an	employee	is	required	to	provide	service	in	exchange	for	the	award,	usually	the	vesting	period.	In	addition,	liability	awards	will	be	remeasured each	reporting	period.	In	2003,	Marathon	adopted	the	fair	value	method	for	grants	made,	modified	or	settled	on	or	after	January	1,	2003.	Accordingly,	management	does not	expect	the	adoption	of	SFAS	No.	123R	to	have	a	material	affect	on	results	of	operations,	financial	position	or	cash	flows.	This	statement	is	effective	for	Marathon	on July	1,	2005.	Marathon	has	not	yet	determined	whether	to	adopt	this	standard	earlier	than	the	effective	date.

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

# Management	Opinion	Concerning	Derivative	Instruments

								Management	has	authorized	the	use	of	futures,	forwards,	swaps	and	options	to	manage	exposure	to	market	fluctuations	in	commodity	prices,	interest	rates,	and foreign	currency	exchange	rates.

								We	use	commodity-based	derivatives	to	manage	price	risk	related	to	the	purchase,	production	or	sale	of	crude	oil,	natural	gas,	and	refined	products.	To	a	lesser extent,	we	are	exposed	to	the	risk	of	price	fluctuations	on	natural	gas	liquids	and	on	petroleum	feedstocks	used	as	raw	materials.

								Our	strategy	has	generally	been	to	obtain	competitive	prices	for	our	products	and	allow	operating	results	to	reflect	market	price	movements	dictated	by	supply	and demand.	We	will	use	a	variety	of	derivative	instruments,	including	option	combinations,	as	part	of	the	overall	risk	management	program	to	manage	commodity	price	risk in	our	different	businesses.	As	market	conditions	change,	we	evaluate	our	risk	management	program	and	could	enter	into	strategies	that	assume	market	risk	whereby cash	settlement	of	commodity-based	derivatives	will	be	based	on	market	prices.

								Our	E&P	segment	primarily	uses	commodity	derivative	instruments	selectively	to	protect	against	price	decreases	on	portions	of	our	future	production	when	deemed advantageous	to	do	so.	We	also	use	financial	derivative	instruments	to	manage	foreign	currency	exchange	rate	exposure	on	foreign	currency	denominated	capital investment	expenditures,	operating	expenses	and	foreign	tax	payments.

								Our	RM&T	segment	uses	commodity	derivative	instruments:

•to	mitigate	the	price	risk	between	the	time	foreign	and	domestic	crude	oil	and	other	feedstock	purchases	for	refinery	supply	are	priced	and	when	they	are actually	refined	into	salable	petroleum	products,

•to	manage	the	price	risk	associated	with	anticipated	natural	gas	purchases	for	refinery	use,

•to	protect	the	value	of	excess	refined	product,	crude	oil	and	LPG	inventories,

•to	lock	in	margins	associated	with	future	fixed	price	sales	of	refined	products	to	non-retail	customers,

•to	protect	against	decreases	in	future	crack	spreads,

•to	mitigate	price	risk	associated	with	freight	on	crude,	feedstocks,	and	refined	product	deliveries,	and

•to	take	advantage	of	trading	opportunities	identified	in	the	commodity	markets.

								Our	IG	segment	is	exposed	to	market	risk	associated	with	the	purchase	and	subsequent	resale	of	natural	gas.	We	use	commodity	derivative	instruments	to	mitigate the	price	risk	on	purchased	volumes	and	anticipated	sales	volumes.

								We	use	financial	derivative	instruments	to	manage	interest	rate	and	foreign	currency	exchange	rate	exposures.	As	we	enter	into	these	derivatives,	assessments	are made	as	to	the	qualification	of	each	transaction	for	hedge	accounting.

								We	believe	that	use	of	derivative	instruments	along	with	risk	assessment	procedures	and	internal	controls	does	not	expose	us	to	material	risk.	However,	the	use	of derivative	instruments	could	materially	affect	our	results	of	operations	in	particular	quarterly	or	annual	periods.	We	believe	that	use	of	these	instruments	will	not	have	a material	adverse	effect	on	financial	position	or	liquidity.

# Commodity	Price	Risk

								Sensitivity	analyses	of	the	incremental	effects	on	income	from	operations	("IFO")	of	hypothetical	10	percent	and	25	percent	changes	in	commodity	prices	for	open derivative	commodity	instruments	as	of	December	31,	2004	and	December	31,	2003,	are	provided	in	the	following	table: (a)

| Derivative	Commodity	Instruments | (b)(c) | 10% | 25% | 10% | 25% |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (d)\nCrude\toil |  | $1.3(e) | $– | $28.3(e) | $87.9(e) |
| (e)\nNatural\tgas |  | 36.3(e) | 90.7(e) | 29.1(e) | 73.5(e) |
| (e)\nRefined\tproducts |  | 2.6(f) | 7.4(f) | 3.6(e) | 9.1(e) |

(a) We	remain	at	risk	for	future	changes	in	the	market	value	of	derivative	instruments;	however,	such	risk	should	be	mitigated	by	price	changes	in	the	underlying	hedged	item.	Effects	of	these	offsets	are	not reported	in	the	sensitivity	analyses.	Amounts	assume	hypothetical	10	percent	and	25	percent	changes	in	closing	commodity	prices,	excluding	basis	swaps,	for	each	open	contract	position	at	December	31,	2004 and	2003.	We	evaluate	our	portfolio	of	derivative	commodity	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,	2004,	would	cause	future	IFO	effects	to	differ	from	those	presented	in	the	table.

(b) Net	open	contracts	for	the	combined	E&P	and	IG	segments	varied	throughout	2004,	from	a	low	of	1	contract	at	December	15	to	a	high	of	39,683	contracts	at	January	1,	and	averaged	19,344	for	the	year.	The number	of	net	open	contracts	for	the	RM&T	segment	varied	throughout	2004,	from	a	low	of	253	contracts	at	July	7	to	a	high	of	23,138	contracts	at	October	13,	and	averaged	11,437	for	the	year.	The	derivative commodity	instruments	used	and	hedging	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) The	calculation	of	sensitivity	amounts	for	basis	swaps	assumes	that	the	physical	and	paper	indices	are	perfectly	correlated.	Gains	and	losses	on	options	are	based	on	changes	in	intrinsic	value	only.

(d) The	direction	of	the	price	change	used	in	calculating	the	sensitivity	amount	for	each	commodity	is	based	on	the	largest	incremental	decrease	in	IFO	when	applied	to	the	derivative	commodity	instruments	used to	hedge	that	commodity.

(e) Price	increase.

(f) Price	decrease.

# E&P	Segment

								Derivative	losses	included	in	the	E&P	segment	were	$169	million	in	2004	compared	to	losses	of	$110	million	in	2003	and	gains	of	$34	million	in	2002. Additionally,	losses	from	discontinued	cash	flow	hedges	of	$3	million	are	included	in	2004	segment	results,	compared	to	losses	of	$8	million	in	2003	and	gains	of $23	million	in	2002.	The	discontinued	cash	flow	hedge	amounts	were	reclassified	from	accumulated	other	comprehensive	income	(loss)	as	it	was	no	longer	probable	that the	original	forecasted	transactions	would	occur.

								Excluded	from	the	E&P	segment	results	were	losses	of	$99	million	in	2004,	losses	of	$66	million	in	2003	and	gains	of	$18	million	in	2002	on	long-term	gas contracts	in	the	United	Kingdom	that	are	accounted	for	as	derivative	instruments.	For	additional	information	on	U.K.	gas	contracts,	see	"Estimated	Fair	Value	of Derivative	Contracts"	on	page	31.

								At	December	31,	2004,	we	had	no	open	equity	production	derivative	contracts.	We	evaluate	the	commodity	price	risk	of	our	equity	production	on	an	ongoing	basis and	may	enter	into	commodity	derivative	instruments	when	it	is	deemed	advantageous.

# RM&T	Segment

								We	do	not	attempt	to	qualify	commodity	derivative	instruments	used	in	our	RM&T	operations	for	hedge	accounting.	As	a	result,	we	recognize	all	changes	in	the	fair value	of	derivatives	used	in	our	RM&T	operations	in	income,	although	most	of	these	derivatives	have	an	underlying	physical	commodity	transaction.	Generally, derivative	losses	occur	when	market	prices	increase,	which	are	offset	by	gains	on	the	underlying	physical	commodity	transactions.	Conversely,	derivative	gains	occur when	market	prices	decrease,	which	are	offset	by	losses	on	the	underlying	physical	commodity	transactions.	Derivative	gains	or	losses	included	in	RM&T	segment income	for	each	of	the	last	three	years	are	summarized	in	the	following	table:

| Strategy	(In	Millions) | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Mitigate\tprice\trisk | $(106) | $(112) | $(95) |
| Protect\tcarrying\tvalues\tof\texcess\tinventories | (98) | (57) | (41) |
| Protect\tmargin\ton\tfixed\tprice\tsales | 8 | 5 | 11 |
| Protect\tcrack\tspread\tvalues | (76) | 6 | 1 |
| Trading\tactivities | 8 | (4) | – |
| Total\tnet\tderivative\tlosses | $(264) | $(162) | $(124) |

								During	2004,	using	derivative	instruments	MAP	sold	crack	spreads	forward	through	the	fourth	quarter	2005	at	values	higher	than	the	company	thought	sustainable in	the	actual	months	these	contracts	expire.	Included	in	the	$76	million	derivative	loss	for	2004	noted	in	the	above	table	for	the	"Protect	crack	spread	values"	strategy	was approximately	an	$8	million	gain	due	to	changes	in	the	fair	value	of	crack-spread	derivatives	that	will	expire	throughout	2005.

								In	addition,	natural	gas	options	are	in	place	to	manage	the	price	risk	associated	with	approximately	41	percent	of	the	first	quarter	2005	anticipated	natural	gas purchases	for	refinery	use.

# IG	Segment

								We	have	used	derivative	instruments	to	convert	the	fixed	price	of	a	long-term	gas	sales	contract	to	market	prices.	The	underlying	physical	contract	is	for	a	specified annual	quantity	of	gas	and	matures	in	2008.	Similarly,	we	will	use	derivative	instruments	to	convert	shorter	term	(typically	less	than	a	year)	fixed	price	contracts	to market	prices	in	our	ongoing	purchase	for	resale	activity;	and	to	hedge	purchased	gas	injected	into	storage	for	subsequent	resale.	Derivative	gains	included	in	IG segment	income	were	$17	million	in	2004,	compared	to	gains	of	$19	million	in	2003	and	losses	of	$8	million	in	2002.	Trading	activity	in	the	IG	segment	resulted	in losses	of	$2	million	in	2004,	compared	to	losses	of	$7	million	in	2003	and	gains	of	$4	million	in	2002	and	have	been	included	in	the	aforementioned	amounts.

# Other	Commodity	Risk

								We	are	impacted	by	basis	risk,	caused	by	factors	that	affect	the	relationship	between	commodity	futures	prices	reflected	in	derivative	commodity	instruments	and the	cash	market	price	of	the	underlying	commodity.	Natural	gas	transaction	prices	are	frequently	based	on	industry	reference	prices	that	may	vary	from	prices experienced	in	local	markets.	For	example,	New	York	Mercantile	Exchange	("NYMEX")	contracts	for	natural	gas	are	priced	at	Louisiana's	Henry	Hub,	while	the underlying	quantities	of	natural	gas	may	be	produced	and	sold	in	the	western	United	States	at	prices	that	do	not	move	in	strict	correlation	with	NYMEX	prices.	If commodity	price	changes	in	one	region	are	not	reflected	in	other	regions,	derivative	commodity	instruments	may	no	longer	provide	the	expected	hedge,	resulting	in increased	exposure	to	basis	risk.	These	regional	price	differences	could	yield	favorable	or	unfavorable	results.	OTC	transactions	are	being	used	to	manage	exposure	to	a portion	of	basis	risk.

								We	are	impacted	by	liquidity	risk,	caused	by	timing	delays	in	liquidating	contract	positions	due	to	a	potential	inability	to	identify	a	counterparty	willing	to	accept	an offsetting	position.	Due	to	the	large	number	of	active	participants,	liquidity	risk	exposure	is	relatively	low	for	exchange-traded	transactions.

# Interest	Rate	Risk

								We	are	impacted	by	interest	rate	fluctuations	which	affect	the	fair	value	of	certain	financial	instruments.	A	sensitivity	analysis	of	the	projected	incremental	effect	of a	hypothetical	10	percent	decrease	in	interest	rates	is	provided	in	the	following	table:

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

(b) See	Note	17	and	18	to	the	Consolidated	Financial	Statements	for	carrying	value	of	instruments.

(c) For	long-term	debt,	this	assumes	a	10	percent	decrease	in	the	weighted	average	yield	to	maturity	of	our	long-term	debt	at	December	31,	2004	and	2003.	For	interest	rate	swap	agreements,	this	assumes	a 10	percent	decrease	in	the	effective	swap	rate	at	December	31,	2004	and	2003.

(d) Includes	amounts	due	within	one	year.

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

								At	December	31,	2004	and	2003,	our	portfolio	of	long-term	debt	was	substantially	comprised	of	fixed	rate	instruments.	Therefore,	the	fair	value	of	the	portfolio	is relatively	sensitive	to	effects	of	interest	rate	fluctuations.	This	sensitivity	is	illustrated	by	the	$164	million	increase	in	the	fair	value	of	long-term	debt	assuming	a hypothetical	10	percent	decrease	in	interest	rates.	However,	our	sensitivity	to	interest	rate	declines	and	corresponding	increases	in	the	fair	value	of	our	debt	portfolio would	unfavorably	affect	our	results	and	cash	flows	only	if	we	would	elect	to	repurchase	or	otherwise	retire	all	or	a	portion	of	its	fixed-rate	debt	portfolio	at	prices	above carrying	value.

								We	have	initiated	a	program	to	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	fixed	and	floating	interest	rate	mix	of	the	debt	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,	by	individual	debt	instrument,	the	interest	rate	swap	activity	as	of	December	31,	2004:

| Floating	Rate	to	be	Paid | Fixed	Rate<br>to	be<br>Received | Notional<br>Amount | Swap<br>Maturity | Fair	Value |
| :--- | :--- | :--- | :--- | :--- |
| Six\tMonth\tLIBOR\t+4.226% | 6.650% | $300\tmillion | 2006 | $(2)\tmillion |
| Six\tMonth\tLIBOR\t+1.935% | 5.375% | $450\tmillion | 2007 | $(1)\tmillion |
| Six\tMonth\tLIBOR\t+3.285% | 6.850% | $400\tmillion | 2008 | $(2)\tmillion |
| Six\tMonth\tLIBOR\t+2.142% | 6.125% | $200\tmillion | 2012 | $(5)\tmillion |

# Foreign	Currency	Exchange	Rate	Risk

								We	manage	our	exposure	to	foreign	currency	exchange	rates	by	utilizing	forward	contracts,	generally	with	terms	of	365	days	or	less.	The	primary	objective	of	this program	is	to	reduce	our	exposure	to	movements	in	the	foreign	currency	markets	by	locking	in	foreign	currency	rates.	At	December	31,	2004,	the	following	commodity derivatives	were	outstanding.	All	contracts	currently	qualify	for	hedge	accounting	unless	noted.

| Financial	Instruments | Period | Notional	Amount | All-in-Rate^(a) | Fair	Value |
| :--- | :--- | :--- | :--- | :--- |
| Foreign\tCurrency\tRate\tSwaps |  |  |  |  |
| Euro | January\t2005\t–\tJuly\t2005 | $89\tmillion | 1.257(c) | $7\tmillion |
| Norwegian\tkroner | January\t2005\t–\tDecember\t2005 | $49\tmillion(b) | 6.213(d) | $1\tmillion |
| British\tpound\tsterling | January\t2005\t–\tSeptember\t2005 | $6\tmillion | 1.759(c) | $1\tmillion |

(a) The	rate	at	which	the	derivative	instruments	will	be	settled.

(b) On	December	31,	2004,	$18	million	was	discontinued	and	no	longer	qualified	for	hedge	accounting.	On	January	31,	2005,	this	amount	was	re-qualified	for	hedge	accounting.

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

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

								The	aggregate	effect	on	foreign	exchange	contracts	of	a	hypothetical	10	percent	change	to	year-end	exchange	rates	would	be	approximately	$15	million.

# Credit	Risk

								We	are	exposed	to	significant	credit	risk	from	United	States	Steel	arising	from	the	Separation.	That	exposure	is	discussed	in	"Management's	Discussion	and Analysis	of	Financial	Condition	and	Results	of	Operations	–	Obligations	Associated	with	the	Separation	of	United	States	Steel"	on	page	42.

# 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	hedging	programs	may	differ materially	from	those	discussed	in	the	forward-looking	statements.

# Item	8.	Consolidated	Financial	Statements	and	Supplementary	Data

# Index	to	2004	Consolidated	Financial	Statements	and	Supplementary	Data

# Management's	Responsibilities	for	Financial	Statements

Management's	Report	on	Internal	Control	over	Financial	Reporting

Report	of	Independent	Registered	Public	Accounting	Firm

# Audited	Consolidated	Financial	Statements:

Consolidated	Statement	of	Income

Consolidated	Balance	Sheet

Consolidated	Statement	of	Cash	Flows

Consolidated	Statement	of	Stockholders'	Equity

Notes	to	Consolidated	Financial	Statements

Selected	Quarterly	Financial	Data	(Unaudited)

Principal	Unconsolidated	Investees	(Unaudited)

Supplementary	Information	on	Oil	and	Gas	Producing	Activities	(Unaudited)

Five-Year	Operating	Summary

Five-Year	Selected	Financial	Data

# 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	report	is consistent	with	these	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 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.

								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	and	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	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,	2004.

								Marathon's	management	assessment	of	the	effectiveness	of	Marathon's	internal	control	over	financial	reporting	as	of	December	31,	2004	has	been audited	by	PricewaterhouseCoopers	LLP,	an	independent	registered	public	accounting	firm,	as	stated	in	their	report	which	is	included	herein.

SIGNATURE SIGNATURE Clarence	P.	Cazalot,	Jr. Janet	F.	Clark President	and Senior	Vice	President Chief	Executive	Officer and	Chief	Financial	Officer

								We	have	completed	an	integrated	audit	of	Marathon	Oil	Corporation	and	its	subsidiaries'	(Marathon)	2004	consolidated	financial	statements	and	of its	internal	control	over	financial	reporting	as	of	December	31,	2004	and	audits	of	its	2003	and	2002	consolidated	financial	statements	in	accordance	with the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States).	Our	opinions,	based	on	our	audits,	are	presented	below.

								In	our	opinion,	the	accompanying	consolidated	financial	statements	appearing	on	pages	F-4	through	F-40	present	fairly,	in	all	material	respects,	the financial	position	of	Marathon	at	December	31,	2004	and	2003,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the	three	years	in	the period	ended	December	31,	2004,	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.	These	financial statements	are	the	responsibility	of	Marathon's	management.	Our	responsibility	is	to	express	an	opinion	on	these	financial	statements	based	on	our	audits. We	conducted	our	audits	of	these	statements	in	accordance	with	the	standards	of	the	Public	Company	Accounting	Oversight	Board	(United	States).	Those standards	require	that	we	plan	and	perform	the	audit	to	obtain	reasonable	assurance	about	whether	the	financial	statements	are	free	of	material misstatement.	An	audit	of	financial	statements	includes	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.	We	believe	that	our	audits	provide	a	reasonable	basis	for	our	opinion.

								As	discussed	in	Note	2	to	the	financial	statements,	Marathon	changed	its	method	of	accounting	for	asset	retirement	costs,	stock	based	compensation and	the	effects	of	early	extinguishment	of	debt	in	2003.

								Also,	in	our	opinion,	management's	assessment,	included	in	the	accompanying	Management's	Report	on	Internal	Control	Over	Financial	Reporting, that	Marathon	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2004,	based	on	criteria	established	in	Internal	Control	– Integrated	Framework	issued	by	the	Committee	of	Sponsoring	Organizations	of	the	Treadway	Commission	(COSO),	is	fairly	stated,	in	all	material respects,	based	on	those	criteria.	Furthermore,	in	our	opinion,	Marathon	maintained,	in	all	material	respects,	effective	internal	control	over	financial reporting	as	of	December	31,	2004,	based	on	criteria	established	in	Internal	Control	–	Integrated	Framework	issued	by	COSO.	Marathon's	management is	responsible	for	maintaining	effective	internal	control	over	financial	reporting	and	for	its	assessment	of	the	effectiveness	of	internal	control	over financial	reporting.	Our	responsibility	is	to	express	opinions	on	management's	assessment	and	on	the	effectiveness	of	the	Marathon's	internal	control	over financial	reporting	based	on	our	audit.	We	conducted	our	audit	of	internal	control	over	financial	reporting	in	accordance	with	the	standards	of	the	Public Company	Accounting	Oversight	Board	(United	States).	Those	standards	require	that	we	plan	and	perform	the	audit	to	obtain	reasonable	assurance	about whether	effective	internal	control	over	financial	reporting	was	maintained	in	all	material	respects.	An	audit	of	internal	control	over	financial	reporting includes	obtaining	an	understanding	of	internal	control	over	financial	reporting,	evaluating	management's	assessment,	testing	and	evaluating	the	design and	operating	effectiveness	of	internal	control,	and	performing	such	other	procedures	as	we	consider	necessary	in	the	circumstances.	We	believe	that	our audit	provides	a	reasonable	basis	for	our	opinions.

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

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

PricewaterhouseCoopers	LLP Houston,	Texas March	10,	2005

# (Dollars	in	millions	except	per	share	data)

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Revenues\tand\tother\tincome: |  |  |  |
| Sales\tand\tother\toperating\trevenues\t(including\tconsumer\texcise\ttaxes) | $39,383 | $32,884 | $25,946 |
| Revenues\tfrom\tmatching\tbuy/sell\ttransactions | 9,164 | 7,158 | 4,480 |
| Sales\tto\trelated\tparties | 1,051 | 921 | 869 |
| Income\tfrom\tequity\tmethod\tinvestments | 170 | 29 | 137 |
| Net\tgains\ton\tdisposal\tof\tassets | 36 | 166 | 67 |
| Gain\t(loss)\ton\townership\tchanges\tin\tMarathon\tAshland\tPetroleum\tLLC | 2 | (1) | 12 |
| Other\tincome | 101 | 77 | 44 |
| Total\trevenues\tand\tother\tincome | 49,907 | 41,234 | 31,555 |
| Costs\tand\texpenses: |  |  |  |
| Cost\tof\trevenues\t(excludes\titems\tshown\tbelow) | 30,740 | 24,918 | 18,878 |
| Purchases\trelated\tto\tmatching\tbuy/sell\ttransactions | 9,050 | 7,195 | 4,514 |
| Purchases\tfrom\trelated\tparties | 202 | 209 | 193 |
| Consumer\texcise\ttaxes | 4,463 | 4,285 | 4,250 |
| Depreciation,\tdepletion\tand\tamortization | 1,217 | 1,144 | 1,151 |
| Selling,\tgeneral\tand\tadministrative\texpenses | 1,025 | 920 | 823 |
| Other\ttaxes | 338 | 299 | 255 |
| Exploration\texpenses | 202 | 180 | 192 |
| Inventory\tmarket\tvaluation\tcredit | – | – | (71) |
| Total\tcosts\tand\texpenses | 47,237 | 39,150 | 30,185 |
| Income\tfrom\toperations | 2,670 | 2,084 | 1,370 |
| Net\tinterest\tand\tother\tfinancing\tcosts | 161 | 186 | 268 |
| Loss\tfrom\tearly\textinguishment\tof\tdebt | – | – | 53 |
| Minority\tinterest\tin\tincome\t(loss)\tof: |  |  |  |
| Marathon\tAshland\tPetroleum\tLLC | 532 | 302 | 173 |
| Equatorial\tGuinea\tLNG\tHoldings\tLimited | (7) | – | – |
| Income\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 1,984 | 1,596 | 876 |
| Provision\tfor\tincome\ttaxes | 727 | 584 | 369 |
| Income\tfrom\tcontinuing\toperations | 1,257 | 1,012 | 507 |
| Discontinued\toperations | 4 | 305 | (4) |
| Income\tbefore\tcumulative\teffect\tof\tchanges\tin\taccounting\tprinciples | 1,261 | 1,317 | 503 |
| Cumulative\teffect\tof\tchanges\tin\taccounting\tprinciples | – | 4 | 13 |
| Net\tincome | $1,261 | $1,321 | $516 |
| Per\tShare\tData |  |  |  |
| Basic |  |  |  |
| Income\tfrom\tcontinuing\toperations | $3.74 | $3.26 | $1.63 |
| Net\tincome | $3.75 | $4.26 | $1.66 |
| Diluted |  |  |  |
| Income\tfrom\tcontinuing\toperations | $3.72 | $3.26 | $1.63 |
| Net\tincome | $3.73 | $4.26 | $1.66 |

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

# (Dollars	in	millions)

|  | December	31 | 2004 | 2003 |
| :--- | :--- | :--- | :--- |
| Assets |  |  |  |
| Current\tassets: |  |  |  |
| Cash\tand\tcash\tequivalents |  | $3,369 | $1,396 |
| Receivables,\tless\tallowance\tfor\tdoubtful\taccounts\tof\t$6\tand\t$5 |  | 3,146 | 2,389 |
| Receivables\tfrom\tUnited\tStates\tSteel |  | 15 | 20 |
| Receivables\tfrom\trelated\tparties |  | 74 | 121 |
| Inventories |  | 1,995 | 1,955 |
| Other\tcurrent\tassets |  | 268 | 163 |
| Total\tcurrent\tassets |  | 8,867 | 6,044 |
| Investments\tand\tlong-term\treceivables,\tless\tallowance\tfor\tdoubtful\taccounts\tof\t$10\tand |  |  |  |
| $10 |  | 1,546 | 1,323 |
| Receivables\tfrom\tUnited\tStates\tSteel |  | 587 | 593 |
| Property,\tplant\tand\tequipment\t–\tnet |  | 11,810 | 10,830 |
| Prepaid\tpensions |  | 128 | 181 |
| Goodwill |  | 252 | 252 |
| Intangibles |  | 108 | 118 |
| Other\tnoncurrent\tassets |  | 125 | 141 |
| Total\tassets |  | $23,423 | $19,482 |
| Liabilities |  |  |  |
| Current\tliabilities: |  |  |  |
| Accounts\tpayable |  | $4,430 | $3,352 |
| Payables\tto\tUnited\tStates\tSteel |  | – | 4 |
| Payables\tto\trelated\tparties |  | 44 | 17 |
| Payroll\tand\tbenefits\tpayable |  | 274 | 230 |
| Accrued\ttaxes |  | 397 | 247 |
| Accrued\tinterest |  | 92 | 85 |
| Long-term\tdebt\tdue\twithin\tone\tyear |  | 16 | 272 |
| Total\tcurrent\tliabilities |  | 5,253 | 4,207 |
| Long-term\tdebt |  | 4,057 | 4,085 |
| Deferred\tincome\ttaxes |  | 1,553 | 1,489 |
| Employee\tbenefit\tobligations |  | 989 | 990 |
| Asset\tretirement\tobligations |  | 477 | 390 |
| Payables\tto\tUnited\tStates\tSteel |  | 5 | 8 |
| Deferred\tcredits\tand\tother\tliabilities |  | 288 | 227 |
| Total\tliabilities |  | 12,622 | 11,396 |
| Minority\tinterest\tin\tMarathon\tAshland\tPetroleum\tLLC |  | 2,559 | 2,011 |
| Minority\tinterest\tin\tEquatorial\tGuinea\tLNG\tHoldings\tLimited |  | 131 | – |
| Commitments\tand\tcontingencies |  | – | – |
| Stockholders'\tEquity |  |  |  |
| Common\tStock\tissued\t–\t346,727,029\tshares\tat\tDecember\t31,\t2004\tand\t312,165,978\tshares |  |  |  |
| at\tDecember\t31,\t2003\t(par\tvalue\t$1\tper\tshare,\tauthorized\t550,000,000\tshares) |  | 347 | 312 |
| Common\tStock\theld\tin\ttreasury\t–\t29,569\tshares\tat\tDecember\t31,\t2004\tand\t1,744,370 |  |  |  |
| shares\tat\tDecember\t31,\t2003 |  | (1) | (46) |
| Additional\tpaid-in\tcapital |  | 4,028 | 3,033 |
| Retained\tearnings |  | 3,810 | 2,897 |
| Accumulated\tother\tcomprehensive\tloss |  | (64) | (112) |
| Unearned\tcompensation |  | (9) | (9) |
| Total\tstockholders'\tequity |  | 8,111 | 6,075 |
| Total\tliabilities\tand\tstockholders'\tequity |  | $23,423 | $19,482 |

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Increase\t(decrease)\tin\tcash\tand\tcash\tequivalents |  |  |  |
| Operating\tactivities: |  |  |  |
| Net\tincome | $1,261 | $1,321 | $516 |
| Adjustments\tto\treconcile\tto\tnet\tcash\tprovided\tfrom\toperating\tactivities: |  |  |  |
| Cumulative\teffect\tof\tchanges\tin\taccounting\tprinciples | – | (4) | (13) |
| Loss\t(income)\tfrom\tdiscontinued\toperations | (4) | (305) | 4 |
| Deferred\tincome\ttaxes | (73) | 71 | 77 |
| Minority\tinterest\tin\tincome\tof\tsubsidiaries | 525 | 302 | 173 |
| Loss\tfrom\tearly\textinguishment\tof\tdebt | – | – | 53 |
| Depreciation,\tdepletion\tand\tamortization | 1,217 | 1,144 | 1,151 |
| Pension\tand\tother\tpostretirement\tbenefits\t–\tnet | 82 | 68 | 87 |
| Inventory\tmarket\tvaluation\tcredit | – | – | (71) |
| Exploratory\tdry\twell\tcosts\tand\tunproved\tproperty\timpairments | 106 | 86 | 116 |
| Net\tgains\ton\tdisposal\tof\tassets | (36) | (166) | (67) |
| Impairment\tof\tinvestments | – | 129 | – |
| Changes\tin\tthe\tfair\tvalue\tof\tlong-term\tnatural\tgas\tcontracts\tin\tthe\tUnited\tKingdom | 99 | 66 | (18) |
| Changes\tin:\tCurrent\treceivables | (709) | (671) | (103) |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tInventories | (41) | 33 | (53) |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tAccounts\tpayable\tand\tother\tcurrent\tliabilities | 1,224 | 496 | 614 |
| All\tother\t–\tnet | 79 | 95 | (135) |
| Net\tcash\tprovided\tfrom\tcontinuing\toperations | 3,730 | 2,665 | 2,331 |
| Net\tcash\tprovided\tfrom\tdiscontinued\toperations | – | 83 | 69 |
| Net\tcash\tprovided\tfrom\toperating\tactivities | 3,730 | 2,748 | 2,400 |
| Investing\tactivities: |  |  |  |
| Capital\texpenditures | (2,237) | (1,892) | (1,520) |
| Acquisitions | – | (252) | (1,160) |
| Disposal\tof\tdiscontinued\toperations | – | 612 | 54 |
| Disposal\tof\tassets | 76 | 644 | 146 |
| Restricted\tcash\t–\twithdrawals | 34 | 146 | 91 |
| \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–\tdeposits | (42) | (108) | (123) |
| Investments\t–\tcontributions | (4) | (34) | (111) |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\tloans\tand\tadvances | (156) | (91) | – |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\treturns\tand\trepayments | 40 | 55 | 10 |
| All\tother\t–\tnet | 1 | (19) | – |
| Investing\tactivities\tof\tdiscontinued\toperations | – | (29) | (48) |
| Net\tcash\tused\tin\tinvesting\tactivities | (2,288) | (968) | (2,661) |
| Financing\tactivities: |  |  |  |
| Commercial\tpaper\tand\trevolving\tcredit\tarrangements\t–\tnet | – | (131) | (375) |
| Debt\tissuance\tcosts | (4) | – | – |
| Other\tdebt\t–\tborrowings | – | – | 1,828 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\trepayments | (259) | (208) | (604) |
| Net\tproceeds\tfrom\tsale\tof\tcommon\tstock | 1,004 | – | – |
| Redemption\tof\tpreferred\tstock\tof\tsubsidiary | – | – | (185) |
| Preferred\tstock\trepurchased | – | – | (110) |
| Treasury\tcommon\tstock\t–\tproceeds\tfrom\tissuances | 43 | 17 | 2 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\tpurchases | (4) | (6) | (7) |
| Dividends\tpaid | (348) | (298) | (285) |
| Contributions\tfrom\tminority\tshareholder\tof\tEquatorial\tGuinea\tLNG\tHoldings\tLimited | 95 | – | – |
| Distributions\tto\tminority\tshareholder\tof\tMarathon\tAshland\tPetroleum\tLLC | – | (262) | (176) |
| Net\tcash\tprovided\tfrom\t(used\tin)\tfinancing\tactivities | 527 | (888) | 88 |
| Effect\tof\texchange\trate\tchanges\ton\tcash: |  |  |  |
| Continuing\toperations | 4 | 8 | 4 |
| Discontinued\toperations | – | 8 | – |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | 1,973 | 908 | (169) |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tyear | 1,396 | 488 | 657 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tyear | $3,369 | $1,396 | $488 |

|  |  | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Common\tstock: |  |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | Balance\tat\tbeginning\tof\tyear | $312 | $312 | $312 | 312,166 | 312,166 | 312,166 |
| (a) | (a) |  |  |  |  |  |  |
| Issuance | Issuance | 35 | – | – | 34,552 | – | – |
| Balance\tat\tend\tof\tyear | Balance\tat\tend\tof\tyear | $347 | $312 | $312 | 346,718 | 312,166 | 312,166 |
| Treasury\tcommon\tstock,\tat\tcost: |  |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | Balance\tat\tbeginning\tof\tyear | $(46) | $(60) | $(74) | (1,744) | (2,293) | (2,771) |
| Repurchased | Repurchased | (4) | (6) | (7) | (124) | (219) | (297) |
| Reissued\tfor: |  |  |  |  |  |  |  |
| Employee\tstock\tplans | Employee\tstock\tplans | 49 | 20 | 19 | 1,838 | 768 | 727 |
| Non-employee\tdirectors\tdeferred\tcompensation\tplan | Non-employee\tdirectors\tdeferred\tcompensation\tplan | – | – | 2 | – | – | 48 |
| Balance\tat\tend\tof\tyear | Balance\tat\tend\tof\tyear | $(1) | $(46) | $(60) | (30) | (1,744) | (2,293) |
|  |  |  |  |  |  | Comprehensive\tIncome |  |
|  |  |  |  |  | 2004 | 2003 | 2002 |
| Additional\tpaid-in\tcapital: |  |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | Balance\tat\tbeginning\tof\tyear | $3,033 | $3,032 | $3,035 |  |  |  |
|  | (a) |  |  |  |  |  |  |
| Common\tstock\tissuance | Common\tstock\tissuance | 970 | – | – |  |  |  |
| Treasury\tcommon\tstock\treissued | Treasury\tcommon\tstock\treissued | 25 | 1 | (3) |  |  |  |
| Balance\tat\tend\tof\tyear | Balance\tat\tend\tof\tyear | $4,028 | $3,033 | $3,032 |  |  |  |
| Unearned\tcompensation: |  |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | Balance\tat\tbeginning\tof\tyear | $(9) | $(7) | $(10) |  |  |  |
| Change\tduring\tyear | Change\tduring\tyear | – | (2) | 3 |  |  |  |
| Balance\tat\tend\tof\tyear | Balance\tat\tend\tof\tyear | $(9) | $(9) | $(7) |  |  |  |
| Retained\tearnings: |  |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | Balance\tat\tbeginning\tof\tyear | $2,897 | $1,874 | $1,643 |  |  |  |
| Net\tincome | Net\tincome | 1,261 | 1,321 | 516 | $1,261 | $1,321 | $516 |
| in\t2002) | in\t2002) | (348) | (298) | (285) |  |  |  |
| Balance\tat\tend\tof\tyear | Balance\tat\tend\tof\tyear | $3,810 | $2,897 | $1,874 |  |  |  |
|  | (b) |  |  |  |  |  |  |
| Accumulated\tother\tcomprehensive\tincome\t(loss) | : |  |  |  |  |  |  |
| Minimum\tpension\tliability\tadjustments: | Minimum\tpension\tliability\tadjustments: |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | Balance\tat\tbeginning\tof\tyear |  |  |  |  |  |  |
|  |  | $(93) | $(47) | $(14) |  |  |  |
| Changes\tduring\tyear | Changes\tduring\tyear | 22 | (46) | (33) | 22 | (46) | (33) |
| Balance\tat\tend\tof\tyear | Balance\tat\tend\tof\tyear | $(71) | $(93) | $(47) |  |  |  |
| Foreign\tcurrency\ttranslation\tadjustments: | Foreign\tcurrency\ttranslation\tadjustments: |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | Balance\tat\tbeginning\tof\tyear | $(4) | $(1) | $(3) |  |  |  |
| Changes\tduring\tyear | Changes\tduring\tyear | (1) | (3) | 2 | (1) | (3) | 2 |
| Balance\tat\tend\tof\tyear | Balance\tat\tend\tof\tyear | $(5) | $(4) | $(1) |  |  |  |
| Deferred\tgains\t(losses)\ton\tderivative\tinstruments: | Deferred\tgains\t(losses)\ton\tderivative\tinstruments: |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | Balance\tat\tbeginning\tof\tyear | $(15) | $(21) | $51 |  |  |  |
| Reclassification\tof\tthe\tcumulative\teffect\tadjustment\tinto | Reclassification\tof\tthe\tcumulative\teffect\tadjustment\tinto |  |  |  |  |  |  |
| income | income | (3) | (3) | (1) | (3) | (3) | (1) |
| Changes\tin\tfair\tvalue | Changes\tin\tfair\tvalue | (82) | (50) | (36) | (82) | (50) | (36) |
| Reclassification\tto\tincome | Reclassification\tto\tincome | 112 | 59 | (35) | 112 | 59 | (35) |
| Balance\tat\tend\tof\tyear | Balance\tat\tend\tof\tyear | $12 | $(15) | $(21) |  |  |  |
| Total\tbalances\tat\tend\tof\tyear | Total\tbalances\tat\tend\tof\tyear | $(64) | $(112) | $(69) |  |  |  |
|  | Total\tcomprehensive\tincome |  |  |  | $1,309 | $1,278 | $413 |
| Total\tstockholders'\tequity | Total\tstockholders'\tequity | $8,111 | $6,075 | $5,082 |  |  |  |

| (b)<br>	Related	income	tax	provision	(credit)	on	changes | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| \t\t\t\tand\treclassifications\tduring\tthe\tyear: |  |  |  |
| Minimum\tpension\tliability\tadjustments | $3 | $(25) | $(18) |
| Foreign\tcurrency\ttranslation\tadjustments | – | (2) | 2 |
| Net\tdeferred\tgains\t(losses)\ton\tderivative\tinstruments | 9 | 3 | (39) |

# 1.	Summary	of	Principal	Accounting	Policies

Marathon	is	engaged	in	worldwide	exploration	and	production	of	crude	oil	and	natural	gas;	domestic	refining,	marketing	and	transportation	of	crude	oil and	petroleum	products	primarily	through	its	62	percent	owned	consolidated	subsidiary	Marathon	Ashland	Petroleum	LLC	(MAP);	and	integrated	gas.

Principles	applied	in	consolidation		–		These	consolidated	financial	statements	include	the	accounts	of	the	businesses	comprising	Marathon.

								The	assets	and	liabilities	of	MAP	are	consolidated	in	these	financial	statements	and	minority	interest	representing	38	percent	of	the	carrying	value	of the	net	assets	of	MAP	has	been	recognized.	Under	certain	circumstances,	the	MAP	Limited	Liability	Company	Agreement	requires	unanimous	approval of	certain	matters	brought	to	the	MAP	Board	of	Managers.	Marathon	does	not	believe	that	the	rights	of	the	minority	shareholder	of	MAP	are	substantive because	the	likelihood	of	those	rights	being	triggered	is	remote.

								Investments	in	variable	interest	entities	("VIE")	in	which	Marathon	is	the	primary	beneficiary	are	consolidated.	Equatorial	Guinea	LNG	Holdings Limited	("EGHoldings"),	in	which	Marathon	holds	a	75	percent	interest	and	Compania	Nacional	de	Petroleos	de	Guinea	Ecuatorial	("GEPetrol")	holds	a 25	percent	interest,	is	a	VIE	and	Marathon	is	its	primary	beneficiary.	EGHoldings	was	formed	for	the	purpose	of	constructing	and	operating	a	liquefied natural	gas	("LNG")	plant,	and	as	of	December	31,	2004,	total	expenditures	of	$551	million,	including	$524	million	of	capital	expenditures,	related	to	the LNG	project	have	been	incurred.

								Investments	in	unincorporated	oil	and	gas	joint	ventures	and	undivided	interests	in	certain	pipelines,	gas	processing	plants	and	LNG	tankers	are consolidated	on	a	pro	rata	basis.

								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.	Differences	in	the	basis	of	the	investment	and	the	separate	net	asset	value	of	the investee,	if	any,	are	amortized	into	income	in	accordance	with	the	remaining	useful	life	of	the	underlying	assets.

								Investments	in	companies	whose	stock	is	publicly	traded	are	carried	at	market	value.	The	difference	between	the	cost	of	these	investments	and market	value	is	recorded	in	other	comprehensive	income	(net	of	tax).	Investments	in	companies	whose	stock	has	no	readily	determinable	fair	value	are carried	at	cost.

								Income	from	equity	method	investments	represents	Marathon's	proportionate	share	of	income	from	equity	method	investments.	Other	income includes	dividend	income	from	other	investments.	Dividend	income	is	recognized	when	dividend	payments	are	received.

								Gains	or	losses	from	a	change	in	ownership	of	a	consolidated	subsidiary	or	an	unconsolidated	investee	are	recognized	in	the	period	of	change.

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,	the	disclosure	of	contingent	assets	and	liabilities	at	year-end	and	the reported	amounts	of	revenues	and	expenses	during	the	year.	Items	subject	to	such	estimates	and	assumptions	include	the	carrying	value	of	property,	plant and	equipment,	goodwill,	intangibles,	equity	method	investments	and	non-exchange	traded	derivative	contracts;	valuation	allowances	for	receivables, inventories	and	deferred	income	tax	assets;	environmental	remediation	liabilities;	liabilities	for	potential	tax	deficiencies	and	potential	litigation	claims and	settlements;	assets	and	obligations	related	to	employee	benefits;	and	the	classification	of	gains	or	losses	on	cash	flow	hedges	of	forecasted transactions.	Actual	results	could	differ	from	the	estimates	and	assumptions	used.

Income	per	common	share		–		Basic	net	income	per	share	is	calculated	based	on	the	weighted	average	number	of	common	shares	outstanding.	Diluted net	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	three	reportable	operating	segments:

•Exploration	and	Production	("E&P")	–	explores	for	and	produces	crude	oil	and	natural	gas	on	a	worldwide	basis;

•Refining,	Marketing	and	Transportation	("RM&T")	–	refines,	markets	and	transports	crude	oil	and	petroleum	products,	primarily	in	the Midwest,	the	upper	Great	Plains	and	southeastern	United	States	through	MAP;	and

•Integrated	Gas	("IG")	–	markets	and	transports	natural	gas	and	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	on	a worldwide	basis.

								Management	has	determined	that	these	are	its	operating	segments	because	these	are	the	components	of	Marathon	(i)	that	engage	in	business activities	from	which	revenues	are	earned	and	expenses	are	incurred,	(ii)	whose	operating	results	are	regularly	reviewed	by	Marathon's	chief	operating decision	maker	to	make	decisions	about	resources	to	be	allocated	and	assess	performance	and	(iii)	for	which	discrete	financial	information	is	available. The	chief	operating	decision	maker	("CODM")	is	responsible	for	allocating	resources	to	and	assessing	performance	of	Marathon's	operating	segments. Information	on	assets	by	segment	is	not	provided	because	it	is	not	reviewed	by	the	CODM.	The	CODM	is	also

the	manager	over	each	of	the	segments.	In	this	role,	he	is	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	with	other	components	in	the	same	segment	because	they	have	similar economic	characteristics.

								Segment	income	represents	income	from	operations	allocable	to	operating	segments.	Marathon	corporate	general	and	administrative	costs	are	not allocated	to	operating	segments.	These	costs	primarily	consist	of	employment	costs	(including	pension	effects),	professional	services,	facilities	and	other related	costs	associated	with	corporate	activities.	Inventory	market	valuation	adjustments,	noncash	gains	(losses)	on	two	long-term	natural	gas	sales contracts	in	the	United	Kingdom	accounted	for	as	derivative	instruments	and	gains	(losses)	on	ownership	changes	in	subsidiaries	also	are	not	allocated	to operating	segments.	Additionally,	certain	nonoperating	or	infrequently	occurring	items	are	not	allocated	to	operating	segments	(see	segment	income reconcilement	table	on	page	F-20).

								Effective	January	1,	2004,	Marathon	realigned	its	segment	reporting	to	report	a	new	business	segment,	Integrated	Gas.	This	segment	includes Marathon's	LNG	operations	in	Alaska	and	Equatorial	Guinea,	methanol	operations	in	Equatorial	Guinea,	the	Elba	Island,	Georgia	LNG	regasification activities	and	certain	other	natural	gas	marketing	and	transportation	activities,	along	with	expenses	related	to	the	continued	development	of	an	integrated gas	business.	These	activities	were	previously	reported	in	the	Other	Energy	Related	Businesses	("OERB")	segment,	which	has	been	eliminated.	Crude	oil marketing	and	transportation	activities	and	costs	associated	with	a	gas-to-liquids	("GTL")	demonstration	plant,	previously	reported	in	OERB,	are	now reported	in	the	E&P	segment.	Refined	product	transportation	activities	not	included	in	MAP,	also	previously	reported	in	OERB,	are	now	reported	in	the RM&T	segment.	The	2003	and	2002	information	has	been	restated	to	report	the	new	segment	structure.

Revenue	recognition		–		Revenues	are	recognized	when	products	are	shipped	or	services	are	provided	to	customers,	the	sales	price	is	fixed	or determinable	and	collectibility	is	reasonably	assured.	Costs	associated	with	revenues	are	recorded	in	costs	of	revenues.

								Marathon	recognizes	revenues	from	the	production	of	oil	and	gas	when	title	is	transferred.	In	the	United	States	and	certain	international	locations, production	volumes	of	liquid	hydrocarbons	or	natural	gas	are	sold	immediately	and	transported	via	pipeline.	At	other	international	locations,	production volumes	may	be	stored	as	inventory	and	sold	at	a	later	time.	Royalties	on	the	production	of	oil	and	gas	are	either	paid	in	cash	or	settled	through	the delivery	of	volumes.	Marathon	includes	royalties	in	its	revenue	and	cost	of	revenues	when	settlement	of	royalties	is	paid	in	cash,	while	settlement	of royalties	based	on	the	delivery	of	volumes	are	excluded	from	revenue	and	cost	of	revenues.

								Rebates	from	vendors	are	recognized	as	a	reduction	to	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.

								Marathon	follows	the	sales	method	of	accounting	for	gas	production	imbalances	and	would	recognize	a	liability	if	the	existing	proved	reserves	were not	adequate	to	cover	the	current	imbalance	situation.

Matching	buy/sell	transactions		–		Matching	buy/sell	transactions	are	arrangements	in	which	Marathon	agrees	to	buy	a	specific	quantity	and	quality	of crude	oil	or	refined	petroleum	products	to	be	delivered	at	a	specific	location	while	simultaneously	agreeing	to	sell	a	specified	quantity	and	quality	of crude	oil	or	refined	petroleum	products	at	a	different	location,	usually	with	the	same	counterparty.	All	matching	buy/sell	transactions	are	settled	in	cash and	are	recorded	in	both	revenues	and	costs	of	revenues	as	separate	sales	and	purchase	transactions,	or	on	a	"gross"	basis.	The	commodity	purchased	and the	commodity	sold	generally	are	similar	in	nature.

								In	a	typical	buy/sell	transaction,	Marathon	enters	into	a	contract	to	sell	a	particular	grade	of	crude	oil	or	refined	product	at	a	specified	location	and date	to	a	particular	counterparty,	and	simultaneously	agrees	to	buy	a	particular	grade	of	crude	oil	or	refined	product	at	a	different	location	on	the	same	or another	specified	date,	typically	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	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	in	order	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.	Also,	for	the	RM&T	segment,	Marathon	enters	into	refined	product	matching	buy/sell	transactions	to	meet projected	customer	demands	and	to	secure	the	required	volumes	in	the	most	cost-effective	manner.

								The	characteristics	of	Marathon's	matching	buy/sell	transactions	include	gross	invoicing	between	Marathon	and	its	counterparties	and	cash settlement	of	the	transactions.	Nonperformance	by	one	party	to	deliver	generally	does	not	relieve	the	other	party's	obligation	to	perform.	Both transactions	require	physical	delivery	of	the	product.	The	risks	and	rewards	of	ownership	are	evidenced	by	title	transfer,	assumption	of	environmental risk,	transportation	scheduling,	credit	risk,	counterparty	nonperformance	risk	and	the	fact	that	Marathon	has	the	primary	obligation	to	perform.

								Marathon	believes	matching	buy/sell	transactions	are	monetary	in	nature	and	thus	outside	the	scope	of	APB	Opinion	No.	29,	"Accounting	for Nonmonetary	Transactions"	("APB	No.	29").	Additionally,	Marathon	has	evaluated	EITF	No.	99-19,	"Reporting	Revenue	Gross	as	a	Principal	versus Net	as	an	Agent"	("EITF	No.	99-19")	and,	based	on	that	evaluation,	management	believes	that	the	recording	of	these	transactions	on	a	gross	basis	is appropriate.

								The	EITF	has	not	yet	addressed	the	first	question.	The	EITF	discussed	the	second	question	at	its	November	2004	meeting	without	reaching	any consensus.	If	the	EITF	were	to	determine	that	these	transactions	should	be	accounted	for	as	monetary	transactions	on	a	gross	basis,	no	change	in Marathon's	accounting	policy	for	matching	buy/sell	transactions	would	be	necessary.	If	the	EITF	were	to	determine	that	these	transactions	should	be accounted	for	as	nonmonetary	transactions	qualifying	for	fair	value	recognition	and	require	a	net	presentation	of	such	transactions,	the	amounts	of revenues	and	cost	of	revenues	associated	with	matching	buy/sell	transactions	would	be	netted	in	Marathon's	consolidated	statement	of	income,	but	there would	be	no	effect	on	income	from	operations,	net	income	or	cash	flows	from	operations.	If	the	EITF	were	to	determine	that	these	transactions	should	be accounted	for	as	nonmonetary	transactions	not	qualifying	for	fair	value	recognition,	these	amounts	of	revenues	and	cost	of	revenues	would	be	netted	in Marathon's	consolidated	statement	of	income	and	there	could	be	an	impact	on	income	from	operations	and	net	income	related	to	the	timing	of	the ultimate	sale	of	product	purchased	in	the	"buy"	side	of	the	matching	buy/sell	transaction.	However,	management	does	not	believe	any	impact	would	be material.	There	would	be	no	impact	on	cash	flows	from	operations	as	a	result	of	this	accounting	treatment.

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.

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

								The	inventory	market	valuation	reserve	results	when	the	recorded	LIFO	cost	basis	of	crude	oil	and	refined	products	inventories	exceeds	net realizable	value.	The	reserve	is	decreased	when	market	prices	increase	and	inventories	turn	over	and	is	increased	when	market	prices	decrease.	Changes	in the	inventory	market	valuation	reserve	result	in	noncash	charges	or	credits	to	costs	and	expenses.

Accounts	Receivable	and	Allowance	for	Doubtful	Accounts		–		Trade	accounts	receivable	are	recorded	at	the	invoiced	amount	and	only	proprietary credit	card	receivables	bear	interest.	Accounts	receivable	consists	mainly	of	trade	receivables.	Account	balances	are	charged	to	bad	debt	expense	when	it is	probable	the	receivable	will	not	be	collected.	The	allowance	for	doubtful	accounts	is	the	best	estimate	of	the	amount	of	probable	credit	losses	in Marathon's	existing	proprietary	credit	card	receivables	and	other	receivables.	Marathon	determines	the	allowance	based	on	historical	write-off	experience and	proprietary	credit	card	sales.	Marathon	reviews	the	allowance	for	doubtful	accounts	quarterly	and	past	due	balances	over	180	days	are	reviewed individually	for	collectibility.

Traditional	derivative	instruments		–		Marathon	uses	commodity-based	derivatives	and	financial	instrument	related	derivatives	to	manage	its	exposure to	commodity	price	risk,	interest	rate	risk	or	foreign	currency	risk.	As	market	conditions	change,	Marathon	may	use	selective	derivative	instruments	that assume	market	risk	in	exchange	for	an	upfront	premium.	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	and	refined	products,	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 derivatives	are	recognized	immediately	in	income,	in	revenues,	other	income,	costs	of	revenues	or	net	interest	and	other	financing	costs,	unless	the derivative	qualifies	as	a	hedge	of	future	cash	flows	or	certain	foreign	currency	exposures.	Cash	flows	related	to	the	use	of	derivatives	are	classified	in operating	activities	with	the	underlying	hedged	transaction.

								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	a	component	of	stockholders'	equity	called	other	comprehensive	income	and	then	reclassified	to	income,	in	revenues,	costs	of	revenues	or net	interest	and	other	financing	costs,	when	the	underlying	anticipated	transaction	occurs.	Any	ineffective	portion	of	such	hedges	is	recognized	in	income as	it	occurs.	For	discontinued	cash	flow	hedges,	prospective	changes	in	the	fair	value	of	the	derivative	are	recognized	in	income.	Any	gain	or	loss accumulated	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	gain	or	loss	accumulated in	other	comprehensive	income	is	immediately	reclassified	into	income.

								For	derivatives	designated	as	hedges	of	the	fair	value	of	recognized	assets,	liabilities	or	firm	commitments,	changes	in	the	fair	value	of	both	the hedged	item	and	the	related	derivative	are	recognized	immediately	in	income,	in	revenues,

costs	of	revenues	or	net	interest	and	other	financing	costs,	with	an	offsetting	effect	included	in	the	basis	of	the	hedged	item.	The	net	effect	is	to	report	in income	the	extent	to	which	the	hedge	is	not	effective	in	achieving	offsetting	changes	in	fair	value.

								For	derivative	instruments	that	are	classified	as	trading,	changes	in	the	fair	value	are	recognized	immediately	in	other	income.	Any	premium received	is	amortized	into	income	based	on	the	underlying	settlement	terms	of	the	derivative	position.	All	related	effects	of	a	trading	strategy,	including physical	settlement	of	the	derivative	position,	are	recognized	in	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	in	the	balance	sheet	at	fair	value	and	changes	in	fair	value	are	recognized	in	income	as	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	that	delivery	location	to	be	considered derivative	instruments.	Other	physical	contracts	that	involve	flash	title	are	also	accounted	for	as	nontraditional	derivative	instruments.	Marathon	has made	an	election	under	generally	accepted	accounting	principles	to	treat	contracts	involving	flash	title	as	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	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	(a)	the well	has	found	a	sufficient	quantity	of	reserves	to	justify	its	completion	as	a	producing	well	and	(b)	Marathon	is	making	sufficient	progress	assessing	the reserves	and	the	economic	and	operating	viability	of	the	project.	Otherwise,	well	costs	are	expensed	if	a	determination	as	to	whether	proved	reserves were	found	cannot	be	made	within	one	year	following	the	completion	of	drilling	and	these	criteria	are	not	met.	The	status	of	suspended	well	costs	is monitored	continuously	and	reviewed	not	less	than	quarterly.

								In	February	2005,	the	Financial	Accounting	Standards	Board	("FASB")	proposed	FASB	Staff	Position	FAS	19-a,	"Accounting	for	Suspended	Well Costs"	("FSP	FAS	19-a"),	which	would	amend	the	guidance	for	suspended	well	costs	in	Statement	of	Financial	Accounting	Standard	No.	19,	"Financial Accounting	and	Reporting	by	Oil	and	Gas	Producing	Companies"	("SFAS	No.	19").	SFAS	No.	19	requires	costs	of	drilling	exploratory	wells	to	be capitalized	pending	determination	of	whether	the	well	has	found	proved	reserves.	If	the	well	has	found	proved	reserves,	the	capitalized	costs	become	part of	the	entity's	wells,	equipment,	and	facilities;	if,	however,	the	well	has	not	found	proved	reserves,	the	capitalized	costs	of	drilling	the	well	are	expensed. If	classification	of	proved	reserves	cannot	be	made	at	the	completion	of	the	drilling	in	an	area	requiring	a	major	capital	expenditure,	paragraph	31(a)	of SFAS	No.	19	provides	that	the	cost	should	continue	to	be	carried	as	an	asset	provided	that	(1)	there	have	been	sufficient	reserves	found	to	justify completion	as	a	producing	well	if	the	required	capital	expenditure	is	made	and	(2)	drilling	of	the	additional	exploratory	well	is	underway	or	firmly planned	for	the	near	future.	If	either	of	those	two	criteria	is	not	met,	SFAS	No.	19	indicates	the	entity	should	expense	the	exploratory	well	costs.	For	all other	exploratory	wells	not	addressed	in	paragraph	31(a),	paragraph	31(b)	provides	that	the	capitalized	costs	should	be	charged	to	expense	if	the	reserves cannot	be	classified	as	proved	after	a	year	following	the	completion	of	exploratory	drilling.	Questions	have	arisen	in	practice	about	the	application	of	this guidance	due	to	changes	in	oil	and	gas	exploration	processes	and	lifecycles.	The	issue	is	whether	there	are	circumstances	that	would	permit	the	continued capitalization	of	exploratory	well	costs	beyond	one	year	other	than	when	additional	exploration	wells	are	necessary	to	justify	major	capital	expenditures and	those	wells	are	underway	or	firmly	planned	for	the	near	future.	The	proposed	FSP	FAS	19-a	would	allow	exploratory	well	costs	to	continue	to	be capitalized	when	(a)	the	well	has	found	a	sufficient	quantity	of	reserves	to	justify	completion	as	a	producing	well	and	(b)	the	enterprise	is	making sufficient	progress	assessing	the	reserves	and	the	economic	and	operating	viability	of	the	project.	Marathon's	current	policy	is	in	accordance	with	the proposed	FSP	FAS	19-a.	The	proposed	FSP	FAS	19-a	also	provides	for	certain	disclosures	to	be	made	regarding	capitalized	exploratory	well	costs.

								Capitalized	costs	of	producing	oil	and	gas	properties	are	depreciated	and	depleted	by	the	units-of-production	method.	Support	equipment	and	other property,	plant	and	equipment	are	depreciated	on	a	straight	line	basis	over	their	estimated	useful	lives.

								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	carrying	value	exceeds	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	values.

								Marathon	evaluates	its	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	or	future	plans	to	develop	acreage	are also	considered.	Impairment	expense	for	unproved	oil	and	gas	properties	is	reported	in	exploration	expense.

								Property,	plant	and	equipment	unrelated	to	oil	and	gas	producing	activities	is	recorded	at	cost	and	depreciated	on	the	straight-line	method	over	the estimated	useful	lives	of	the	assets,	which	range	from	3	to	42	years.

								When	property,	plant	and	equipment	depreciated	on	an	individual	basis	are	sold	or	otherwise	disposed	of,	any	gains	or	losses	are	reported	in	income. Gains	on	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	reclassified	as	held	for	sale.	Proceeds	from	disposal	of	property,	plant	and	equipment depreciated	on	a	group	basis	are	credited	to	accumulated	depreciation,	depletion	and	amortization	with	no	immediate	effect	on	income.

Goodwill		–		Goodwill	represents	the	excess	of	the	purchase	price	over	the	estimated	fair	value	of	the	net	assets	acquired,	primarily	from	the	acquisitions of	the	Equatorial	Guinea	interests	in	2002	and	of	Pennaco	Energy,	Inc.	in	2000.	Annually,	Marathon	assesses	the	carrying	amount	of	goodwill	by	testing for	impairment.	The	impairment	test	requires	allocating	goodwill	and	other	assets	and	liabilities	to	reporting	units.	Marathon	has	determined	the components	of	the	E&P	segment	have	similar	economic	characteristics	and	therefore	aggregates	the	components	into	a	single	reporting	unit.	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	down	to	its	implied	fair	value	with	a	charge	to	expense.

Intangible	assets		–		Intangible	assets	consists	of	deferred	marketing	costs,	intangible	contract	rights,	proprietary	information,	and	unrecognized	pension plan	prior	service	costs.	The	marketing	costs	incurred	in	the	RM&T	segment	relate	to	refurbishment	of	various	branded	jobber	locations.	These	marketing costs	are	amortized	over	five	to	ten	years	depending	on	the	term	of	the	associated	marketing	agreement.	Additionally,	Marathon	has	intangibles	in	the	IG segment	associated	with	the	acquisition	of	a	contractual	right	to	utilize	the	Elba	Island	LNG	terminal	in	Savannah,	Georgia.	These	rights	are	being amortized	over	the	expected	life	of	the	contract.

Major	maintenance	activities		–		Marathon	incurs	costs	for	planned	major	refinery	maintenance	("turnarounds").	Such	costs	are	expensed	in	the	same annual	period	as	incurred;	however,	estimated	annual	turnaround	costs	are	recognized	in	income	throughout	the	year	on	a	pro	rata	basis.

Environmental	remediation	liabilities		–		Environmental	remediation	expenditures	are	capitalized	if	the	costs	mitigate	past	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.

Asset	retirement	obligations		–		The	fair	value	of	asset	retirement	obligations	are	recognized	in	the	period	in	which	they	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	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.	Depreciation	of	capitalized	asset	retirement	cost	and	accretion	of	asset	retirement	obligations	are recorded	over	time.	The	depreciation	will	generally	be	determined	on	a	units-of-production	basis,	while	the	accretion	to	be	recognized	will	escalate	over the	life	of	the	producing	assets.	Asset	retirement	obligations	have	not	been	recognized	for	certain	refinery,	crude	oil	and	product	pipeline	and	marketing assets	because	the	fair	value	cannot	be	estimated	due	to	the	uncertainty	of	the	settlement	date	of	the	obligation.	Additionally,	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.

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	existing	assets	and	liabilities	and	their	tax	bases	as	reported	in	Marathon's	filings	with	the	respective	taxing authority.	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.

Pensions	and	other	postretirement	benefits		–		Marathon	has	noncontributory	defined	benefit	pension	plans	covering	substantially	all	domestic employees,	international	employees	located	in	Ireland,	Norway	and	the	United	Kingdom,	and	most	MAP	employees.	In	addition,	several	excess	benefits plans	exist	covering	domestic	employees	within	defined	regulatory	compensation	limits.	Benefits	under	these	plans	are	based	primarily	on	years	of service	and	final	average	pensionable	earnings.	MAP	also	participates	in	a	multiemployer	plan	that	provides	coverage	for	less	than	5	percent	of	its employees.	The	benefits	provided	include	both	pension	and	health	care.

								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	prefunded.

								Marathon	uses	a	December	31	measurement	date	for	its	pension	and	other	postretirement	benefit	plans.

Stock-based	compensation		–		The	Marathon	Oil	Corporation	2003	Incentive	Compensation	Plan	(the	"Plan")	authorizes	the	Compensation	Committee	of the	Board	of	Directors	of	Marathon	to	grant	stock	options,	stock	appreciation	rights,	stock	awards,	cash	awards	and	performance	awards	to	employees. The	Plan	also	allows	Marathon	to	provide	equity	compensation	to	its	non-employee	directors	of	its	Board	of	Directors.	The	Plan	was	approved	by Marathon's	shareholders	on	April	30,	2003.	No	more	than	20,000,000	shares	of	common	stock	may	be	issued	under	the	Plan,	and	no	more	than 8,500,000	of	those	shares	may	be	used	for	awards	other	than	stock	options	or	stock	appreciation	rights.	Shares	subject	to	awards	that	are	forfeited, terminated,	expire	unexercised,	settled	in	cash,	exchanged	for	other	awards,	tendered	to	satisfy	the	purchase	price	of	an	award,	withheld	to	satisfy	tax obligations	or	otherwise	lapse	again	become	available	for	awards.

								The	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	(collectively,	the	"Prior	Plans").	No	new	grants	will	be	made	from	the	Prior	Plans.	Any	awards	previously	granted under	the	Prior	Plans	shall	continue	to	vest	and/or	be	exercisable	in	accordance	with	their	original	terms	and	conditions.

								Stock	options	represent	the	right	to	purchase	shares	of	stock	at	the	fair	market	value	of	the	stock	on	the	date	of	grant.	Certain	options	are	granted 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	plan,	over	the	option	price	of	shares.	Most	stock	options	granted	under	the Plan	vest	ratably	over	a	three-year	period	and	all	expire	10	years	from	the	date	they	are	granted.

								Similar	to	stock	options,	stock	appreciation	rights	("SARs")	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	exercise	price.	In	general,	SARs	that	have	been	granted	under	the	Plan	are	settled	in shares	of	stock,	vest	ratably	over	a	three-year	period,	and	have	a	maximum	term	of	10	years	from	the	date	they	are	granted.

								The	Compensation	Committee	grants	stock-based	Performance	Awards	to	officers	under	the	Plan.	The	stock-based	Performance	Awards	represent shares	of	common	stock	that	are	subject	to	forfeiture	provisions	and	restrictions	on	transfer.	Those	restrictions	may	be	removed	if	certain	pre-established performance	measures	are	met.	The	stock-based	Performance	Awards	granted	under	the	Plan	generally	vest	at	the	end	of	a	thirty-six	month	performance period	if	certain	pre-established	performance	targets	are	achieved.

								Marathon	also	grants	restricted	stock	to	certain	non-officer	employees	under	the	Plan.	Participants	are	awarded	restricted	stock	by	the	Salary	and Benefits	Committee	based	on	their	performance	within	certain	guidelines.	The	restricted	stock	awards	vest	in	one-third	increments	over	a	three-year period,	contingent	on	the	recipient's	continued	employment.	Prior	to	vesting,	the	restricted	stock	recipients	have	the	right	to	vote	such	stock	and	receive dividends	thereon.	The	nonvested	shares	are	not	transferable	and	are	retained	by	Marathon	until	they	vest.

								Unearned	compensation	is	charged	to	equity	when	restricted	stock	and	performance	shares	are	granted.	Compensation	expense	is	recognized	over the	balance	of	the	vesting	period	and	is	adjusted	if	conditions	of	the	restricted	stock	or	performance	share	grant	are	not	met.	Amounts	related	to	the performance-based	restricted	stock	awards	under	the	1990	Plan	are	subsequently	adjusted	for	changes	in	the	market	value	of	the	underlying	stock.

								Marathon	maintains	an	equity	compensation	program	for	its	non-employee	directors	under	the	Plan.	Pursuant	to	the	program,	non-employee directors	must	defer	50	percent	of	their	annual	retainers	in	the	form	of	common	stock	units.	In	addition,	the	program	provides	each	non-employee director	with	a	matching	grant	of	up	to	1,000	shares	of	common	stock	on	his	or	her	initial	election	to	the	board	if	he	or	she	purchases	an	equivalent number	of	shares	within	60	days	of	joining	the	board.

								Effective	January	1,	2003,	Marathon	applied	the	fair	value	based	method	of	accounting	to	future	grants	and	any	modified	grants	for	stock-based compensation.	All	prior	outstanding	and	unvested	awards	continue	to	be	accounted	for

under	the	intrinsic	value	method.	The	following	net	income	and	per	share	data	illustrates	the	effect	on	net	income	and	net	income	per	share	if	the	fair value	method	had	been	applied	to	all	outstanding	and	unvested	awards	in	each	period.

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Net\tincome\tapplicable\tto\tCommon\tStock |  |  |  |
| As\treported | $1,261 | $1,321 | $516 |
| Add:\tStock-based\temployee\tcompensation\texpense\tincluded\tin\treported\tnet\tincome,\tnet\tof\trelated\ttax |  |  |  |
| effects | 39 | 23 | 5 |
| Deduct:\tTotal\tstock-based\temployee\tcompensation\texpense\tdetermined\tunder\tfair\tvalue\tmethod\tfor\tall |  |  |  |
| awards,\tnet\tof\trelated\ttax\teffects | (32) | (17) | (16) |
| Pro\tforma\tnet\tincome\tapplicable\tto\tCommon\tStock | $1,268 | $1,327 | $505 |
| Basic\tnet\tincome\tper\tshare |  |  |  |
| –\tAs\treported | $3.75 | $4.26 | $1.66 |
| –\tPro\tforma | $3.77 | $4.28 | $1.63 |
| Diluted\tnet\tincome\tper\tshare |  |  |  |
| –\tAs\treported | $3.73 | $4.26 | $1.66 |
| –\tPro\tforma | $3.75 | $4.28 | $1.63 |

The	above	pro	forma	amounts	were	based	on	a	Black-Scholes	option-pricing	model,	which	included	the	following	information	and	assumptions:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Weighted-average\tgrant-date\texercise\tprice\tper\tshare | $33.61 | $25.58 | $28.12 |
| Expected\tannual\tdividends\tper\tshare | $1.00 | $.97 | $.92 |
| Expected\tlife\tin\tyears | 5.5 | 5 | 5 |
| Expected\tvolatility | 32% | 34% | 35% |
| Risk\tfree\tinterest\trate | 3.9% | 3.0% | 4.5% |
| Weighted-average\tgrant-date\tfair\tvalue\tof\toptions\tgranted\tduring\tthe\tyear,\tas\tcalculated\tfrom\tabove | $8.83 | $5.37 | $7.79 |

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	Separation.	These	exposures	are	discussed	in	Note	3.

Reclassifications		–		Certain	reclassifications	of	prior	years'	data	have	been	made	to	conform	to	2004	classifications.

# 2.	New	Accounting	Standards

Effective	July	1,	2004,	Marathon	adopted	FASB	Staff	Position	FAS	106-2	("FSP	FAS	106-2")	"Accounting	and	Disclosure	Requirements	Related	to	the Medicare	Prescription	Drug,	Improvement	and	Modernization	Act	of	2003"	("the	Act").	FSP	FAS	106-2	includes	guidance	on	recognizing	the	effects	of the	new	legislation	under	the	various	conditions	surrounding	the	assessment	of	"actuarial	equivalence."	Marathon	has	determined,	based	on	available regulatory	guidance,	that	the	postretirement	plans'	prescription	drug	benefits	are	actuarially	equivalent	to	the	Medicare	"Part	D"	benefit	under	the	Act.	The subsidy-related	reduction	at	July	1,	2004	in	the	accumulated	postretirement	benefit	obligation	for	the	Marathon	and	MAP	postretirement	plans	are $44	million	and	$49	million.	The	combined	favorable	pretax	effect	of	the	subsidy-related	reduction	for	2004	on	the	measurement	of	the	net	periodic postretirement	benefit	cost	related	to	service	cost,	interest	cost	and	actuarial	gain	amortization,	is	$7	million.

								Effective	July	1,	2004,	Marathon	adopted	FASB	Staff	Position	FAS	142-2,	"Application	of	FASB	Statement	No.	142,	Goodwill	and	Other Intangible	Assets,	to	Oil-	and	Gas-Producing	Entities"	("FSP	FAS	142-2").	FSP	FAS	142-2	states	drilling	and	mineral	rights	of	oil-	and	gas-producing entities	are	excluded	from	Statement	of	Financial	Accounting	Standard	No.	142	"Goodwill	and	Other	Intangible	Assets"	("SFAS	No.	142"),	and accordingly,	should	not	be	classified	as	intangible	assets	rather	than	oil	and	gas	properties.	The	adoption	of	FSP	FAS	142-2	did	not	have	an	effect	on Marathon's	financial	position,	cash	flows	or	results	of	operations.

								Effective	December	21,	2004,	Marathon	adopted	FASB	Staff	Position	FAS	109-1,	"Application	of	FASB	Statement	No.	109,	Accounting	for Income	Taxes,	to	the	Tax	Deduction	on	Qualified	Production	Activities	Provided	by	the	American	Jobs	Creation	Act	of	2004"	("FSP	FAS	109-1").	FSP FAS	109-1	states	the	deduction,	signed	into	law	by	the	President	on	October	22,	2004,	of	up	to	9	percent	(when	fully	phased-in)	of	the	lesser	of (a)	"qualified	production	activities	income,"	as	defined	in	the	Act,	or	(b)	taxable	income	(after	the	deduction	for	the	utilization	of	any	net	operating	loss carryforwards)	should	be	accounted	for	as	a	special	deduction	in	accordance	with	Statement	109.	Accordingly,	Marathon	will	treat	the	deduction	as	a permanent	difference	in	the	years	taken.

								Effective	December	21,	2004,	Marathon	adopted	FASB	Staff	Position	FAS	109-2,	"Accounting	and	Disclosure	Guidance	for	the	Foreign	Earnings Repatriation	Provision	within	the	American	Jobs	Creation	Act	of	2004"	("FSP	FAS	109-2").	The	American	Jobs	Creation	Act	of	2004	(the	Act) introduces	a	special	one-time	dividends	received	deduction	on	the	repatriation	of	certain	foreign	earnings	to	a	U.S.	taxpayer,	provided	certain	criteria	are met.	FSP	FAS	109-2	states	an	enterprise	is	allowed	time	beyond	the	financial	reporting	period	of	enactment	to	evaluate	the	effect	of	the	Act	on	its	plan for	reinvestment	or	repatriation	of	foreign	earnings	for	purposes	of	applying	Statement	109.	Marathon	does	not	intend	to	repatriate	foreign	earnings	due	to the	cash	commitments	for	foreign	capital	projects.

								In	the	second	quarter	of	2002,	the	Financial	Accounting	Standards	Board	("FASB")	issued	Statement	of	Financial	Accounting	Standards	No.	145 "Rescission	of	FASB	Statements	No.	4,	44,	and	64,	Amendment	of	FASB	Statement	No.	13,	and	Technical	Corrections"	("SFAS	No.	145").	Effective January	1,	2003,	Marathon	adopted	the	provisions	relating	to	the	classification	of	the	effects	of	early	extinguishment	of	debt	in	the	consolidated	statement of	income.	As	a	result,	losses	of	$53	million	from	the	early	extinguishment	of	debt	in	2002,	which	were	previously	reported	as	an	extraordinary	item	(net of	tax	of	$20	million),	have	been	reclassified	into	income	before	income	taxes.	The	adoption	of	SFAS	No.	145	had	no	impact	on	net	income	for	2002.

								Effective	January	1,	2003,	Marathon	adopted	the	fair	value	recognition	provisions	of	Statement	of	Financial	Accounting	Standards	No.	123 "Accounting	for	Stock-Based	Compensation"	("SFAS	No.	123").	Statement	of	Financial	Accounting	Standards	No.	148	"Accounting	for	Stock-Based Compensation	–	Transition	and	Disclosure"	("SFAS	No.	148"),	an	amendment	of	SFAS	No.	123,	provides	alternative	methods	for	the	transition	of	the accounting	for	stock-based	compensation	from	the	intrinsic	value	method	to	the	fair	value	method.	Marathon	has	applied	the	fair	value	method	to	grants made,	modified	or	settled	on	or	after	January	1,	2003.	The	impact	on	Marathon's	2003	net	income	was	not	materially	different	than	under	previous accounting	standards.

								Effective	January	1,	2003,	Marathon	adopted	Statement	of	Financial	Accounting	Standards	No.	143	"Accounting	for	Asset	Retirement	Obligations" ("SFAS	No.	143").	The	transition	adjustment	related	to	adopting	SFAS	No.	143	on	January	1,	2003,	was	recognized	as	a	cumulative	effect	of	a	change	in accounting	principle.	The	cumulative	effect	on	net	income	of	adopting	SFAS	No.	143	was	a	net	favorable	effect	of	$4	million,	net	of	tax	of	$4	million.	At the	time	of	adoption,	total	assets	increased	$120	million,	and	total	liabilities	increased	$116	million.	The	amounts	recognized	on	adoption	are	based	on numerous	estimates	and	assumptions,	including	future	retirement	costs,	future	recoverable	quantities	of	oil	and	gas,	future	inflation	rates	and	the	credit- adjusted	risk-free	interest	rate.

								Since	the	issuance	of	Statement	of	Financial	Accounting	Standards	No.	133	"Accounting	for	Derivative	Instruments	and	Hedging	Activities" ("SFAS	No.	133"),	as	amended	by	SFAS	Nos.	137	and	138,	the	FASB	has	issued	several	interpretations.	As	a	result,	Marathon	has	recognized	in	income the	effect	of	changes	in	the	fair	value	of	two	long-term	natural	gas	sales	contracts	in	the	United	Kingdom.	As	of	January	1,	2002,	Marathon	recognized	a favorable	cumulative	effect	of	a	change	in	accounting	principle	of	$13	million,	net	of	tax	of	$7	million.

# 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 ("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.	("Clairton	1314B"),	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	the	payment	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.

								The	Tax	Sharing	Agreement	incorporates	the	general	tax	sharing	principles	of	the	former	tax	allocation	policy.	In	general,	Marathon	and	United States	Steel,	will	make	payments	between	them	such	that,	with	respect	to	any	consolidated,	combined	or	unitary	tax	returns	for	any	taxable	period	or portion	thereof	ending	on	or	before	the	Separation	Date,	the	amount	of	taxes	to	be	paid	by	each	of	Marathon	and	United	States	Steel	will	be	determined, subject	to	certain	adjustments,	as	if	the	former	groups	each	filed	their	own	consolidated,	combined	or	unitary	tax	return.	The	Tax	Sharing	Agreement	also provides	for	payments	between	Marathon	and	United	States	Steel	for	certain	tax	adjustments	that	may	be	made	after	the	Separation.	Other	provisions address,	but	are	not	limited	to,	the	handling	of	tax	audits,	settlements	and	return	filing	in	cases	where	both	Marathon	and	United	States	Steel	have	an interest	in	the	results	of	these	activities.

								In	2004	and	2003,	in	accordance	with	the	terms	of	the	tax	sharing	agreement,	Marathon	paid	$3	million	and	$16	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	1992 through	1994.	Included	in	discontinued	operations	in	2003	is	an	$8	million	adjustment	to	the	liabilities	to	United	States	Steel	under	this	tax	sharing agreement.

Relationship	Between	Marathon	and	United	States	Steel	After	the	Separation		–		As	a	result	of	the	Separation,	Marathon	and	United	States	Steel	are separate	companies,	and	neither	has	any	ownership	interest	in	the	other.	Thomas	J.	Usher	is	the	non-executive	chairman	of	the	board	of	both	companies, and	as	of	December	31,	2004,	four	of	the	ten	remaining	members	of	Marathon's	board	of	directors	are	also	directors	of	United	States	Steel.

								Sales	to	United	States	Steel	in	2004,	2003	and	2002	were	$30	million,	$31	million	and	$14	million,	primarily	for	natural	gas.	Purchases	from	United States	Steel	in	2004,	2003	and	2002	were	$27	million,	$14	million	and	$12	million,	primarily	for	raw	materials.	Management	believes	that	transactions with	United	States	Steel	were	conducted	under	terms	comparable	to	those	with	unrelated	parties.	Marathon	reimbursed	United	States	Steel	$3	million	in both	2004	and	2002	for	the	payment	of	benefits	to	retirees,	including	Mr.	Usher,	under	United	States	Steel's	2001	plan	of	reorganization.

								In	2002,	Marathon	cancelled	the	unvested	restricted	stock	awards	held	by	certain	former	officers	and	provided	each	with	an	appropriate	cash settlement.	The	total	cost	of	the	settlement	was	$5	million.

Amounts	Receivable	from	or	Payable	to	United	States	Steel	Arising	from	the	Separation		–		As	previously	discussed,	Marathon	remains	primarily obligated	for	certain	financings	for	which	United	States	Steel	has	assumed	responsibility	for	repayment	under	the	terms	of	the	Separation.	When	United States	Steel	makes	payments	on	the	principal	of	these	financings,	both	the	receivable	and	the	obligation	will	be	reduced.

								At	December	31,	2004	and	2003,	amounts	receivable	or	payable	to	United	States	Steel	were	included	in	the	balance	sheet	as	follows:

|  | 2004 | 2003 |
| :--- | :--- | :--- |
| Receivables: |  |  |
| Current: |  |  |
| Receivables\trelated\tto\tdebt\tand\tother\tobligations\tfor\twhich\tUnited\tStates\tSteel\thas\tassumed\tresponsibility\tfor |  |  |
| repayment | $15 | $20 |
| Noncurrent: |  |  |
| Receivables\trelated\tto\tdebt\tand\tother\tobligations\tfor\twhich\tUnited\tStates\tSteel\thas\tassumed\tresponsibility\tfor |  |  |
| repayment | $587 | $593 |
| Payables: |  |  |
| Current: |  |  |
| Income\ttax\tsettlement\tand\trelated\tinterest\tpayable | $– | $4 |
| Noncurrent: |  |  |
| Reimbursements\tpayable\tunder\tnonqualified\temployee\tbenefit\tplans | $5 | $8 |

								Marathon	remains	primarily	obligated	for	$55	million	of	operating	lease	obligations	assumed	by	United	States	Steel,	of	which	$42	million	has	in turn	been	assumed	by	other	third	parties	that	had	purchased	plants	and	operations	divested	by	United	States	Steel.

								In	addition,	Marathon	remains	contingently	liable	for	certain	obligations	of	United	States	Steel.	See	Note	28	for	additional	details	on	these guarantees.

# 4.	Related	Party	Transactions

# Related	parties	include:

•Ashland	Inc.	("Ashland"),	which	holds	a	38	percent	ownership	interest	in	MAP,	a	consolidated	subsidiary;

•GEPetrol,	which	holds	a	25	percent	ownership	interest	in	EGHoldings,	a	consolidated	subsidiary;	and

•Equity	method	investees.	See	"Principal	Unconsolidated	Investees"	on	page	F-41	for	major	investees.

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

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Ashland | $274 | $258 | $218 |
| Equity\tinvestees: |  |  |  |
| Pilot\tTravel\tCenters\tLLC\t("PTC") | 715 | 635 | 645 |
| Centennial\tPipeline\tLLC\t("Centennial") | 49 | 16 | – |
| Other | 13 | 12 | 6 |
| Total | $1,051 | $921 | $869 |

								Purchases	from	related	parties	were	as	follows:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Ashland | $22 | $24 | $33 |
| Equity\tinvestees |  |  |  |
| Centennial | 56 | 49 | 16 |
| Other | 124 | 136 | 144 |
| Total | $202 | $209 | $193 |

								Receivables	from	related	parties	were	as	follows:

|  | 2004 | 2003 |
| :--- | :--- | :--- |
| Ashland | $18 | $22 |
| Equity\tinvestees: |  |  |
| PTC | 19 | 16 |
| (a)\nAlba\tPlant\tLLC\tand\trelated\tcompanies | 17 | 73 |
| Centennial | 16 | 7 |
| Other | 4 | 3 |
| Total | $74 | $121 |

(a) Receivables	relate	to	invoices	paid	by	Marathon	on	behalf	of	Alba	Plant	LLC.

								Payables	to	related	parties	were	as	follows:

|  | 2004 | 2003 |
| :--- | :--- | :--- |
| Ashland | $– | $1 |
| GEPetrol | 23 | – |
| Equity\tinvestees |  |  |
| Centennial | 12 | 10 |
| Other | 9 | 6 |
| Total | $44 | $17 |

								MAP	has	a	$190	million	uncommitted	revolving	credit	agreement	with	Ashland.	Interest	on	borrowings	is	based	on	defined	short-term	borrowing rates.	At	December	31,	2004	and	2003,	there	were	no	borrowings	against	this	facility.	Interest	paid	to	Ashland	for	borrowings	under	this	agreement	was less	than	$1	million	for	2004,	2003	and	2002.

								Cash	held	in	escrow	for	future	contributions	to	EGHoldings	from	GEPetrol	of	$66	million	is	classified	as	restricted	cash	and	is	included	in investments	and	long-term	receivables	as	of	December	31,	2004.

# 5.	Business	Combinations

On	May	12,	2003,	Marathon	acquired	Khanty	Mansiysk	Oil	Corporation	("KMOC")	for	$285	million,	including	the	assumption	of	$31	million	in	debt. KMOC	is	currently	evaluating	or	developing	nine	oil	fields	in	the	Khanty-Mansiysk	region	of	western	Siberia	in	the	Russian	Federation.	Results	of operations	for	2003	include	the	results	of	KMOC	from	May	12,	2003.	The	allocation	of	purchase	price	is	final.	There	was	no	goodwill	associated	with	the purchase.

								The	following	table	summarizes	the	allocation	of	the	purchase	price	of	KMOC	to	the	assets	acquired	and	liabilities	assumed	at	the	date	of acquisition:

								The	following	unaudited	pro	forma	data	for	Marathon	includes	the	results	of	operations	of	KMOC	giving	effect	to	the	acquisition	as	if	it	had	been consummated	at	the	beginning	of	the	period	presented.	The	pro	forma	data	is	based	on	historical	information	and	does	not	necessarily	represent	the	actual results	that	would	have	occurred	nor	is	it	necessarily	indicative	of	future	results	of	operations.

# (In	millions,	except	per	share	amounts)

| Revenues	and	other	income | $41,257 |
| :--- | :--- |
| Income\tfrom\tcontinuing\toperations | 1,005 |
| Net\tincome | 1,314 |
| Per\tshare\tamounts\tapplicable\tto\tCommon\tStock |  |
| Income\tfrom\tcontinuing\toperations\t–\tbasic\tand\tdiluted | 3.24 |
| Net\tincome\t–\tbasic\tand\tdiluted | 4.23 |

								During	2002,	in	two	separate	transactions,	Marathon	acquired	interests	in	the	Alba	Field	offshore	Equatorial	Guinea,	West	Africa,	and	certain	other related	assets.

								On	January	3,	2002,	Marathon	acquired	certain	interests	from	CMS	Energy	Corporation	for	$1.005	billion.	Marathon	acquired	three	entities	that own	a	combined	52.4	percent	working	interest	in	the	Alba	Production	Sharing	Contract	and	a	net	43.2	percent	interest	in	an	onshore	liquefied	petroleum gas	processing	plant	through	an	equity	method	investee.	Additionally,	Marathon	acquired	a	45.0	percent	net	interest	in	an	onshore	methanol	production plant	through	an	equity	method	investee.	Results	of	operations	for	2002	include	the	results	of	the	interests	acquired	from	CMS	Energy	from	January	3, 2002.

								On	June	20,	2002,	Marathon	acquired	100	percent	of	the	outstanding	stock	of	Globex	Energy,	Inc.	("Globex")	for	$155	million.	Globex	owned	an additional	10.9	percent	working	interest	in	the	Alba	Production	Sharing	Contract	and	an	additional	net	9.0	percent	interest	in	the	onshore	liquefied petroleum	gas	processing	plant.	Globex	also	held	oil	and	gas	interests	offshore	Australia,	which	were	sold	on	October	28,	2003.	Results	of	operations include	the	results	of	the	interests	acquired	from	Globex	from	June	20,	2002.

								The	CMS	and	Globex	allocations	of	purchase	price	are	final.	The	goodwill	arising	from	the	allocations	was	$175	million,	which	was	assigned	to	the E&P	segment.	Significant	factors	that	resulted	in	the	recognition	of	goodwill	include:	the	ability	to	acquire	an	established	business	with	an	assembled workforce	and	a	proven	track	record	and	a	strategic	acquisition	in	a	core	geographic	area.

								Additionally,	the	purchase	price	allocated	to	equity	method	investments	was	$224	million	higher	than	the	underlying	net	assets	of	the	investees.	This excess	will	be	amortized	over	the	expected	useful	life	of	the	underlying	assets	except	for	$81	million	of	goodwill	relating	to	equity	method	investments.

# 6.	Discontinued	Operations

On	October	1,	2003,	Marathon	sold	its	exploration	and	production	operations	in	western	Canada	for	$612	million.	This	divestiture	decision	was	made	as part	of	Marathon's	strategic	plan	to	rationalize	noncore	oil	and	gas	properties.	The	results	of	these	operations	have	been	reported	separately	as discontinued	operations	in	Marathon's	Consolidated	Statement	of	Income.	The	sale	resulted	in	a	gain	of	$278	million,	including	a	tax	benefit	of $8	million,	which	has	been	reported	in	discontinued	operations.	Revenues	applicable	to	the	discontinued	operations	totaled	$188	million	and $165	million	for	2003	and	2002.	Pretax	income	or	loss	from	discontinued	operations	was	income	of	$66	million	for	2003	and	a	loss	of	$4	million	for 2002.	During	2004,	the	final	working	capital	adjustment	was	determined,	which	resulted	in	an	additional	gain	of	$4	million	and	is	reported	in discontinued	operations.

# 7.	Income	Per	Common	Share

|  | Basic | Diluted | Basic | Diluted | Basic | Diluted |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Income\tfrom\tcontinuing\toperations | $1,257 | $1,257 | $1,012 | $1,012 | $507 | $507 |
| Income\t(loss)\tfrom\tdiscontinued\toperations | 4 | 4 | 305 | 305 | (4) | (4) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | – | 4 | 4 | 13 | 13 |
| Net\tincome | $1,261 | $1,261 | $1,321 | $1,321 | $516 | $516 |
| Shares\tof\tcommon\tstock\toutstanding\t(thousands): |  |  |  |  |  |  |
| Average\tnumber\tof\tcommon\tshares\toutstanding | 336,485 | 336,485 | 310,129 | 310,129 | 309,792 | 309,792 |
| Effect\tof\tdilutive\tsecurities\t–\tstock\toptions | – | 1,768 | – | 197 | – | 159 |
| Average\tcommon\tshares\tincluding\tdilutive\teffect | 336,485 | 338,253 | 310,129 | 310,326 | 309,792 | 309,951 |
| Per\tshare: |  |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $3.74 | $3.72 | $3.26 | $3.26 | $1.63 | $1.63 |
| Income\t(loss)\tfrom\tdiscontinued\toperations | $.01 | $.01 | $.99 | $.99 | $(.01) $ | (.01) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | $– | $– | $.01 | $.01 | $.04 | $.04 |
| Net\tincome | $3.75 | $3.73 | $4.26 | $4.26 | $1.66 | $1.66 |

# 8.	Segment	Information

								Revenues	by	product	line	were:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Refined\tproducts | $29,780 | $24,092 | $19,729 |
| Merchandise | 2,489 | 2,395 | 2,521 |
| Liquid\thydrocarbons | 13,860 | 10,500 | 6,517 |
| Natural\tgas | 3,266 | 3,796 | 2,362 |
| Transportation\tand\tother\tproducts | 203 | 180 | 166 |
| Total | $49,598 | $40,963 | $31,295 |

Matching	buy/sell	transactions	settled	in	cash	by	product	line	were:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Refined\tproducts | $1,226 | $826 | $771 |
| Liquid\thydrocarbons | 7,938 | 6,332 | 3,709 |
| Total | $9,164 | $7,158 | $4,480 |

# The	following	represents	information	by	operating	segment:

| (In	millions) | Exploration<br>and<br>Production | Refining,<br>Marketing	and<br>Transportation | Integrated<br>Gas | Total |
| :--- | :--- | :--- | :--- | :--- |
| 2004 |  |  |  |  |
| Revenues: |  |  |  |  |
| Customer | $4,519 | $42,435 | $1,593 | $48,547 |
| (a)\nIntersegment | 370 | 152 | 146 | 668 |
| Related\tparties | 8 | 1,043 | – | 1,051 |
| Total\trevenues | $4,897 | $43,630 | $1,739 | $50,266 |
| Segment\tincome | $1,696 | $1,406 | $48 | $3,150 |
| Income\tfrom\tequity\tmethod\tinvestments | 20 | 81 | 69 | 170 |
| (b)\nDepreciation,\tdepletion\tand\tamortization | 750 | 416 | 8 | 1,174 |
| (c)\nImpairments | – | – | – | – |
| (d)\nCapital\texpenditures | 944 | 784 | 490 | 2,218 |
| 2003 |  |  |  |  |
| Revenues: |  |  |  |  |
| Customer | $4,394 | $33,508 | $2,140 | $40,042 |
| (a)\nIntersegment | 405 | 97 | 108 | 610 |
| Related\tparties | 12 | 909 | – | 921 |
| Total\trevenues | $4,811 | $34,514 | $2,248 | $41,573 |
| Segment\tincome | $1,580 | $819 | $(3) | $2,396 |
| (e)\nIncome\tfrom\tequity\tmethod\tinvestments | 50 | 82 | 21 | 153 |
| (b)\nDepreciation,\tdepletion\tand\tamortization | 724 | 375 | 12 | 1,111 |
| (c)\nImpairments | 3 | – | – | 3 |
| (d)\nCapital\texpenditures | 973 | 772 | 131 | 1,876 |
| 2002 |  |  |  |  |
| Revenues: |  |  |  |  |
| Customer | $3,894 | $25,384 | $1,148 | $30,426 |
| (a)\nIntersegment | 583 | 146 | 69 | 798 |
| Related\tparties | – | 869 | – | 869 |
| Total\trevenues | $4,477 | $26,399 | $1,217 | $32,093 |
| Segment\tincome | $1,059 | $372 | $23 | $1,454 |
| Income\tfrom\tequity\tmethod\tinvestments | 75 | 48 | 14 | 137 |
| (b)\nDepreciation,\tdepletion\tand\tamortization | 744 | 364 | 3 | 1,111 |
| (c)\nImpairments | 13 | – | – | 13 |
| (d)\nCapital\texpenditures | 820 | 621 | 48 | 1,489 |

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

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

(c) Excludes	impairments	of	unproved	oil	and	gas	properties	and	$12	million	of	proved	property	impairments	not	allocated	to	the	E&P	segment	in	2004.

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

(e) Excludes	a	$124	million	loss	on	the	dissolution	of	MKM	Partners	L.P.,	which	was	not	allocated	to	segments.	See	Note	13.

The	following	reconciles	segment	income	to	income	from	operations	as	reported	in	Marathon's	consolidated	statement	of	income:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Segment\tincome | $3,150 | $2,396 | $1,454 |
| Items\tnot\tallocated\tto\tsegments: |  |  |  |
| Administrative\texpenses | (307) | (227) | (194) |
| Gains\t(losses)\ton\tU.K.\tlong-term\tgas\tcontracts | (99) | (66) | 18 |
| Impairment\tof\tcertain\toil\tand\tgas\tproperties | (44) | – | – |
| Corporate\tinsurance\tadjustment | (32) | – | – |
| Gain\ton\tasset\tdisposition | – | 106 | 24 |
| Loss\ton\tdissolution\tof\tMKM\tPartners\tL.P. | – | (124) | – |
| Gain\t(loss)\ton\townership\tchanges\tin\tsubsidiaries | 2 | (1) | 12 |
| Contract\tsettlement | – | – | (15) |
| Inventory\tmarket\tvaluation\tadjustments | – | – | 71 |
| Total\tincome\tfrom\toperations | $2,670 | $2,084 | $1,370 |

								The	information	below	summarizes	the	operations	in	different	geographic	areas.	Transfers	between	geographic	areas	are	at	prices	that	approximate market.

| (In	millions) | Year | Within	Geographic<br>Areas | Between<br>Geographic	Areas | Total | Assets^(a) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| United\tStates | 2004 | $47,284 | $– | $47,284 | $8,396 |
|  | 2003 | 39,377 | – | 39,377 | 8,061 |
|  | 2002 | 29,930 | – | 29,930 | 7,904 |
| Canada | 2004 | 698 | 1,678 | 2,376 | 23 |
|  | 2003 | 413 | 1,218 | 1,631 | 24 |
|  | 2002 | 265 | 917 | 1,182 | 485 |
| United\tKingdom | 2004 | 995 | – | 995 | 1,076 |
|  | 2003 | 849 | – | 849 | 1,215 |
|  | 2002 | 916 | – | 916 | 1,316 |
| Equatorial\tGuinea | 2004 | 312 | – | 312 | 2,444 |
|  | 2003 | 119 | – | 119 | 1,656 |
|  | 2002 | 82 | – | 82 | 1,018 |
| Other\tForeign\tCountries | 2004 | 309 | 190 | 499 | 1,208 |
|  | 2003 | 205 | 134 | 339 | 1,049 |
|  | 2002 | 102 | 153 | 255 | 1,144 |
| Eliminations | 2004 | – | (1,868) | (1,868) | – |
|  | 2003 | – | (1,352) | (1,352) | – |
|  | 2002 | – | (1,070) | (1,070) | – |
| Total | 2004 | $49,598 | – | $49,598 | $13,147 |
|  | 2003 | 40,963 | – | 40,963 | 12,005 |
|  | 2002 | 31,295 | – | 31,295 | 11,867 |

(a) Includes	property,	plant	and	equipment	and	investments.

# 9.	Other	Items

# 										Net	interest	and	other	financing	costs

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Interest\tand\tother\tfinancial\tincome: |  |  |  |
| Interest\tincome | $45 | $16 | $10 |
| Income\tfrom\tinterest\trate\tswaps | 24 | 23 | 2 |
| Foreign\tcurrency\tadjustments | 9 | 13 | 8 |
| Total | 78 | 52 | 20 |
| Interest\tand\tother\tfinancing\tcosts: |  |  |  |
| (a)\nInterest\tincurred | 262 | 282 | 288 |
| Less\tinterest\tcapitalized | 48 | 41 | 16 |
| Net\tinterest\texpense | 214 | 241 | 272 |
| Interest\ton\ttax\tissues | 12 | (13) | 9 |
| Other | 13 | 10 | 7 |
| Total | 239 | 238 | 288 |
| Net\tinterest\tand\tother\tfinancing\tcosts | $161 | $186 | $268 |

# 										Foreign	currency	transactions

								Aggregate	foreign	currency	gains	(losses)	were	included	in	the	income	statement	as	follows:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Net\tinterest\tand\tother\tfinancing\tcosts | $9 | $13 | $8 |
| Provision\tfor\tincome\ttaxes | (15) | (15) | (10) |
| Aggregate\tforeign\tcurrency\tgains\t(losses) | $(6) | $(2) | $(2) |

# 10.	Income	Taxes

# Provisions	(credits)	for	income	taxes	were:

|  | Current | Deferred | Total | Current | Deferred | Total | Current | Deferred | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Federal | \t$473\t$ | (22)$ | 451\t$ | 280\t$ | 95\t$ | 375\t$ | 105\t$ | (26)$ | 79 |
| State\tand\tlocal | 47 | 1 | 48 | 56 | (4) | 52 | 21 | 33 | 54 |
| Foreign | 280 | (52) | 228 | 177 | (20) | 157 | 166 | 70 | 236 |
| Total | \t$800\t$ | (73)$ | 727\t$ | 513\t$ | 71\t$ | 584\t$ | 292\t$ | 77\t$ | 369 |

								A	reconciliation	of	federal	statutory	tax	rate	(35	percent)	to	total	provisions	follows:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Statutory\trate\tapplied\tto\tincome\tbefore\tincome\ttaxes | $694 | $559 | $307 |
| Effects\tof\tforeign\toperations:\n(a)\nRemeasurement\tof\tdeferred\ttaxes\tdue\tto\tlegislated\tchanges | – | – | 61 |
| All\tother,\tincluding\tforeign\ttax\tcredits | 26 | (7) | (12) |
| State\tand\tlocal\tincome\ttaxes\tafter\tfederal\tincome\ttax\teffects | 32 | 35 | 34 |
| Credits\tother\tthan\tforeign\ttax\tcredits | (2) | (6) | (11) |
| Effects\tof\tpartially\towned\tcompanies | (3) | (6) | (6) |
| Adjustment\tof\tprior\tyears'\tfederal\tincome\ttaxes | (11) | 17 | (1) |
| Other | (9) | (8) | (3) |
| Total\tprovisions | $727 | $584 | $369 |

(a) Represents	a	one-time	deferred	tax	charge	as	a	result	of	the	enactment	of	a	supplemental	tax	in	the	United	Kingdom.

								Deferred	tax	assets	and	liabilities	resulted	from	the	following:

|  | December	31 | 2004 | 2003 |
| :--- | :--- | :--- | :--- |
| Deferred\ttax\tassets: |  |  |  |
| Net\toperating\tloss\tcarryforwards\t(expiring\tin\t2023) |  | $2 | $– |
| Capital\tloss\tcarryforwards\t(expiring\tin\t2008) |  | 57 | 67 |
| State\ttax\tloss\tcarryforwards\t(expiring\tin\t2005\tthrough\t2021) |  | 122 | 131 |
| (a) |  |  |  |
| Foreign\ttax\tloss\tcarryforwards |  | 581 | 479 |
| Expected\tfederal\tbenefit\tfor: |  |  |  |
| Crediting\tcertain\tforeign\tdeferred\tincome\ttaxes |  | 292 | 331 |
| Deducting\tstate\tand\tforeign\tdeferred\tincome\ttaxes |  | 36 | 45 |
| Employee\tbenefits |  | 341 | 301 |
| Contingencies\tand\tother\taccruals |  | 201 | 180 |
| Investments\tin\tsubsidiaries\tand\tequity\tinvestees |  | 65 | 68 |
| Other |  | 156 | 130 |
| (b) |  |  |  |
| Valuation\tallowances\n: |  |  |  |
| Federal |  | (57) | (67) |
| State |  | (71) | (73) |
| (c) |  |  |  |
| Foreign |  | (365) | (283) |
| (d) |  |  |  |
| Total\tdeferred\ttax\tassets |  | 1,360 | 1,309 |
| Deferred\ttax\tliabilities: |  |  |  |
| (c) |  |  |  |
| Property,\tplant\tand\tequipment |  | 2,192 | 2,168 |
| Inventory |  | 315 | 317 |
| Prepaid\tpensions |  | 72 | 96 |
| Other |  | 147 | 145 |
| Total\tdeferred\ttax\tliabilities |  | 2,726 | 2,726 |
| Net\tdeferred\ttax\tliabilities |  | $1,366 | $1,417 |

(a) For	2004,	includes	$534	million	for	Norway	which	has	no	expiration	date.	The	remainder	expire	2005	through	2019.

(b) Valuation	allowances	related	to	deferred	federal	tax	assets	are	associated	with	capital	loss	carryforwards.	The	remaining	valuation	allowances	are	primarily	associated	with	net	operating	loss	carryforwards	in several	state	jurisdictions,	Norway,	and	several	other	foreign	jurisdictions.

(c) A	revision	was	made	to	the	deferred	tax	liability	for	property,	plant	and	equipment	and	valuation	allowance	for	Norway	at	December	31,	2003.	The	revision	increased	the	deferred	tax	liability	by	$153	million and	decreased	the	valuation	allowance	by	the	same	amount.	The	revision	had	no	impact	on	income,	financial	position	or	cash	flow.

(d) Marathon	expects	to	generate	sufficient	future	taxable	income	to	realize	the	benefit	of	the	deferred	tax	assets.	In	addition,	the	ability	to	realize	the	benefit	of	foreign	tax	credits	is	based	on	certain	assumptions concerning	future	operating	conditions	(particularly	as	related	to	prevailing	oil	prices),	income	generated	from	foreign	sources	and	Marathon's	tax	profile	in	the	years	that	such	credits	may	be	claimed.

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

|  | December	31 | 2004 | 2003 |
| :--- | :--- | :--- | :--- |
| Assets: |  |  |  |
| Other\tcurrent\tassets |  | $127 | $37 |
| Other\tnoncurrent\tassets |  | 60 | 35 |
| Liabilities: |  |  |  |
| Deferred\tincome\ttaxes |  | 1,553 | 1,489 |
| Net\tdeferred\ttax\tliabilities |  | $1,366 | $1,417 |

								The	consolidated	tax	returns	of	Marathon	for	the	years	1998	through	2003	are	under	various	stages	of	audit	and	administrative	review	by	the	IRS. Marathon	believes	it	has	made	adequate	provision	for	income	taxes	and	interest	which	may	become	payable	for	years	not	yet	settled.

								Pretax	income	from	continuing	operations	included	amounts	attributable	to	foreign	sources	of	$534	million	in	2004,	$453	million	in	2003	and $372	million	in	2002.

								Undistributed	income	of	certain	consolidated	foreign	subsidiaries	at	December	31,	2004,	amounted	to	$687	million.	No	provision	for	deferred	U.S. income	taxes	has	been	made	for	these	subsidiaries	because	Marathon	intends	to	permanently	reinvest	such	income	in	those	foreign	operations.	If	such income	were	not	permanently	reinvested,	a	deferred	tax	liability	of	$241	million	would	have	been	required.

								See	Note	3	for	a	discussion	of	the	Tax	Sharing	Agreement	between	Marathon	and	United	States	Steel.

# 11.	Business	Transformation

During	2003,	Marathon	implemented	an	organizational	realignment	plan	that	included	streamlining	Marathon's	business	processes	and	services, realigning	reporting	relationships	to	reduce	costs	across	all	organizations,	consolidating	organizations	in	Houston	and	reducing	the	workforce.	During 2004,	Marathon	entered	into	two	outsourcing	agreements	to	achieve	further	business	process	improvements	and	cost	reductions.

								During	2004	and	2003,	Marathon	recorded	$43	million	and	$24	million	of	costs	as	general	and	administrative	expenses	related	to	these	business transformation	programs.	These	charges	included	employee	severance	and	benefit	costs	related	to	the	elimination	of	approximately	700	regular	employee positions,	relocation	costs,	net	benefit	plans	settlement	and	curtailment	losses	and	fixed	asset	related	costs.

								The	following	table	sets	forth	the	significant	components	and	activity	in	the	business	transformation	programs	during	2004	and	2003.

| (In	millions) | Accrued<br>January	1 | Expense | Noncash<br>Charges	(Gains) | Cash<br>Payments | Accrued<br>December	31 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 |  |  |  |  |  |
| Employee\tseverance\tand\ttermination\tbenefits | $12 | $15 | $– | $24 | $3 |
| Net\tbenefit\tplans\tsettlement\tand\tcurtailment\tlosses | – | 20 | 20 | – | – |
| Relocation\tcosts | 5 | 8 | – | 11 | 2 |
| Fixed\tasset\trelated\tcosts | 1 | – | – | 1 | – |
| Total | $18 | $43 | $20 | $36 | $5 |
| 2003 |  |  |  |  |  |
| Employee\tseverance\tand\ttermination\tbenefits | $– | $25 | $– | $13 | $12 |
| Net\tbenefit\tplans\tsettlement\tand\tcurtailment\tgains | – | (10) | (10) | – | – |
| Relocation\tcosts | – | 5 | – | – | 5 |
| Fixed\tasset\trelated\tcosts | – | 4 | 2 | 1 | 1 |
| Total | $– | $24 | $(8) | $14 | $18 |

								No	additional	significant	charges	are	expected	to	be	incurred	in	2005.

# 12.	Inventories

|  | December	31 | 2004 | 2003 |
| :--- | :--- | :--- | :--- |
| Liquid\thydrocarbons\tand\tnatural\tgas |  | $676 | $674 |
| Refined\tproducts\tand\tmerchandise |  | 1,192 | 1,151 |
| Supplies\tand\tsundry\titems |  | 127 | 130 |
| Total |  | $1,995 | $1,955 |

								The	LIFO	method	accounted	for	92	percent	and	91	percent	of	total	inventory	value	at	December	31,	2004	and	2003.	Current	acquisition	costs	were estimated	to	exceed	the	LIFO	inventory	values	at	December	31,	2004	and	2003,	by	approximately	$1,294	million	and	$655	million.	Cost	of	revenues	was reduced	and	income	from	operations	was	increased	by	$4	million	in	2004,	$11	million	in	2003,	and	less	than	$1	million	in	2002	as	a	result	of	liquidations of	LIFO	inventories.

# 13.	Investments	and	Long-Term	Receivables

|  | December	31 | 2004 | 2003 |
| :--- | :--- | :--- | :--- |
| Equity\tmethod\tinvestments: |  |  |  |
| Alba\tPlant\tLLC |  | $432 | $277 |
| Atlantic\tMethanol\tProduction\tCompany,\tLLC |  | 265 | 263 |
| Pilot\tTravel\tCenters\tLLC |  | 372 | 373 |
| Other |  | 265 | 259 |
| Other\tinvestments |  | 3 | 3 |
| Recoverable\tenvironmental\tcosts\treceivable |  | 52 | 81 |
| Value-added\ttax\trefunds\treceivable |  | 32 | 13 |
| Fair\tvalue\tof\tderivative\tassets |  | 24 | 34 |
| Deposits\tof\trestricted\tcash |  | 89 | 5 |
| Other\treceivables |  | 12 | 15 |
| Total |  | $1,546 | $1,323 |

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Income\tdata\t–\tyear: |  |  |  |
| Revenues\tand\tother\tincome | $7,419 | $7,036 | $5,541 |
| Operating\tincome | 434 | 435 | 329 |
| Net\tincome | 330 | 319 | 264 |
| Balance\tsheet\tdata\t–\tDecember\t31: |  |  |  |
| Current\tassets | $583 | $619 |  |
| Noncurrent\tassets | 3,990 | 3,727 |  |
| Current\tliabilities | 569 | 641 |  |
| Noncurrent\tliabilities | 1,511 | 1,172 |  |

								Marathon's	carrying	value	of	its	equity	method	investments	is	$258	million	higher	than	the	underlying	net	assets	of	investees.	This	basis	difference is	being	amortized	into	income	over	the	remaining	useful	lives	of	the	underlying	net	assets.

								Dividends	and	partnership	distributions	received	from	equity	investees	(excluding	distributions	that	represented	a	return	of	capital	previously contributed)	were	$127	million	in	2004,	$175	million	in	2003	and	$109	million	in	2002.

								On	June	30,	2003,	Marathon	Oil	Corporation	and	Kinder	Morgan	Energy	Partners,	L.P.	("Kinder	Morgan")	dissolved	MKM	Partners	L.P.	which had	oil	and	gas	production	operations	in	the	Permian	Basin	of	Texas.	Marathon	held	an	85	percent	noncontrolling	interest	in	the	partnership.	Prior	to	the dissolution	of	the	partnership,	Kinder	Morgan	acquired	MKM	Partners	L.P.'s	12.75	percent	interest	in	the	SACROC	unit	for	an	undisclosed	amount.	The partnership	recorded	a	loss	on	the	disposal	of	SACROC	of	$19	million,	of	which	Marathon's	share	was	$17	million.	Also	prior	to	the	dissolution, Marathon	recorded	a	$107	million	impairment	of	its	investment	in	MKM	Partners	L.P.	due	to	an	other-than-temporary	decline	in	the	fair	value	of	the investment.	The	total	loss	recognized	by	Marathon	related	to	the	dissolution	of	MKM	Partners	L.P.	was	$124	million.	The	partnership's	interest	in	the Yates	field	was	distributed	to	Marathon	and	Kinder	Morgan	on	dissolution.

# 14.	Property,	Plant	and	Equipment

|  | December	31 | 2004 | 2003 |
| :--- | :--- | :--- | :--- |
| Production |  | $15,162 | $14,267 |
| Refining |  | 4,398 | 3,822 |
| Marketing |  | 1,954 | 1,926 |
| Transportation |  | 1,816 | 1,760 |
| Gas\tprocessing |  | 524 | 52 |
| Other |  | 382 | 366 |
| Total |  | 24,236 | 22,193 |
| Less\taccumulated\tdepreciation,\tdepletion\tand\tamortization |  | 12,426 | 11,363 |
| Net |  | $11,810 | $10,830 |

								Property,	plant	and	equipment	includes	gross	assets	acquired	under	capital	leases	of	$49	million	at	December	31,	2004	and	2003,	with	related amounts	in	accumulated	depreciation,	depletion	and	amortization	of	$6	million	and	$2	million	at	December	31,	2004	and	2003.

								On	November	3,	2003,	Marathon	sold	its	42.45	percent	interest	in	the	Yates	field	and	its	100	percent	interest	in	the	Yates	gathering	system	to	Kinder Morgan	for	$229	million	and	recognized	a	loss	of	$8	million.	This	divestiture	decision

was	made	as	part	of	Marathon's	strategic	plan	to	rationalize	noncore	oil	and	gas	properties.	The	Yates	field	and	gathering	system	consisted	of	assets	of $240	million	of	property,	plant	and	equipment	and	asset	retirement	obligations	of	$3	million.

								During	2002,	Marathon	acquired	additional	interests	in	coalbed	natural	gas	assets	in	the	Powder	River	Basin	of	northern	Wyoming	and	southern Montana	from	XTO	Energy,	Inc.	("XTO")	in	exchange	for	certain	oil	and	gas	properties	in	eastern	Texas	and	northern	Louisiana.	Additionally, 100	million	cubic	feet	per	day	of	long-term	gas	transportation	capacity	was	released	to	Marathon	by	the	original	owner	of	the	Powder	River	Basin interests.	On	July	1,	2002,	Marathon	completed	this	transaction	by	selling	its	production	interests	in	the	San	Juan	Basin	of	New	Mexico	to	XTO	for $42	million.	Marathon	recognized	a	gain	of	$24	million	in	2002	related	to	this	transaction.

# 15.	Goodwill

The	changes	in	the	carrying	amount	of	goodwill	for	the	years	ended	December	31,	2004	and	2003,	are	as	follows:

| (In	millions) | Exploration<br>and<br>Production | Refining,	Marketing<br>and<br>Transportation | Total |
| :--- | :--- | :--- | :--- |
| Balance\tas\tof\tJanuary\t1,\t2003 | $253 | $21 | $274 |
| Purchase\tprice\tadjustment | (7) | – | (7) |
| Goodwill\tallocated\tto\tsale\tof\twestern\tCanada\toperations | (15) | – | (15) |
| Balance\tas\tof\tDecember\t31,\t2003 | 231 | 21 | 252 |
| Current\tyear\tactivity | – | – | – |
| Balance\tas\tof\tDecember\t31,\t2004 | $231 | $21 | $252 |

								The	E&P	segment	tests	for	impairment	in	the	second	quarter	of	each	year.	The	RM&T	segment	tests	for	impairment	in	the	fourth	quarter	of	each year.	No	impairment	in	the	carrying	value	has	been	deemed	necessary.

# 16.	Intangible	Assets

Intangible	assets	are	as	follows:

| (In	millions)																		December	31 | Gross	Carrying<br>Amount | Accumulated<br>Amortization | Net	Carrying<br>Amount |
| :--- | :--- | :--- | :--- |
| 2004 |  |  |  |
| Amortized\tintangible\tassets: |  |  |  |
| Branding\tagreements | $53 | $19 | $34 |
| Elba\tIsland\tdelivery\trights | 42 | 5 | 37 |
| Other | 39 | 27 | 12 |
| Total | $134 | $51 | $83 |
| Unamortized\tintangible\tassets: |  |  |  |
| Unrecognized\tprior\tservice\tcosts | $20 | $– | $20 |
| Other | 5 | – | 5 |
| Total | $25 | $– | $25 |
| 2003 |  |  |  |
| Amortized\tintangible\tassets: |  |  |  |
| Branding\tagreements | $53 | $19 | $34 |
| Elba\tIsland\tdelivery\trights | 42 | 2 | 40 |
| Other | 40 | 23 | 17 |
| Total | $135 | $44 | $91 |
| Unamortized\tintangible\tassets: |  |  |  |
| Unrecognized\tprior\tservice\tcosts | $23 | $– | $23 |
| Other | 4 | – | 4 |
| Total | $27 | $– | $27 |

The	following	table	sets	forth	quantitative	information	by	category	of	derivative	instrument	at	December	31,	2004	and	2003.	These	amounts	are	reported on	a	gross	basis	by	individual	derivative	instrument.	The	amounts	exclude	the	variable	margin	deposit	balances	held	in	various	brokerage	accounts.

|  |  | December	31 | Assets^(a) | (Liabilities)^(a) | Assets^(a) | (Liabilities)^(a) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Commodity\tInstruments |  |  |  |  |  |  |
| Fair\tvalue\thedges\n: | (b) |  |  |  |  |  |
| Exchange\ttraded\tcommodity\tfutures | Exchange\ttraded\tcommodity\tfutures |  | $2 | $(1) | $–\t\t\t $– | $–\t\t\t $– |
| OTC\tcommodity\tswaps | OTC\tcommodity\tswaps |  | 27 | – | 17 | (1) |
| Cash\tflow\thedges\n: | (c) |  |  |  |  |  |
| OTC\tcommodity\tswaps | OTC\tcommodity\tswaps |  | $– | $– | $3 | $(9) |
| OTC\tcommodity\toptions | OTC\tcommodity\toptions |  | – | – | 2 | (23) |
| Non-hedge\tdesignation: |  |  |  |  |  |  |
| Exchange-traded\tcommodity\tfutures | Exchange-traded\tcommodity\tfutures |  | $222 | $(210) | $94 | $(98) |
| Exchange-traded\tcommodity\toptions | Exchange-traded\tcommodity\toptions |  | 79 | (65) | 5 | (11) |
| OTC\tcommodity\tswaps | OTC\tcommodity\tswaps |  | 101 | (61) | 61 | (38) |
| OTC\tcommodity\toptions | OTC\tcommodity\toptions |  | 5 | (4) | 5 | (4) |
| Nontraditional\tInstruments |  |  |  |  |  |  |
| United\tKingdom\tlong-term\tnatural\tgas | United\tKingdom\tlong-term\tnatural\tgas |  |  |  |  |  |
| contracts | (d) |  | $– | $(127) | $– | $(29) |
|  | (e) |  |  |  |  |  |
| Physical\tcommodity\tcontracts | Physical\tcommodity\tcontracts |  | 86 | (91) | 70 | (61) |
| Financial\tInstruments |  |  |  |  |  |  |
| Fair\tvalue\thedges: |  |  |  |  |  |  |
|  | (f) |  |  |  |  |  |
| OTC\tinterest\trate\tswaps | OTC\tinterest\trate\tswaps |  | 2 | (12) | $11 | $(7) |
| Cash\tflow\thedges\n: | (c) |  |  |  |  |  |
| OTC\tforeign\tcurrency\tswaps | OTC\tforeign\tcurrency\tswaps |  | $10 | $(1) | $– | $– |

(a) The	fair	value	and	carrying	value	of	derivative	instruments	are	the	same.	The	fair	value	amounts	for	OTC	positions	are	determined	using	option-pricing	models	or	dealer	quotes.	The	fair	values	of	exchange- traded	positions	are	based	on	market	quotes	derived	from	major	exchanges.	The	fair	value	of	interest	rate	and	foreign	currency	swaps	is	based	on	dealer	quotes.	Marathon's	consolidated	balance	sheet	is	reported on	a	net	asset/(liability)	basis	by	brokerage	firm,	as	permitted	by	the	master	netting	agreements.

(b) There	was	no	ineffectiveness	associated	with	fair	value	hedges	for	2004	or	2003	because	the	hedging	instrument	and	the	existing	firm	commitment	contracts	are	priced	on	the	same	underlying	index.	Certain derivative	instruments	used	in	the	fair	value	hedges	mature	between	2005	and	2008.

(c) The	ineffective	portion	of	changes	in	the	fair	value	for	cash	flow	hedges,	on	a	before	tax	basis,	during	2004	and	2003	was	$1	million	and	less	than	$1	million.	In	addition,	during	2004	and	2003,	losses	of $3	million	and	$8	million	were	recognized	in	revenues	as	the	result	of	a	discontinuation	of	a	portion	of	a	cash	flow	hedge	related	to	natural	gas	and	crude	oil	production.	Of	the	$12	million	recorded	in	OCI	as	of December	31,	2004,	$2	million	is	expected	to	be	reclassified	to	income	in	2005.

(d) The	contract	price	under	the	U.K.	long-term	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	gas	strip	price	to	the	expected	sales	volumes	under	these	contracts	for	the	next	eighteen	months.	The eighteen-month	period	represents	approximately	ninety	percent	of	market	liquidity	in	that	region.

(e) Certain	physical	commodity	contracts	are	classified	as	nontraditional	derivative	instruments	because	certain	volumes	covered	by	these	contracts	are	physically	netted	at	particular	delivery	locations. Additionally,	other	physical	contracts	that	involve	flash	title	are	accounted	for	as	nontraditional	derivative	instruments.

(f) The	fair	value	of	OTC	interest	rate	swaps	exclude	accrued	interest	amounts	not	yet	settled.	As	of	December	31,	2004	and	2003,	accrued	interest	approximated	$4	million	and	$7	million.	The	net	fair	value	of	the OTC	interest	rate	swaps	as	of	December	31,	2004	and	2003	of	a	$10	million	loss	and	a	$4	million	gain,	is	included	in	long-term	debt	(see	Note	20).

# 18.	Fair	Value	of	Financial	Instruments

Fair	value	of	the	financial	instruments	disclosed	herein	is	not	necessarily	representative	of	the	amount	that	could	be	realized	or	settled,	nor	does	the	fair value	amount	consider	the	tax	consequences	of	realization	or	settlement.	The	following	table	summarizes	financial	instruments,	excluding	derivative financial	instruments	disclosed	in	Note	17,	by	individual	balance	sheet	account.	Marathon's	financial	instruments	at	December	31,	2004	and	2003	were:

| (In	millions) | December	31 | Fair<br>Value | Carrying<br>Amount | Fair<br>Value | Carrying<br>Amount |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Financial\tassets: |  |  |  |  |  |
| Cash\tand\tcash\tequivalents |  | $3,369 | $3,369 | $1,396 | $1,396 |
| Receivables |  | 3,220 | 3,220 | 2,510 | 2,510 |
| Receivables\tfrom\tUnited\tStates\tSteel |  | 590 | 602 | 549 | 613 |
| Investments\tand\tlong-term\treceivables |  | 266 | 188 | 186 | 117 |
| Total\tfinancial\tassets |  | $7,445 | $7,379 | $4,641 | $4,636 |
| Financial\tliabilities: |  |  |  |  |  |
| Accounts\tpayable |  | $4,474 | $4,474 | $3,369 | $3,369 |
| Payables\tto\tUnited\tStates\tSteel |  | 5 | 5 | 12 | 12 |
| Accrued\tinterest |  | 92 | 92 | 85 | 85 |
| Long-term\tdebt\t(including\tamounts\tdue\twithin\tone\tyear) |  | 4,480 | 3,925 | 4,740 | 4,181 |
| Total\tfinancial\tliabilities |  | $9,051 | $8,496 | $8,206 | $7,647 |

								Fair	value	of	financial	instruments	classified	as	current	assets	or	liabilities	approximates	carrying	value	due	to	the	short-term	maturity	of	the instruments.	Fair	value	of	investments	and	long-term	receivables	was	based	on	discounted	cash	flows	or	other	specific	instrument	analysis.	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.	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

Certain	banks	provide	Marathon	with	uncommitted	short-term	lines	of	credit	totaling	$200	million	bearing	interest	at	short-term	market	rates	determined at	the	time	of	a	request	for	borrowings.	At	December	31,	2004,	there	were	no	borrowings	against	these	lines	of	credit.

								MAP	has	a	$190	million	revolving	credit	agreement	with	Ashland	that	terminates	in	March	2005,	as	discussed	in	Note	4.	Pursuant	to	the	terms	of Marathon's	agreement	to	acquire	the	38	percent	ownership	interest	in	MAP	currently	held	by	Ashland	(see	Note	29),	MAP	effectively	was	restricted	from borrowing	from	Ashland	under	this	facility	after	September	30,	2004.

# 20.	Long-Term	Debt

|  | December	31 | 2004 | 2003 |
| :--- | :--- | :--- | :--- |
| Marathon\tOil\tCorporation: |  |  |  |
| (a) |  |  |  |
| Revolving\tcredit\tfacility\tdue\t2009 |  | $– | $– |
| (a) |  |  |  |
| Commercial\tpaper |  | – | – |
| 7.200%\tnotes\tdue\t2004 |  | – | 251 |
| 6.650%\tnotes\tdue\t2006 |  | 300 | 300 |
| (b) |  |  |  |
| 5.375%\tnotes\tdue\t2007 |  | 450 | 450 |
| 6.850%\tnotes\tdue\t2008 |  | 400 | 400 |
| (b) |  |  |  |
| 6.125%\tnotes\tdue\t2012 |  | 450 | 450 |
| (b) |  |  |  |
| 6.000%\tnotes\tdue\t2012 |  | 400 | 400 |
| (b) |  |  |  |
| 6.800%\tnotes\tdue\t2032 |  | 550 | 550 |
| 9.375%\tdebentures\tdue\t2012 |  | 163 | 163 |
| 9.125%\tdebentures\tdue\t2013 |  | 271 | 271 |
| 9.375%\tdebentures\tdue\t2022 |  | 81 | 81 |
| 8.500%\tdebentures\tdue\t2023 |  | 123 | 123 |
| 8.125%\tdebentures\tdue\t2023 |  | 229 | 229 |
| (b) |  |  |  |
| 6.570%\tpromissory\tnote\tdue\t2006 |  | 9 | 15 |
| Series\tA\tMedium\tterm\tnotes\tdue\t2022 |  | 3 | 3 |
| 4.750%\t–\t6.875%\tObligations\trelating\tto\tIndustrial\tDevelopment\tand\tEnvironmental |  |  |  |
| (c) |  |  |  |
| Improvement\tBonds\tand\tNotes\tdue\t2009\t–\t2033 |  | 496 | 494 |
| (d) |  |  |  |
| Sale-leaseback\tfinancing\tdue\t2003\t–\t2012 |  | 71 | 76 |
| (e) |  |  |  |
| Capital\tlease\tobligation\tdue\t2012\nConsolidated\tsubsidiaries: |  | 51 | 59 |
| (a) |  |  |  |
| Revolving\tcredit\tfacility\tdue\t2009 |  | – | – |
| All\tother\tobligations,\tincluding\tcapital\tlease\tobligations\tdue\t2005\t–\t2018 |  | 44 | 47 |
| (f)(g) |  |  |  |
| Total |  | 4,091 | 4,362 |
| Unamortized\tdiscount |  | (8) | (9) |
| (h) |  |  |  |
| Fair\tvalue\tadjustments\ton\tnotes\tsubject\tto\thedging |  | (10) | 4 |
| Amounts\tdue\twithin\tone\tyear |  | (16) | (272) |
| Long-term\tdebt\tdue\tafter\tone\tyear |  | $4,057 | $4,085 |

(a) Marathon	has	a	$1.5	billion	5-year	revolving	credit	agreement	and	MAP	has	a	$500	million	5-year	revolving	credit	facility,	both	of	which	terminate	in	May	2009.	Interest	on	these	facilities	is	based	on	defined short-term	market	rates.	During	the	term	of	the	agreements,	Marathon	is	obligated	to	pay	a	variable	facility	fee	on	total	commitments,	which	at	December	31,	2004	was	0.125%.	At	December	31,	2004,	there were	no	borrowings	against	these	facilities.	Commercial	paper	is	supported	by	the	unused	and	available	credit	on	the	Marathon	5-year	facility	and,	accordingly,	is	classified	as	long-term	debt.

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

(c) United	States	Steel	has	assumed	responsibility	for	repayment	of	$472	million	of	these	obligations.

(d) This	sale-leaseback	financing	arrangement	relates	to	a	lease	of	a	slab	caster	at	United	States	Steel's	Fairfield	Works	facility	in	Alabama	with	a	term	through	2012.	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.

(e) This	obligation	relates	to	a	lease	of	equipment	at	United	States	Steel's	Clairton	Works	cokemaking	facility	in	Pennsylvania	with	a	term	through	2012.	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.

(f) Required	payments	of	long-term	debt	for	the	years	2006-2009	are	$315	million,	$474	million,	$417	million	and	$20	million,	respectively.	Of	these	amounts,	payments	assumed	by	United	States	Steel	are $11	million,	$21	million,	$14	million	and	$15	million,	respectively.

(g) In	the	event	of	a	change	in	control	of	Marathon,	as	defined	in	the	related	agreements,	debt	obligations	totaling	$1.579	billion	at	December	31,	2004,	may	be	declared	immediately	due	and	payable.

(h) See	Note	17	for	information	on	interest	rate	swaps.

# 21.	Deferred	Credits	and	Other	Liabilities

# Deferred	credits	and	other	liabilities	included	the	following:

|  | December	31 | 2004 | 2003 |
| :--- | :--- | :--- | :--- |
| Deferred\tcredits: |  |  |  |
| Deferred\trevenue\ton\tgas\tsupply\tcontracts |  | $21 | $27 |
| Deferred\tcredits\ton\tcrude\toil\tcontracts |  | 13 | 30 |
| Deferred\tgain\ton\tformation\tof\tCentennial\tPipeline\tLLC |  | 12 | 12 |
| Other\tdeferred\tcredits |  | 2 | 1 |
| Other\tliabilities: |  |  |  |
| Environmental\tremediation\tliabilities |  | 69 | 82 |
| Liability\tfor\tretrospective\tinsurance\tpremiums |  | 46 | – |
| Accrued\tLNG\tfacility\tcosts |  | 20 | 22 |
| Fair\tvalue\tof\tderivative\tliabilities |  | 76 | 22 |
| Indemnification\tpayable |  | 9 | 9 |
| Guarantees |  | 4 | 4 |
| Other |  | 16 | 18 |
| Total\tdeferred\tcredits\tand\tother\tliabilities |  | $288 | $227 |

# 22.	Supplemental	Cash	Flow	Information

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Net\tcash\tprovided\tfrom\toperating\tactivities\tfrom\tcontinuing\toperations\tincluded: |  |  |  |
| Interest\tand\tother\tfinancing\tcosts\tpaid\t(net\tof\tamount\tcapitalized) | $206 | $254 | $258 |
| Income\ttaxes\tpaid\tto\ttaxing\tauthorities | 674 | 537 | 173 |
| Income\ttax\tsettlements\tpaid\tto\tUnited\tStates\tSteel | 3 | 16 | 7 |
| Commercial\tpaper\tand\trevolving\tcredit\tarrangements\t–\tnet: |  |  |  |
| Commercial\tpaper\t–\tissued | – | $4,733 | $10,669 |
| –\trepayments | – | (4,833) | (10,569) |
| Credit\tagreements\t–\tborrowings | – | 3 | 3,700 |
| –\trepayments | – | (34) | (4,175) |
| Ashland\tcredit\tagreements\t–\tborrowings | 653 | 182 | 266 |
| –\trepayments | (653) | (182) | (266) |
| Total | $– | $(131) | $(375) |
| Noncash\tinvesting\tand\tfinancing\tactivities: |  |  |  |
| Common\tStock\tissued\tfor\temployee\tstock\tplans | $6 | $4 | $9 |
| Asset\tretirement\tcosts\tcapitalized | 66 | 61 | – |
| Liabilities\tassumed\tin\tconnection\twith\tcapital\texpenditures | 1 | 1 | 10 |
| Debt\tpayments\tassumed\tby\tUnited\tStates\tSteel | 13 | 5 | 4 |
| Capital\tlease\tobligations: |  |  |  |
| Asset\tacquired | – | 41 | – |
| Assumed\tby\tUnited\tStates\tSteel | – | 59 | – |
| Disposal\tof\tassets: |  |  |  |
| Exchange\tof\toil\tand\tgas\tproducing\tproperties\tfor\tPowder\tRiver\tbasin\tassets | – | – | 42 |
| Notes\treceived\tin\tasset\tdisposal\ttransactions | – | – | 5 |
| Liabilities\tassumed\tin\tacquisitions: |  |  |  |
| KMOC | – | 107 | – |
| Equatorial\tGuinea\tinterests | – | – | 179 |
| Net\tassets\tcontributed\tto\tjoint\tventures | 3 | 42 | – |
| Joint\tventure\tdissolution | – | 212 | – |
| Liabilities\tassumed\tby\tbuyer\tof\tdiscontinued\toperations | – | 212 | – |

# 23.	Pensions	and	Other	Postretirement	Benefits

The	following	summarizes	the	obligations	and	funded	status	for	those	plans	sponsored	by	Marathon:

|  | U.S. | Int'l | U.S. | Int'l |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Change\tin\tbenefit\tobligations |  |  |  |  |  |  |
| Benefit\tobligations\tat\tJanuary\t1 | $540 | $262 | $455 | $156 | $387 | $433 |
| Service\tcost | 24 | 9 | 23 | 7 | 4 | 6 |
| Interest\tcost | 31 | 14 | 31 | 11 | 22 | 27 |
| Plan\tamendment | – | – | – | – | – | (97) |
| Actuarial\t(gain)\tlosses | 46 | 41 | 64 | 93 | (31)(a) | 52 |
| Net\tsettlements\tand\tcurtailments | (80) | – | 1 | – | (1) | (4) |
| Benefits\tpaid | (14) | (4) | (34) | (5) | (25) | (30) |
| Benefit\tobligations\tat\tDecember\t31 | $547 | $322 | $540 | $262 | $356 | $387 |
| Change\tin\tplan\tassets |  |  |  |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tJanuary\t1 | $463 | $139 | $413 | $104 |  |  |
| Actual\treturn\ton\tplan\tassets | 35 | 27 | 81 | 32 |  |  |
| Employer\tcontribution | 7 | 24 | – | 8 |  |  |
| Settlement\tpayments | (77) | – | – | – |  |  |
| Benefits\tpaid\tfrom\tplan\tassets | (14) | (5) | (31) | (5) |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tDecember\t31 | $414 | $185 | $463 | $139 |  |  |
| (b) |  |  |  |  |  |  |
| Funded\tstatus\tof\tplans\tat\tDecember\t31 | $(133) | $(137) | $(77) | $(123) | $(356) | $(387) |
| Unrecognized\tnet\ttransition\tasset | (2) | – | (4) | – | – | – |
| Unrecognized\tprior\tservice\tcosts\t(benefits) | 15 | – | 20 | – | (65) | (81) |
| Unrecognized\tnet\tlosses | 228 | 127 | 230 | 114 | 122 | 162 |
| Prepaid\t(accrued)\tbenefit\tcost | $108 | $(10) | $169 | $(9) | $(299) | $(306) |
| Amounts\trecognized\tin\tthe\tstatement\tof\tfinancial\tposition: |  |  |  |  |  |  |
| Prepaid\tbenefit\tcost | $128 | $– | $181 | $– | $– | $– |
| Accrued\tbenefit\tliability | (27) | (81) | (21) | (93) | (299) | (306) |
| (c) |  |  |  |  |  |  |
| Accumulated\tother\tcomprehensive\tincome | 7 | 71 | 9 | 84 | – | – |
| Prepaid\t(accrued)\tbenefit\tcost | $108 | $(10) | $169 | $(9) | $(299) | $(306) |

The	accumulated	benefit	obligation	for	all	defined	benefit	pension	plans	was	$660	million	and	$658	million	at	December	31,	2004	and	2003, respectively.	Other	Benefits	in	the	above	table	is	not	applicable	to	Marathon's	foreign	subsidiaries.

(a) Includes	the	impact	related	to	the	Act,	which	reduced	the	obligation	by	$44	million.

(b) Includes	several	plans	that	have	accumulated	benefit	obligations	in	excess	of	plan	assets:

|  | U.S. | Int'l | U.S. | Int'l |
| :--- | :--- | :--- | :--- | :--- |
| Projected\tbenefit\tobligations | $(45) | (322) | $(35) | (262) |
| Accumulated\tbenefit\tobligations | (27) | (265) | (21) | (233) |
| Fair\tvalue\tof\tplan\tassets | – | 185 | – | 139 |

(c) Excludes	income	tax	effects.

								The	following	summarizes	the	obligations	and	funded	status	for	those	plans	sponsored	by	MAP:

|  | 2004 | 2003 | 2004 | 2003 |
| :--- | :--- | :--- | :--- | :--- |
| Change\tin\tbenefit\tobligations |  |  |  |  |
| Benefit\tobligations\tat\tJanuary\t1 | $1,051 | $831 | $346 | $295 |
| Service\tcost | 70 | 64 | 14 | 15 |
| Interest\tcost | 64 | 59 | 20 | 19 |
| Actuarial\t(gain)\tlosses | 114 | 144 | (34)(a) | 21 |
| Settlement\tpayments | (4) | – | – | – |
| Benefits\tpaid | (92) | (47) | (5) | (4) |
| Benefit\tobligations\tat\tDecember\t31 | $1,203 | $1,051 | $341 | $346 |
| Change\tin\tplan\tassets |  |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tJanuary\t1 | $473 | $356 |  |  |
| Actual\treturn\ton\tplan\tassets | 44 | 75 |  |  |
| Employer\tcontribution | 114 | 89 |  |  |
| Settlement\tpayments | (4) | – |  |  |
| Benefits\tpaid\tfrom\tplan\tassets | (92) | (47) |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tDecember\t31 | $535 | $473 |  |  |
| (b) |  |  |  |  |
| Funded\tstatus\tof\tplans\tat\tDecember\t31 | $(668) | $(578) | $(341) | $(346) |
| Unrecognized\tnet\ttransition\tasset | (2) | (3) | – | – |
| Unrecognized\tprior\tservice\tcosts\t(credits) | 18 | 21 | (26) | (33) |
| Unrecognized\tnet\tlosses | 502 | 411 | 61 | 98 |
| Accrued\tbenefit\tcost | $(150) | $(149) | $(306) | $(281) |
| Amounts\trecognized\tin\tthe\tstatement\tof\tfinancial\tposition: |  |  |  |  |
| Accrued\tbenefit\tliability | $(230) | $(248) | $(306) | $(281) |
| Intangible\tasset | 20 | 23 | – | – |
| (c) |  |  |  |  |
| Accumulated\tother\tcomprehensive\tincome | 60 | 76 | – | – |
| Accrued\tbenefit\tcost | $(150) | $(149) | $(306) | $(281) |

								The	accumulated	benefit	obligation	for	all	defined	benefit	pension	plans	was	$763	million	and	$721	million	at	December	31,	2004	and	2003.

(b) All	MAP	plans	have	accumulated	benefit	obligations	in	excess	of	plan	assets:

|  | 2004 | 2003 |
| :--- | :--- | :--- |
| Projected\tbenefit\tobligations | $(1,203) | $(1,051) |
| Accumulated\tbenefit\tobligations | (763) | (721) |
| Fair\tvalue\tof\tplan\tassets | 535 | 473 |

(c) Excludes	the	effects	of	minority	interest	and	income	taxes.

								The	following	information	disclosed	thru	page	F-34	relates	to	the	plans	sponsored	by	Marathon	and	MAP.

|  | U.S. | Int'l | U.S. | Int'l |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Components\tof\tnet\tperiodic\tbenefit\tcost |  |  |  |  |  |  |  |  |
| Service\tcost | $94 | $9 | $87 | $7 | $66 | $18 | $21 | $16 |
| Interest\tcost | 95 | 14 | 90 | 11 | 74 | 42 | 46 | 40 |
| Expected\treturn\ton\tplan\tassets | (84) | (10) | (84) | (7) | (100) | – | – | – |
| Amortization\n–\tnet\ttransition\tgain | (4) | – | (4) | – | (4) | – | – | – |
| –\tprior\tservice\tcosts\t(credits) | 4 | – | 5 | – | 5 | (14) | (10) | (8) |
| –\tactuarial\tloss | 39 | 7 | 32 | 5 | 7 | 11 | 12 | 4 |
| (a) |  |  |  |  |  |  |  |  |
| Multi-employer\tand\tother\tplans | 2 | – | 2 | – | 7 | 3 | 2 | 2 |
| (b) |  |  |  |  |  |  |  |  |
| Settlement,\tcurtailment\tand\ttermination\tlosses\t(gains) | 37 | – | 6 | 1 | – | (9) | (16) | – |
| (c) |  |  |  |  |  |  |  |  |
| Net\tperiodic\tbenefit\tcost | $183 | $20(d) | $134 | $17 | $55 | $51 | $55 | $54 |

(a) International	net	periodic	pension	cost	of	$5	million	for	the	year	ending	2002	was	disclosed	in	the	aggregate	as	other	plans.

(b) Includes	business	transformation	costs.

(d) Excludes	an	additional	$4	million	of	pension	expense	recognized	under	international	minimum	funding	requirements	of	the	1995	Pension	Act.

								Historical	markets	are	studied	and	long-term	historical	relationships	between	equities	and	fixed	income	are	preserved	consistent	with	the	widely accepted	capital	market	principle	that	assets	with	higher	volatility	generate	a	greater	return	over	the	long	run.	Certain	components	of	the	asset	mix	are modeled	with	various	assumptions	regarding	inflation,	debt	returns	and	stock	yields.	Peer	data	and	historical	returns	are	reviewed	to	check	for reasonability	and	appropriateness.

								The	overall	expected	long-term	return	on	plan	assets	is	derived	using	the	expected	returns	on	the	different	asset	classes,	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	stock.	Expected	returns	on	debt	securities	are	taken	directly	at	market	yields	and	cash	is	taken	at	the	local	currency	base	rate.

Assumed	health	care	cost	trend	rates	at	December	31:

|  | 2004 | 2003 |
| :--- | :--- | :--- |
| Health\tcare\tcost\ttrend\trate\tassumed\tfor\tnext\tyear | 9.0% | 9.5% |
| Rate\tto\twhich\tthe\tcost\ttrend\trate\tis\tassumed\tto\tdecline\t(the\tultimate\ttrend\trate) | 5% | 5% |
| Year\tthat\tthe\trate\treaches\tthe\tultimate\ttrend\trate | 2012 | 2012 |

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

| (In	millions) | 1-Percentage-<br>Point	Increase | 1-Percentage<br>Point	Decrease |
| :--- | :--- | :--- |
| Effect\ton\ttotal\tof\tservice\tand\tinterest\tcost\tcomponents | $11 | $(9) |
| Effect\ton\tother\tpostretirement\tbenefit\tobligations | 99 | (85) |

								The	pension	plans	weighted-average	asset	allocations	by	asset	category	are	as	follows:

| Equity	securities | 78% | 73% | 77% | 76% |
| :--- | :--- | :--- | :--- | :--- |
| Debt\tsecurities | 21% | 24% | 22% | 23% |
| Real\testate | 1% | – | 1% | – |
| Other | – | 3% | – | 1% |
| Total | 100% | 100% | 100% | 100% |

								The	investment	policy	reflects	the	funded	status	of	the	plan	and	the	future	ability	of	the	Company	to	make	further	contributions.	Historical performance	results	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	equities	and	25	percent	debt	securities.	Management	of	the	plans'	assets is	delegated	to	the	United	States	Steel	and	Carnegie	Pension	Fund.	The	fund	manager	has	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.	Investment performance	and	risk	is	measured	and	monitored	on	an	ongoing	basis	through	quarterly	investment	meetings	and	periodic	asset	and	liability	studies.

								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	of	approximately	75	percent	equities	and	25	percent	debt	securities	and	the	unitized	pool approach	meets	this	objective	and	controls	the	various	risks	to	which	the	plans	assets	are	exposed,	including	matching	the	timing	of	estimated	future obligations	to	the	maturities	of	the	plans'	assets.	The	day-to-day	management	of	the	plans'	assets	are	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	provides	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.

								Both	MAP	and	Marathon's	foreign	subsidiaries	expect	to	make	contributions	to	their	funded	pension	plans	in	2005	approximating	$127	million	and $31	million,	respectively.	Marathon	is	not	required	to	make	a	cash	contribution	to	its	funded	domestic	pension	plan	in	2005.	Cash	contributions	to	be paid	from	the	general	assets	of	the	company	for	both	the	unfunded	pension	and	postretirement	benefit	plans	are	expected	to	be	approximately	$2	million and	$34	million	in	2005.

								The	following	gross	benefit	payments,	which	reflect	expected	future	service,	as	appropriate,	are	expected	to	be	paid:

|  | MOC | MAP |  | MOC | MAP |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2005 | $28 | $50 | $5 | $26 | $8 |
| 2006 | 29 | 55 | 5 | 26 | 9 |
| 2007 | 33 | 68 | 5 | 26 | 11 |
| 2008 | 37 | 75 | 5 | 26 | 12 |
| 2009 | 39 | 90 | 6 | 28 | 14 |
| Years\t2010-2014 | 283 | 638 | 32 | 140 | 106 |

(a) Expected	medicare	reimbursements	for	2006	through	2014	total	$22	million	and	$7	million	for	Marathon	and	MAP.

								Marathon	also	contributes	to	several	defined	contribution	plans	for	eligible	employees.	Contributions	to	these	plans,	which	for	the	most	part	are based	on	a	percentage	of	the	employees'	salary,	totaled	$35	million	in	2004,	$37	million	in	2003	and	$37	million	in	2002.

# 24.	Asset	Retirement	Obligations

								Changes	in	asset	retirement	obligations	during	the	year	were:

| Changes	in	asset	retirement	obligations	during	the	year	were: |  |  |
| :--- | :--- | :--- |
| (In\tmillions) | 2004 | 2003 |
| Asset\tretirement\tobligations\tas\tof\tJanuary\t1 | $390 | $339 |
| (a)\nLiabilities\tincurred | 17 | 32 |
| (b)\nLiabilities\tsettled | (3) | (42) |
| Accretion\texpense\t(included\tin\tdepreciation,\tdepletion\tand\tamortization) | 24 | 20 |
| Revisions\tof\tprevious\testimates | 49 | 41 |
| Asset\tretirement\tobligations\tas\tof\tDecember\t31 | $477 | $390 |

(a) Includes	$12	million	related	to	the	acquisition	of	Khanty	Mansiysk	Oil	Corporation	in	2003.

(b) Includes	$25	million	associated	with	assets	sold	in	2003.

# 25.	Stock-Based	Compensation	Plans

								The	following	is	a	summary	of	stock	option	and	SARs	activity:

|  |  | (a) |
| :--- | :--- | :--- |
|  | Shares | Price |
| Balance\tDecember\t31,\t2001 | 6,730,105 | 28.62 |
| Granted | 1,763,500 | 28.12 |
| Exercised | (242,155) | 27.58 |
| Canceled | (186,840) | 24.50 |
| Balance\tDecember\t31,\t2002 | 8,064,610 | 28.70 |
| Granted | 1,729,800 | 25.58 |
| Exercised | (642,265) | 24.48 |
| Canceled | (145,765) | 30.27 |
| Balance\tDecember\t31,\t2003 | 9,006,380 | 28.33 |
| Granted | 2,067,300 | 33.28 |
| Exercised | (2,963,546) | 17.17 |
| Canceled | (96,886) | 30.78 |
| (b)\nBalance\tDecember\t31,\t2004 | 8,013,248 | 29.84 |

(a) Weighted-average	exercise	price.

								The	following	table	represents	stock	options	and	SARs	at	December	31,	2004:

(a) Of	the	shares	granted	under	the	2003	Incentive	Compensation	Plan,	11,968	have	vested	and	41,577	have	been	cancelled	or	forfeited.	In	addition	to	the	shares,	11,750	restricted	stock	units	have	been	granted	to international	participants	under	the	plan,	270	have	vested	and	none	have	been	cancelled	or	forfeited.	Thus,	as	of	December	31,	2004,	600,235	shares	and	11,480	units	were	outstanding	under	the	plan.

(c) Of	the	shares	granted	under	the	Non-Officer	Restricted	Stock	Plan	since	2001,	399,613	have	vested	and	115,435	have	been	cancelled	or	forfeited.	In	addition	to	the	shares,	73,390	restricted	stock	units	have	been granted	to	international	participants	under	the	plan,	30,480	have	vested	and	9,955	have	been	cancelled	or	forfeited.	Thus,	as	of	December	31,	2004,	358,970	shares	and	32,955	units	were	outstanding	under	the plan.

(d) Of	the	shares	granted	under	the	special	restricted	stock	program,	5,960	shares	have	been	cancelled	or	forfeited.	In	addition	to	the	shares,	6,360	restricted	stock	units	were	granted	to	international	participants pursuant	to	this	program.	All	shares	and	units	granted	under	the	program	vested	on	January	23,	2003,	and	no	additional	shares	will	be	granted.

								On	January	1,	2004,	all	non-employee	directors	were	granted	additional	stock-based	compensation	valued	at	$40,000	in	the	form	of	common	stock units.	Common	stock	units	are	book	entry	units	equal	in	value	to	a	share	of	stock.	During	2004,	21,786	shares	of	stock	were	issued;	during	2003,	15,799 shares	of	stock	were	issued	and	during	2002,	14,472	shares	of	stock	were	issued.

# 26.	Stockholder	Rights	Plan

In	2002,	the	Marathon's	stockholder	rights	plan	(the	Rights	Plan),	was	amended	due	to	the	Separation.	In	January	2003,	the	expiration	date	of	the	Rights Plan	was	accelerated	to	January	31,	2003.

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	remaining noncancelable	lease	terms	in	excess	of	one	year	are	as	follows:

| (In	millions) | Capital<br>Lease<br>Obligations | Operating<br>Lease<br>Obligations |
| :--- | :--- | :--- |
| 2005 | $20 | $95 |
| 2006 | 26 | 80 |
| 2007 | 34 | 53 |
| 2008 | 26 | 43 |
| 2009 | 26 | 26 |
| Later\tyears | 101 | 120 |
| Sublease\trentals | – | (54) |
| Total\tminimum\tlease\tpayments | 233 | $363 |

								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	$42	million	have	been	included	above	and	an	equal	amount	has	been	reported	as	sublease	rentals.

								Of	the	$166	million	present	value	of	net	minimum	capital	lease	payments,	$122	million	was	related	to	obligations	assumed	by	United	States	Steel under	the	Financial	Matters	Agreement.	Of	the	$363	million	total	minimum	operating	lease	payments,	$13	million	was	assumed	by	United	States	Steel under	the	Financial	Matters	Agreement.

								During	2003,	Marathon	purchased	two	LNG	tankers	which	were	previously	leased.	A	$17	million	charge	was	recorded	on	the	termination	of	the operating	leases.	These	tankers	are	used	to	transport	LNG	from	Kenai,	Alaska	to	Tokyo,	Japan.

								Operating	lease	rental	expense	was:

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Minimum\trental | $168(a) | $182(a) | $196(a) |
| Contingent\trental | 15 | 15 | 13 |
| Sublease\trentals | (12) | (9) | (11) |
| Net\trental\texpense | $171 | $188 | $198 |

# 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,	2004	and	2003,	accrued	liabilities	for	remediation	totaled	$110	million	and	$117	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	cleanup	efforts	related	to	underground	storage	tanks	at	retail marketing	outlets,	were	$65	million	and	$86	million	at	December	31,	2004	and	2003,	respectively.

								On	May	11,	2001,	MAP	entered	into	a	consent	decree	with	the	U.S.	Environmental	Protection	Agency	which	commits	it	to	complete	certain	agreed on	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	is	approximately	$370	million	over	the	eight-year	period, with	about	$240	million	incurred	through	December	31,	2004.	In	addition,	MAP	has	nearly	completed	certain	agreed	on	supplemental	environmental projects	as	part	of	this	settlement	of	an	enforcement	action	for	alleged	Clean	Air	Act	violations,	at	a	cost	of	$9	million.	MAP	believes	that	this	settlement will	provide	MAP	with	increased	permitting	and	operating	flexibility	while	achieving	significant	emission	reductions.

Guarantees		–		Marathon	and	MAP	have	issued	the	following	guarantees:

|  |  | Undiscounted	Payments |
| :--- | :--- | :--- |
| (In\tmillions) |  | as\tof\tDecember\t31, |
|  | Term | 2004^(l) |
| Indebtedness\tof\tequity\tinvestees: |  |  |
| (a) |  |  |
| LOCAP | Perpetual-Loan\tBalance\tVaries | $23 |
| (a) |  |  |
| LOOP | 2005-2024 | 160 |
| (b) |  |  |
| Centennial | 2007-2024 | 75 |
| Guarantees/indemnifications\trelated\tto\tasset\tsales: |  |  |
| (c) |  |  |
| Yates | Indefinite | 228 |
| (d) |  |  |
| Canada | Indefinite | 568 |
| (e) |  |  |
| Miscellaneous\tasset\tsales | 2005-Indefinite | 30 |
| Other: |  |  |
| (f) |  |  |
| United\tStates\tSteel | 2005-2012 | 634 |
| (g) |  |  |
| Centennial\tPipeline\tcatastrophic\tevent | Indefinite | 50 |
| (h) |  |  |
| Alliance\tPipeline | 2005-2015 | 67 |
| (i) |  |  |
| Kenai\tKachemak\tPipeline\tLLC | 2005-2017 | 15 |
| (j) |  |  |
| Corporate\tassets | (j) | 14 |
| (k) |  |  |
| Mobile\ttransportation\tequipment\tleases | 2005-2008 | 6 |

(a) 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	("T&D")	agreements.	A	T&D	agreement	creates	a	potential	obligation	to	advance	funds	in	the	event	of	a	cash	shortfall.	When	these	rights	are	assigned	to	a	lender	to	secure	financing, the	T&D	is	considered	to	be	an	indirect	guarantee	of	indebtedness.	Under	the	agreements,	Marathon	is	required	to	advance	funds	if	the	investees	are	unable	to	service	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.	Assuming	non-payment	by	the	investees,	the	maximum	potential	amount	of future	payments	under	the	guarantees	is	estimated	to	be	$183	million	and	$192	million	at	December	31,	2004	and	2003,	respectively.	Included	in	these	amounts	are	a	LOOP	revolving	credit	facility	of $25	million	at	December	31,	2004	and	2003,	and	a	LOCAP	revolving	credit	facility	of	$23	million	at	December	31,	2004	and	2003.	The	undrawn	portion	of	the	revolving	credit	facilities	is	$34	million	as	of December	31,	2004	and	2003.

(b) MAP	holds	an	interest	in	a	refined	products	pipeline,	Centennial	Pipeline	LLC	("Centennial"),	and	has	guaranteed	the	repayment	of	Centennial's	outstanding	balance	under	a	Master	Shelf	Agreement,	which expires	in	2024,	and	a	Credit	Agreement,	which	expires	in	2007.	The	guarantees	arose	in	order	to	obtain	adequate	financing.	Prior	to	expiration	of	the	Master	Shelf	Agreement,	MAP	could	be	relinquished	from responsibility	under	the	guarantee	should	Centennial	meet	certain	financial	tests.	If	Centennial	defaults	on	its	outstanding	balance,	the	estimated	maximum	potential	amount	of	future	payments	is	$75	million	at December	31,	2004	and	2003.

(c) In	2003,	Marathon	sold	its	interest	in	the	Yates	field	and	gathering	system	to	Kinder	Morgan.	In	accordance	with	this	transaction,	Marathon	indemnified	Kinder	Morgan	from	inaccuracies	in	Marathon's representations,	warranties,	covenants	and	agreement.	There	is	not	a	specified	term	on	these	guarantees	and	the	maximum	potential	amount	of	future	cash	payments	is	estimated	at	$228	million.

(d) In	conjunction	with	the	sale	of	certain	Canadian	assets	to	Husky	Oil	operations	Limited	("Husky")	during	2003,	Marathon	guaranteed	Husky	with	regards	to	unknown	environmental	obligations	and inaccuracies	in	representations,	warranties,	covenants	and	agreements	by	Marathon.	These	indemnifications	are	part	of	the	normal	course	of	doing	business	and	selling	assets.	Per	the	Purchase	and	Sale agreement,	the	maximum	potential	amount	of	future	payments	associated	with	these	guarantees	is	$568	million.

(e) Marathon	entered	into	certain	performance	and	general	guarantees	and	environmental	and	general	indemnifications	in	connection	with	certain	asset	sales.	The	terms	vary	from	2005	to	indefinite	and	the maximum	potential	amount	of	future	payments	under	the	guarantees	and	indemnifications	is	estimated	to	be	$30	million.

(f) Marathon	has	guaranteed	United	States	Steel's	contingent	obligation	to	repay	certain	distributions	from	its	50	percent-owned	joint	venture,	PRO-TEC	Coating	Company	("PRO-TEC").	Should	PRO-TEC default	under	its	agreements	and	should	United	States	Steel	be	unable	to	perform	under	its	guarantee,	Marathon	is	required	to	perform	on	behalf	of	United	States	Steel.	The	maximum	potential	payout	is estimated	at	$14	million	at	December	31,	2004	and	2003.	Additionally,	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.	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	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	at	December	31,	2004	and	2003,	including	interest	and	tax	gross-up,	was	approximately	$620	million	and	$610	million.	Furthermore,	United	States Steel	under	certain	circumstances	has	indemnified	the	partnership	for	environmental	obligations.	The	maximum	potential	amount	of	this	indemnity	obligation	is	not	estimable.

(g) The	agreement	between	Centennial	and	its	members	allows	each	member	to	contribute	cash	in	lieu	of	Centennial	procuring	separate	insurance	in	the	event	of	third-party	liability	arising	from	a	catastrophic event.	There	is	an	indefinite	term	for	the	agreement	and	each	member	is	to	contribute	cash	in	proportion	to	its	ownership	interest,	up	to	a	maximum	amount	of	$50	million	at	December	31,	2004	and	2003.	In February	2003,	Marathon's	ownership	interest	in	Centennial	increased	from	33	percent	to	50	percent.	As	a	result	of	this	modification	to	the	Centennial	catastrophic	event	guarantee,	MAP	recorded	a	$4	million obligation	during	2003.

(h) Marathon	is	a	party	to	a	long-term	transportation	services	agreement	with	Alliance	Pipeline	L.P.	("Alliance").	The	agreement	requires	Marathon	to	pay	minimum	annual	charges	of	approximately	$5	million through	2015.	The	payments	are	required	even	if	the	transportation	facility	is	not	utilized.	As	this	contract	has	been	used	by	Alliance	to	secure	its	financing,	the	arrangement	qualifies	as	an	indirect	guarantee	of indebtedness.	This	agreement	runs	through	2015	and	has	a	maximum	potential	payout	of	$67	million	at	December	31,	2004	and	2003.	As	a	result	of	the	Canadian	sale	discussed	above,	Husky	has	indemnified Marathon	for	any	claims	related	to	these	guarantees.

(i) Kenai	Kachemak	Pipeline	LLC	("KKPL")	was	organized	in	late	2002.	Marathon	is	an	equity	investor	in	KKPL,	holding	a	60	percent,	noncontrolling	interest.	In	April	2003,	Marathon	guaranteed	KKPL's performance	to	properly	construct,	operate,	maintain	and	abandon	the	pipeline	in	accordance	with	the	Alaska	Pipeline	Act	and	the	Right	of	Way	Lease	Agreement	with	the	State	of	Alaska.	The	major obligations	covered	under	the	guarantee	include	maintaining	the	right-of-way,	satisfying	any	liabilities	caused	by	operation	of	the	pipeline,	and	providing	for	the	abandonment	costs.	Obligations	that	could	arise under	the	guarantee	would	vary	according	to	the	circumstances	triggering	payment	but	the	maximum	potential	payment	is	estimated	at	$15	million	at	December	31,	2004	and	2003.

(j) Marathon	has	entered	into	leases	of	corporate	assets	containing	general	lessee	indemnities	and	guaranteed	residual	value	clauses.	There	is	not	a	specified	term	and	the	maximum	potential	amount	of	future payments	is	estimated	to	be	$14	million.

(k) These	leases	contain	terminal	rental	adjustment	clauses	which	provide	that	MAP	will	indemnify	the	lessor	to	the	extent	that	the	proceeds	from	the	sale	of	the	asset	at	the	end	of	the	lease	fall	short	of	the specified	minimum	percentage	of	original	value.

(l) $318	million	represents	guarantees	made	by	MAP	and	$34	million	represents	the	undrawn	portion	of	revolving	credit	facilities.

Contract	commitments		–		At	December	31,	2004	and	2003,	Marathon's	contract	commitments	to	acquire	property,	plant	and	equipment	totaled $1,094	million	and	$565	million,	respectively.	The	$529	million	increase	is	primarily	due	to	contractual	commitments	related	to	the	Equatorial	Guinea LNG	project.	Included	in	these	contract	commitments	is	$65	million	related	to	the	approximately	$300	million	in	refinery	upgrade	and	expansion	projects for	MAP's	74,000	bpd	Detroit,	Michigan	refinery.	Marathon	will	loan	MAP	the	funds	necessary	for	the	Detroit,	Michigan	refinery	upgrade	and	expansion projects.	The	MAP	LLC	Agreement	has	been	amended	to	allow	the	Detroit	refinery	cash	flows	to	be	dedicated	to	service	this	debt.	The	Put/Call Agreement	was	amended	to	provide	that,	in	the	event	Marathon	exercises	its	call	right,	the	Detroit	refinery	will	not	be	valued	at	an	amount	less	than	the working	capital	related	to	the	Detroit	refinery,	excluding	working	capital	additions	related	to	the	expansion	and	clean	fuels	projects.

Agreements	with	joint	owners		–		In	connection	with	the	1998	formation	of	MAP,	Marathon	and	Ashland	entered	into	a	Put/Call,	Registration	Rights	and Standstill	Agreement	(the	Put/Call	Agreement).	The	Put/Call	Agreement	provides	that	at	any	time	after	December	31,	2004,	Ashland	will	have	the	right to	sell	to	Marathon	all	of	Ashland's	ownership	interest	in	MAP,	for	an	amount	in	cash	and/or	Marathon	debt	or	equity	securities	equal	to	the	product	of 85	percent	(90	percent	if	equity	securities	are	used)	of	the	fair	market	value	of	MAP	at	that	time,	multiplied	by	Ashland's	percentage	interest	in	MAP. Payment	could	be	made	at	closing,	or	at	Marathon's	option,	in	three	equal	annual	installments,	the	first	of	which	would	be	payable	at	closing.	At	any	time after	December	31,	2004,	Marathon	will	have	the	right	to	purchase	all	of	Ashland's	ownership	interests	in	MAP,	for	an	amount	in	cash	equal	to	the product	of	115	percent	of	the	fair	market	value	of	MAP	at	that	time,	multiplied	by	Ashland's	percentage	interest	in	MAP.	Pursuant	to	the	terms	of Marathon's	agreement	to	acquire	the	38	percent	ownership	interest	in	MAP	currently	held	by	Ashland,	Ashland	does	not	have	the	right	to	exercise	its	put right	and	Marathon	does	not	have	the	right	to	exercise	its	call	right	under	the	Put/Call	Agreement	unless	and	until	the	acquisition	agreement	is terminated.

								As	part	of	the	formation	of	PTC,	MAP	and	Pilot	Corporation	(Pilot)	entered	into	a	Put/Call	and	Registration	Rights	Agreement	(Agreement).	The Agreement	provides	that	any	time	after	September	1,	2008,	Pilot	will	have	the	right	to	sell	its	interest	in	PTC	to	MAP	for	an	amount	of	cash	and/or Marathon,	MAP	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,	MAP	will	have	the	right	to	purchase Pilot's	interest	in	PTC	for	an	amount	of	cash	and/or	Marathon,	MAP	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.

								In	connection	with	the	formation	of	EGHoldings,	GEPetrol	was	given	certain	contractual	rights	with	respect	to	the	purchase	and	resale	to	a	third party	of	a	13	percent	interest	in	EGHoldings	currently	held	by	Marathon.	These	rights	give	GEPetrol	the	option	to	purchase	this	13	percent	interest	and resell	it	to	a	third	party.	These	rights	specify	that	Marathon	will	be	reimbursed	for	its	historical	costs	plus	an	additional	specified	rate	of	return,	which escalates	depending	on	the	time	period	during	which	such	purchase	and	resale	occurs,	and	a	right	to	share	in	additional	proceeds	above	those	amounts under	certain	circumstances	of	resale.	If	GEPetrol's	rights	are	not	exercised	within	one	year	from	date	of	project	sanction,	the	rights	expire.

# 29.	Proposed	Acquisition

Marathon	has	entered	into	an	agreement	which	would	result	in	the	acquisition	of	the	38	percent	ownership	interest	in	MAP	currently	held	by	Ashland.	In addition,	Marathon	would	acquire	a	portion	of	Ashland's	Valvoline	Instant	Oil	Change	business	and	its	maleic	anhydride	business.	As	a	result	of	the transaction,	MAP	will	become	a	wholly	owned	subsidiary	of	Marathon.

								As	part	of	the	transaction,	Ashland	will	receive	approximately	$800	million	in	cash	and	accounts	receivable	from	MAP	to	redeem	a	portion	of	its interest	in	MAP.	Marathon	will	assume	approximately	$1.9	billion	of	debt,	which	is	expected	to	be	repaid	immediately	following	closing.	Additionally, Ashland	shareholders	will	receive	$315	million	in	Marathon	common	stock.	Ashland's	liabilities	under	certain	existing	environmental	indemnification obligations	related	to	MAP	will	be	capped	at	$50	million.

								The	MAP	Limited	Liability	Company	Agreement	has	been	amended	to	eliminate	the	requirement	for	MAP	to	make	quarterly	cash	distributions	to Marathon	and	Ashland	between	the	date	the	principal	transaction	agreements	were	signed	and	the	closing	of	the	transaction.	As	a	result,	the	redemption proceeds	to	Ashland	(cash	and	accounts	receivable)	will	be	increased	by	an	amount	equal	to	approximately	38	percent	of	the	cash	accumulated	from MAP's	operations	during	that	period,	subject	to	certain	adjustments.	At	December	31,	2004,	Ashland's	share	of	distributable	cash	was	$574	million.	In the	event	of	a	termination	of	the	acquisition	agreement,	MAP's	obligation	to	make	cash	distributions	to	Marathon	and	Ashland	would	be	restored.

								On	June	1,	2004,	the	United	States	Federal	Trade	Commission	granted	early	termination	of	the	pre-closing	waiting	period	mandated	by	the	Hart- Scott-Rodino	Act,	thereby	indicating	that	it	had	no	present	intent	to	challenge	the	acquisition	and	permitting	the	parties	to	proceed	toward	closing. Additionally,	Marathon	and	Ashland	submitted	a	request	for	a	letter	ruling	to	the	United	States	Internal	Revenue	Service	("IRS")	on	the	tax-free	status	of the	proposed	acquisition.	Related	to	the	proposed	acquisition,	Marathon	filed	a	registration	statement	on	Form	S-4	with	the	United	States	Securities	and Exchange	Commission	on	October	12,	2004,	subsequent	to	Ashland	filing	a	preliminary	proxy	statement	on	Schedule	14A	on	June	21,	2004,	and Amendment	No.	1	to	Schedule	14A	on	August	31,	2004.	The	completion	of	the	acquisition	is	subject	to	a	number	of	conditions,	including	favorable private	letter	rulings	from	the	IRS,	Ashland	shareholder	approval	and	Ashland	public	debt	holder	consents.

# 30.	Suspended	Exploratory	Well	Costs

Deferred	exploratory	well	costs	were	as	follows:

| (In	millions,	except	number	of	projects) | Projects	as	of<br>December	31,	2004 | December	31,	2004 | December	31,	2003 | December	31,	2002 |
| :--- | :--- | :--- | :--- | :--- |
| Additional\twells\tare\tunderway\tor\tfirmly\tplanned: |  |  |  |  |
| Less\tthan\tone\tyear\tsince\trig\trelease | 17 | $254 | $146 | $86 |
| Greater\tthan\tone\tyear\tsince\trig\trelease | 2 | 55 | – | – |
| Additional\twells\tare\tnot\tunderway\tor\tfirmly\tplanned: |  |  |  |  |
| Less\tthan\tone\tyear\tsince\trig\trelease | 1 | 23 | – | 12 |
| Greater\tthan\tone\tyear\tsince\trig\trelease | – | – | 78 | 9 |
| (a) |  |  |  |  |
| Drilling\tand\tcompletion\tcosts | 44 | 7 | 19 | 29 |
| Discontinued\toperations | – | – | – | 12 |
| Total\tdeferred\texploratory\twell\tcosts | 64 | $339 | $243 | $148 |
| Number\tof\tprojects\tthat\thave\texploratory\twell\tcosts\tthat\thave\nbeen\tcapitalized\tfor\ta\tperiod\tgreater\tthan\tone\tyear |  | 2 | 4 | 2 |

(a) Include	costs	of	single	well	projects	currently	drilling	and	costs	for	installation	of	permanent	equipment	for	recently	drilled	wells.

								Deferred	exploratory	well	costs	of	$339	million	as	of	December	31,	2004	were	incurred	during	the	following	years:

| (In	millions) | 2004 | 2003 | 2002 | 2001 |
| :--- | :--- | :--- | :--- | :--- |
| Deferred\texploratory\twell\tcosts | $173 | $63 | $57 | $46 |

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

| (In	millions) | Balance	at<br>Beginning	of<br>Period | Additions | Dry	Well<br>Expense | Transfer	to<br>Proved<br>Properties | Other |  | Balance<br>at	End	of<br>Period |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tended\tDecember\t31,\t2004 | $243 | $239 | $(54) | $(89) | $– |  | $339 |
| Year\tended\tDecember\t31,\t2003 | 148 | 256 | (56) | (90) | (15 | (a) | 243 |
| Year\tended\tDecember\t31,\t2002 | 161 | 153 | (100) | (66) | – |  | 148 |

(a) Related	to	the	sale	of	Marathon's	exploration	and	production	operations	in	Western	Canada

								Of	the	total	capitalized	costs	for	exploratory	wells,	approximately	$78	million	and	$9	million	at	December	31,	2003	and	2002	related	to	wells	for which	costs	had	been	suspended	for	more	than	one	year	following	the	completion	of	drilling	and	for	which	additional	exploratory	wells	are	not	underway or	firmly	planned.	There	were	none	at	December	31,	2004.	For	each	of	these	wells,	sufficient	progress	is	being	made	assessing	the	reserves	and	the economic	and	operating	viability	of	these	projects	to	justify	continued	capitalization	of	the	costs.	The	following	table	presents	information	relating	to these	wells:

|  |  |  | Costs | Costs | Costs |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  |  |  | Capitalized\tat | Capitalized\tat | Capitalized\tat |
| Area |  |  | 12/31/04 | 12/31/03 | 12/31/02 |
|  | Prospect | Month\tSuspended | (in\tmillions) | (in\tmillions) | (in\tmillions) |
| Irish\tSea | Corrib | July\t2001 | $–\t\t(a) | $21(a) | $–\t\t(a) |
| Gulf\tof\tMexico | Ozona | June\t2002 | –\t\t(b) | 42(b) | – |
| Gulf\tof\tMexico | Flathead | January\t2002 | –\t\t(c) | 12(c) | – |
| Other\tminor\twells |  |  | – | 3 | 9 |
| Total |  |  | $– | $78 | $9 |

(a) A	plan	of	development	for	the	Corrib	Field	was	submitted	to	the	Petroleum	Affairs	Division	of	the	Department	of	Communications	Marine	and	Natural	Resources	in	November	2000.	Awards	of	major contracts	for	a	terminal,	subsea	facilities,	and	an	onshore	pipeline	were	made	between	March	and	August	2001.	Design	of	the	facilities	was	commenced	and	material	was	procured.	Planning	approval	for	the terminal	construction	was	received	from	the	Mayo	County	Council	(the	"local	authority")	in	August	2001	but	this	approval	was	appealed	to	the	National	Planning	Appeals	Board	("ABP")	in	September	2001.	As a	result	of	the	expected	delay,	due	to	the	appeal	to	ABP,	a	revised	plan	of	development	was	submitted	in	November	2001	and	a	Petroleum	Lease	was	awarded	to	the	Corrib	joint	venture	participants	in	the	same month.	In	2001,	Marathon	recognized	proved	undeveloped	reserves	due	to	Marathon's	record	of	obtaining	necessary	permits	and	approvals	in	Ireland.	In	May	2002,	ABP	approved	the	revised	plan	of development.	In	April	2003,	following	a	lengthy	appeals	process,	ABP	refused	planning	permission	for	the	terminal	due	to	concerns	over	the	long	term	stability	of	stripped	peat	that	was	to	be	stored	on	the	site. Marathon	reclassified	approximately	14	million	barrels	of	oil	equivalent	from	proved	undeveloped	reserves	to	unproved	reserves	in	2003	due	to	continuing	delays	in	receiving	the	necessary	approval	for	the terminal.	In	December	2003,	a	new	planning	application	was	submitted	to	the	local	authority	for	the	terminal	which	addressed	ABP's	concerns	over	peat	stability.	The	local	authority	granted	planning permission	for	the	revised	application	in	April	2004;	however	this	was	subsequently	appealed	to	ABP.	In	October	2004,	ABP	upheld	the	local	authority's	decision	to	grant	planning	permission	for	the	natural	gas terminal.	This	decision	is	a	major	step	forward	in	the	Corrib	Project	and	has	allowed	development	activities	to	proceed.	Marathon	recognized	proved	reserves	for	Corrib	at	the	end	of	2004.

(b) In	2001	a	successful	discovery	well	was	drilled	on	the	Ozona	prospect.	In	2002,	two	sidetrack	wells	were	drilled.	One	was	successful	while	the	other	was	written	off	to	exploratory	dry	well	expense	in	the amount	of	$14	million.	An	integrated	project	team	was	formed	in	2003	to	formulate	a	development	plan.	Marathon	is	currently	negotiating	commercial	terms	of	a	production	handling	agreement	with	a	nearby operator	and	is	also	in	the	process	of	reviewing	seismic	data	to	obtain	a	better	understanding	of	the	complex	salt	formations	in	the	area	and	to	optimize	the	location	of	the	next	well.	As	of	December	31,	2004, drilling	operations	for	the	next	well	were	firmly	planned	and	are	expected	to	be	completed	in	July	2005.	The	results	of	this	well	will	determine	when	proved	reserves	will	be	recognized.

(c) Future	plans	are	to	re-enter	and	sidetrack	this	well.	All	costs	below	16,000	feet,	which	totaled	$18	million,	were	written	off	to	exploratory	dry	well	expense	in	2001	and	2002.	Marathon	entered	into	a	joint venture	agreement	on	August	5,	2003,	for	a	technical	evaluation	of	the	prospect.	In	addition,	Marathon	is	in	the	process	of	reviewing	seismic	data	for	another	drilling	prospect.	As	of	December	31,	2004,	a	well was	firmly	planned	for	2005.	If	a	discovery	is	made,	plans	are	to	utilize	the	initial	wellbore	to	sidetrack	as	an	appraisal	well.	The	earliest	that	proved	reserves	could	potentially	be	recognized	would	be	at	project sanction,	estimated	in	2007.	If	the	2005	well	is	not	successful,	the	initial	well	will	be	written	off	in	2005.

|  | 4th	Qtr. | 3rd	Qtr. | 2nd	Qtr. | 1st	Qtr. | 4th	Qtr. | 3rd	Qtr. | 2nd	Qtr. | 1st	Qtr. |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Revenues | $14,183 | $12,249 | $12,514 | $10,652 | $11,034 | $10,253 | $9,644 | $10,032 |
| Income\tfrom\toperations | 821 | 542 | 829 | 478 | 353 | 658 | 526 | 547 |
| Income\tfrom\tcontinuing\toperations | 429 | 222 | 348 | 258 | 199 | 293 | 235 | 285 |
| Income\t(loss)\tfrom\tdiscontinued\toperations | – | – | 4 | – | 286 | (12) | 13 | 18 |
| Income\tbefore\tcumulative\teffect\tof\tchanges\tin |  |  |  |  |  |  |  |  |
| accounting\tprinciple | 429 | 222 | 352 | 258 | 485 | 281 | 248 | 303 |
| Net\tincome | 429 | 222 | 352 | 258 | 485 | 281 | 248 | 307 |
| Common\tStock\tdata: |  |  |  |  |  |  |  |  |
| Net\tincome\tper\tshare |  |  |  |  |  |  |  |  |
| –\tBasic | 1.24 | .64 | 1.02 | .83 | 1.57 | .90 | .80 | .99 |
| –\tDiluted | 1.23 | .64 | 1.02 | .83 | 1.57 | .90 | .80 | .99 |
| Dividends\tpaid\tper\tshare | .28 | .25 | .25 | .25 | .25 | .25 | .23 | .23 |
| (a) |  |  |  |  |  |  |  |  |
| Price\trange\tof\tCommon\tStock\n: |  |  |  |  |  |  |  |  |
| –\tLow | 36.67 | 33.98 | 32.22 | 30.78 | 28.91 | 25.01 | 22.56 | 20.20 |
| –\tHigh | 42.13 | 41.52 | 37.84 | 36.06 | 33.37 | 29.42 | 27.00 | 24.04 |

(a) Composite	tape

| Alba	Plant	LLC | Cayman	Islands | 52% | (a) | Liquified	Petroleum	Gas |
| :--- | :--- | :--- | :--- | :--- |
| Atlantic\tMethanol\tProduction\tCompany,\tLLC | United\tStates | 45% | 45% | Methanol\tProduction |
| Centennial\tPipeline\tLLC | United\tStates | 50% | (b) | Pipeline\t&amp;\tStorage\tFacility |
| Kenai\tKachemak\tPipeline,\tLLC | United\tStates | 60% | (a) | Natural\tGas\tTransmission |
| Kenai\tLNG\tCorporation | United\tStates | 30% | 30% | Natural\tGas\tLiquification |
| LOCAP\tLLC | United\tStates | 50% | (b) | Pipeline\t&amp;\tStorage\tFacilities |
| LOOP\tLLC | United\tStates | 47% | (b) | Offshore\tOil\tPort |
| Manta\tRay\tOffshore\tGathering\tCompany,\tLLC | United\tStates | 24% | 24% | Natural\tGas\tTransmission |
| Minnesota\tPipe\tLine\tCompany | United\tStates | 33% | (b) | Pipeline\tFacility |
| Nautilus\tPipeline\tCompany,\tLLC | United\tStates | 24% | 24% | Natural\tGas\tTransmission |
| Odyssey\tPipeline\tLLC | United\tStates | 29% | 29% | Pipeline\tFacility |
| Pilot\tTravel\tCenters\tLLC | United\tStates | 50% | (b) | Travel\tCenters |
| Poseidon\tOil\tPipeline\tCompany,\tLLC | United\tStates | 28% | 28% | Crude\tOil\tTransportation |
| Southcap\tPipe\tLine\tCompany | United\tStates | 22% | (b) | Crude\tOil\tTransportation |

(a) Represents	a	noncontrolling	interest.

(b) Represents	the	ownership	interest	held	by	MAP.

								The	supplemental	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	and	Gabon;	and	Other	International,	which	includes	activities	in Nova	Scotia,	Russian	Federation	and	other	international	locations	outside	of	Europe	and	Africa.	Equity	investees	include	Marathon's	share	of	the	oil	and	gas	producing activities	of	companies	that	are	accounted	for	by	the	equity	method.	This	includes	Alba	Plant	LLC,	CLAM	Petroleum	B.V.	(sold	in	2003),	Kenai	Kachemak	Pipeline, LLC,	LLC	JV	Chernogorskoye	(sold	in	2004)	and	MKM	Partners	L.P.	(dissolved	in	2003).	No	oil	or	gas	reserves	are	attributed	to	ownership	in	Alba	Plant	LLC	or Kenai	Kachemak	Pipeline,	LLC.

| (In	millions)										December	31 | United<br>States | Europe | Africa | Other<br>Int'l. | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2004\tCapitalized\tcosts: |  |  |  |  |  |
| Proved\tproperties | $6,508 | $5,689 | $1,376 | $231 | $13,804 |
| Unproved\tproperties | 454 | 115 | 181 | 215 | 965 |
| Suspended\texploratory\twells | 115 | 15 | 174 | 35 | 339 |
| Total | 7,077 | 5,819 | 1,731 | 481 | 15,108 |
| Accumulated\tdepreciation,\tdepletion\tand\tamortization: |  |  |  |  |  |
| Proved\tproperties | 4,432 | 4,209 | 201 | 55 | 8,897 |
| Unproved\tproperties | 22 | – | 9 | 33 | 64 |
| Total | 4,454 | 4,209 | 210 | 88 | 8,961 |
| Net\tcapitalized\tcosts | $2,623 | $1,610 | $1,521 | $393 | $6,147 |
| Share\tof\tequity\tinvestees'\tcapitalized\tcosts | $14 | $– | $377 | $– | $391 |
| 2003\tCapitalized\tcosts: |  |  |  |  |  |
| Proved\tproperties | $6,158 | $5,288 | $1,147 | $119 | $12,712 |
| Unproved\tproperties | 507 | 255 | 268 | 237 | 1,267 |
| Suspended\texploratory\twells | 108 | 46 | 58 | 31 | 243 |
| Total | 6,773 | 5,589 | 1,473 | 387 | 14,222 |
| Accumulated\tdepreciation,\tdepletion\tand\tamortization: |  |  |  |  |  |
| Proved\tproperties | 4,128 | 3,922 | 144 | 17 | 8,211 |
| Unproved\tproperties | 37 | – | 9 | – | 46 |
| Total | 4,165 | 3,922 | 153 | 17 | 8,257 |
| Net\tcapitalized\tcosts | $2,608 | $1,667 | $1,320 | $370 | $5,965 |
| Share\tof\tequity\tinvestees'\tcapitalized\tcosts | $14 | $– | $251 | $11 | $276 |

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

| (In	millions) | United<br>States | Europe | Africa | Other<br>Int'l. | Continuing<br>Operations | Discontinued<br>Operations | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2004\tProperty\tacquisition: |  |  |  |  |  |  |  |
| Proved | $9 | $– | $3 | $– | $12 | $– | $12 |
| Unproved | 10 | – | 1 | – | 11 | – | 11 |
| Exploration | 96 | 27 | 127 | 41 | 291 | – | 291 |
| Development | 316 | 151 | 140 | 102 | 709 | – | 709 |
| (b)\nCapitalized\tasset\tretirement\tcosts | 14 | 49 | 5 | (5) | 63 | – | 63 |
| Total | 445 | 227 | 276 | 138 | 1,086 | – | 1,086 |
| Share\tof\tequity\tinvestees'\tcosts\tincurred | 1 | – | 128 | 1 | 130 | – | 130 |
| 2003\tProperty\tacquisition: |  |  |  |  |  |  |  |
| Proved | $1 | $1 | $– | $66 | $68 | $– | $68 |
| Unproved | 5 | 3 | 1 | 244 | 253 | – | 253 |
| Exploration | 114 | 35 | 53 | 29 | 231 | 17 | 248 |
| Development | 266 | 148 | 352 | 33 | 799 | 26 | 825 |
| (b)(c)\nCapitalized\tasset\tretirement\tcosts | 9 | 47 | 3 | 14 | 73 | – | 73 |
| Total | 395 | 234 | 409 | 386 | 1,424 | 43 | 1,467 |
| Share\tof\tequity\tinvestees'\tcosts\tincurred | 29 | 4 | 80 | 12 | 125 | – | 125 |
| 2002\tProperty\tacquisition: |  |  |  |  |  |  |  |
| Proved | $–\t\t\t $– | $–\t\t\t $– | $341 | $24 | $365 | $– | $365 |
| Unproved | 2 | 105 | 294 | 2 | 403 | – | 403 |
| Exploration | 184 | 10 | 24 | 40 | 258 | 27 | 285 |
| Development | 273 | 100 | 126 | 1 | 500 | 39 | 539 |
| Total | 459 | 215 | 785 | 67 | 1,526 | 66 | 1,592 |

# Share	of	equity	investees'	costs	incurred

(a) Includes	costs	incurred	whether	capitalized	or	expensed.

(b) Includes	the	effect	of	foreign	currency	fluctuations.

(c) Excludes	$161	million	cumulative	effect	of	adopting	SFAS	No.	143.

# Results	of	Operations	for	Oil	and	Gas	Producing	Activities

| (In	millions) | United<br>States | Europe | Africa | Other<br>Int'l. | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2004:\tRevenues\tand\tother\tincome:\nSales^(a) | $1,631 | $876 | $260 | $56 | $2,823 |
| Transfers | 392 | 28 | 159 | 75 | 654 |
| Total\trevenues | 2,023 | 904 | 419 | 131 | 3,477 |
| Expenses: |  |  |  |  |  |
| Production\tcosts | (381) | (166) | (55) | (96) | (698) |
| Transportation\tcosts^(b) | (112) | (35) | (6) | (7) | (160) |
| Exploration\texpenses | (79) | (19) | (28) | (44) | (170) |
| Depreciation,\tdepletion\tand\tamortization^(c) | (356) | (275) | (56) | (26) | (713) |
| Impairments^(d) | – | – | – | (44) | (44) |
| Administrative\texpenses | (39) | (4) | (15) | (24) | (82) |
| Total\texpenses | (967) | (499) | (160) | (241) | (1,867) |
| Other\tproduction-related\tincome\t(losses)^(e) | – | 15 | – | – | 15 |
| Results\tbefore\tincome\ttaxes | 1,056 | 420 | 259 | (110) | 1,625 |
| Income\ttaxes\t(credits)^(f) | 378 | 156 | 97 | (28) | 603 |
| Results\tof\tcontinuing\toperations | $678 | $264 | $162 | $(82) | $1,022 |
| Share\tof\tequity\tinvestees'\tresults\tof\toperations | $1 | $– | $9 | $1 | $11 |
| 2003:\tRevenues\tand\tother\tincome:\nSales^(a) | $1,777 | $728 | $139 | $43 | $2,687 |
| Transfers | 424 | 20 | 127 | 24 | 595 |
| Other\tincome\t(loss)^(g) | (88) | 65 | (1) | – | (24) |
| Total\trevenues | 2,113 | 813 | 265 | 67 | 3,258 |
| Expenses: |  |  |  |  |  |
| Production\tcosts | (410) | (136) | (55) | (53) | (654) |
| Transportation\tcosts^(b) | (120) | (32) | (5) | (3) | (160) |
| Exploration\texpenses | (118) | (18) | (15) | (28) | (179) |
| (c)(h)\nDepreciation,\tdepletion\tand\tamortization | (407) | (227) | (42) | (11) | (687) |
| Impairments | (3) | – | – | – | (3) |
| Administrative\texpenses | (43) | (17) | (4) | (36) | (100) |
| Total\texpenses | (1,101) | (430) | (121) | (131) | (1,783) |
| (e)\nOther\tproduction-related\tincome\t(losses) | 1 | 26 | – | – | 27 |
| Results\tbefore\tincome\ttaxes | 1,013 | 409 | 144 | (64) | 1,502 |
| (f)\nIncome\ttaxes\t(credits) | 352 | 146 | 4 | (27) | 475 |
| Results\tof\tcontinuing\toperations | $661 | $263 | $140 | $(37) | $1,027 |
| Results\tof\tdiscontinued\toperations | $– | $– | $– | $41 | $41 |
| Share\tof\tequity\tinvestees'\tresults\tof\toperations | $8 | $4 | $6 | $– | $18 |
| 2002:\tRevenues\tand\tother\tincome:\n(a)\nSales | $1,174 | $703 | $86 | $10 | $1,973 |
| Transfers | 574 | 34 | 128 | – | 736 |
| (f)\nOther\tincome | 21 | – | – | 2 | 23 |
| Total\trevenues | 1,769 | 737 | 214 | 12 | 2,732 |
| Expenses: |  |  |  |  |  |
| Production\tcosts | (365) | (145) | (48) | (5) | (563) |
| (b)\nTransportation\tcosts | (106) | (34) | (2) | – | (142) |
| Exploration\texpenses | (155) | (10) | (9) | (18) | (192) |
| Depreciation,\tdepletion\tand\tamortization | (411) | (251) | (41) | (2) | (705) |
| Impairments | (13) | – | – | – | (13) |
| Administrative\texpenses | (41) | (29) | (2) | (38) | (110) |
| Contract\tsettlement | (15) | – | – | – | (15) |
| Total\texpenses | (1,106) | (469) | (102) | (63) | (1,740) |
| (e)\nOther\tproduction-related\tincome\t(losses) | 1 | (4) | – | – | (3) |
| Results\tbefore\tincome\ttaxes | 664 | 264 | 112 | (51) | 989 |
| Income\ttaxes\t(credits)^(f) | 237 | 82 | 36 | (18) | 337 |
| Results\tof\tcontinuing\toperations | $427 | $182 | $76 | $(33) | $652 |
| Results\tof\tdiscontinued\toperations | $– | $– | $– | $(16) | $(16) |
| Share\tof\tequity\tinvestees'\tresults\tof\toperations | $30 | $4 | $4 | $– | $38 |

(a) Excludes	noncash	effects	of	changes	in	the	fair	value	of	certain	long-term	gas	sales	contracts	in	the	United	Kingdom.

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

(c) Includes	accretion	of	interest	on	asset	retirement	obligations.

(d) Includes	impairment	of	unproved	and	producing	oil	and	gas	properties.

(e) Includes	revenues,	net	of	associated	costs,	from	third-party	activities	that	are	an	integral	part	of	Marathon's	production	operations	which	may	include	the	processing	and/or	transportation	of	third-party production,	and	the	purchase	and	subsequent	resale	of	gas	utilized	in	reservoir	management.

(f) Computed	by	adjusting	results	before	income	taxes	by	permanent	differences	and	multiplying	the	result	by	the	35	percent	statutory	rate	and	adjusting	for	applicable	tax	credits.

(g) Includes	net	gains	(losses)	on	asset	dispositions.

(h) Excludes	the	cumulative	effect	on	net	income	of	the	adoption	of	SFAS	No.	143.

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Results\tbefore\tincome\ttaxes | $1,625 | $1,502 | $989 |
| Items\tnot\tincluded\tin\tresults\tof\tcontinuing\toil\t&amp;\tgas\toperations: |  |  |  |
| Marketing\tincome\tand\ttechnology\tcosts | 16 | 24 | 25 |
| Income\tfrom\tequity\tmethod\tinvestments | 12 | 20 | 52 |
| Other | (1) | (5) | 2 |
| Items\tnot\tallocated\tto\tE&amp;P\tsegment\tincome: |  |  |  |
| Impairment\tof\tcertain\tunproved\tand\tproducing\toil\tand\tgas\tproperties | 44 | – | – |
| Gain\ton\tasset\tdisposition | – | (85) | (24) |
| Contract\tsettlement | – | – | 15 |
| Loss\ton\tjoint\tventure\tdissolution | – | 124 | – |
| E&amp;P\tsegment\tincome | $1,696 | $1,580 | $1,059 |

|  | United<br>States | Europe | Africa | Other<br>Int'l. | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2004 | $5.58 | $5.39 | $3.35 | $16.76 | $5.75 |
| 2003 | 4.92 | 4.35 | 3.98 | 14.56 | 4.95 |
| 2002 | 4.17 | 4.03 | 3.81 | 14.95 | 3.90 |

(a) Computed	using	production	costs,	excluding	transportation	costs,	as	disclosed	in	the	Results	of	Operations	for	Oil	and	Gas	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	Sales	Prices

|  | United<br>States | Europe | Africa | Other<br>Int'l. | Continuing<br>Operations | Discontinued<br>Operations |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| (excluding\tderivative\tgains\tand\tlosses) |  |  |  |  |  |  |
| 2004:\tLiquid\thydrocarbons\t(per\tbbl) | $32.76 | $37.16 | $35.11 | $22.65 | $33.31 | $– |
| (a)\nNatural\tgas\t(per\tmcf) | 4.89 | 4.11 | .25 | – | 4.31 | – |
| 2003:\tLiquid\thydrocarbons\t(per\tbbl) | $26.92 | $28.50 | $26.29 | $18.33 | $26.72 | $28.96 |
| (a)\nNatural\tgas\t(per\tmcf) | 4.53 | 3.32 | .25 | – | 3.96 | 5.43 |
| 2002:\tLiquid\thydrocarbons\t(per\tbbl) | $22.18 | $24.40 | $22.62 | $26.98 | $22.86 | $23.29 |
| (a)\nNatural\tgas\t(per\tmcf) | 2.87 | 2.66 | .24 | – | 2.69 | 3.30 |
| (including\tderivative\tgains\tand\tlosses) |  |  |  |  |  |  |
| 2004:\tLiquid\thydrocarbons\t(per\tbbl) | $29.11 | $33.65 | $35.11 | $22.62 | $30.73 | $– |
| (a)\nNatural\tgas\t(per\tmcf) | 4.85 | 4.11 | .25 | – | 4.28 | – |
| 2003:\tLiquid\thydrocarbons\t(per\tbbl) | $26.09 | $27.27 | $26.29 | $18.33 | $25.96 | $28.96 |
| (a)\nNatural\tgas\t(per\tmcf) | 4.31 | 3.32 | .25 | – | 3.81 | 5.43 |
| 2002:\tLiquid\thydrocarbons\t(per\tbbl) | $21.83 | $24.53 | $22.62 | $26.98 | $22.68 | $23.39 |
| (a)\nNatural\tgas\t(per\tmcf) | 3.05 | 2.66 | .24 | – | 2.79 | 3.30 |

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

# Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves

								Estimates	of	the	proved	reserves	have	been	prepared	by	internal	asset	teams	including	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	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	are	subject	to	changes,	either	positively	or	negatively,	as additional	information	becomes	available	and	contractual,	economic	and	political	conditions	change.

								Marathon's	net	proved	reserve	estimates	have	been	adjusted	as	necessary	to	consider	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,	unless	there	is	a	clear	and	consistent	history	of contract	extension,	have	been	included	in	the	proved	reserve	estimate.	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,	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.	Production	volumes	shown	are	sales volumes,	net	of	any	products	consumed	during	production	activities.

| (Millions	of	barrels) | United<br>States | Europe | Africa^(a) | Other<br>Int'l | Continuing<br>Operations | Discontinued<br>Operations |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Liquid\tHydrocarbons |  |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2002 | 268 | 88 | 17 | – | 373 |  | 13 |
| (b)\nPurchase\tof\treserves\tin\tplace | – | – | 107 | 3 | 110 |  | – |
| Revisions\tof\tprevious\testimates | 16 | 4 | 1 | – | 21 |  | – |
| Improved\trecovery | 2 | – | – | – | 2 |  | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 4 | 3 | 87 | – | 94 |  | – |
| Production | (42) | (19) | (9) | – | (70) |  | (2) |
| (b)\nSales\tof\treserves\tin\tplace | (3) | – | – | – | (3) |  | (1) |
| End\tof\tyear\t–\t2002 | 245 | 76 | 203 | 3 | 527 |  | 10 |
| (b)\nPurchase\tof\treserves\tin\tplace | – | – | – | 64 | 64 |  | – |
| (c)\nExchange\tof\treserves\tin\tplace | 173 | – | – | – | 173 |  | – |
| Revisions\tof\tprevious\testimates | – | (4) | 25 | 11 | 32 |  | – |
| Improved\trecovery | 4 | – | – | 4 | 8 |  | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 10 | 2 | – | 14 | 26 |  | – |
| Production | (39) | (15) | (10) | (4) | (68) |  | (1) |
| (b)\nSales\tof\treserves\tin\tplace | (183) | – | – | (3) | (186) |  | (9) |
| End\tof\tyear\t–\t2003 | 210 | 59 | 218 | 89 | 576 |  | – |
| (b)\nPurchase\tof\treserves\tin\tplace | 1 | – | 2 | – | 3 |  | – |
| Revisions\tof\tprevious\testimates | (1) | 3 | 14 | (51) | (35) |  | – |
| Improved\trecovery | 1 | – | – | – | 1 |  | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 9 | 60 | 1 | 7 | 77 |  | – |
| Production | (29) | (15) | (12) | (6) | (62) |  | – |
| (b)\nSales\tof\treserves\tin\tplace | – | – | – | – | – |  | – |
| End\tof\tyear\t–\t2004 | 191 | 107 | 223 | 39 | 560 |  | – |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2002 | 243 | 69 | 14 | – | 326 |  | 11 |
| End\tof\tyear\t–\t2002 | 226 | 63 | 113 | 2 | 404 |  | 9 |
| End\tof\tyear\t–\t2003 | 193 | 47 | 120 | 31 | 391 |  | – |
| End\tof\tyear\t–\t2004 | 171 | 41 | 147 | 27 | 386 |  | – |

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

| Beginning	of	year	–	2002 | 184 | – | – | – | 184 | – |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Revisions\tof\tprevious\testimates | 2 | – | – | – | 2 | – |
| Production | (3) | – | – | – | (3) | – |
| End\tof\tyear\t–\t2002 | 183 | – | – | – | 183 | – |
| (b) |  |  |  |  |  |  |
| Purchase\tof\treserves\tin\tplace | – | – | – | 2 | 2 | – |
| (c) |  |  |  |  |  |  |
| Exchange\tof\treserves\tin\tplace | (173) | – | – | – | (173) | – |
| Production | (2) | – | – | – | (2) | – |
| (b) |  |  |  |  |  |  |
| Sales\tof\treserves\tin\tplace | (8) | – | – | – | (8) | – |
| End\tof\tyear\t–\t2003 | – | – | – | 2 | 2 | – |
| (b) |  |  |  |  |  |  |
| Sales\tof\treserves\tin\tplace | – | – | – | (2) | (2) | – |
| End\tof\tyear\t–\t2004 | – | – | – | – | – | – |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2002 | 178 | – | – | – | 178 | – |
| End\tof\tyear\t–\t2002 | 177 | – | – | – | 177 |  |
| End\tof\tyear\t–\t2003 | – | – | – | 2 | 2 | – |
| End\tof\tyear\t–\t2004 | – | – | – | – | – | – |
| Natural\tGas |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2002 | 1,793 | 615 | – | – | 2,408 | 399 |
| (b) |  |  |  |  |  |  |
| Purchase\tof\treserves\tin\tplace | – | – | 571 | – | 571 | 9 |
| Revisions\tof\tprevious\testimates | 48 | 4 | – | – | 52 | (20) |
| Improved\trecovery | – | – | – | – | – | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 156 | 46 | 101 | – | 303 | 32 |
| (d) |  |  |  |  |  |  |
| Production | (272) | (103) | (19) | – | (394) | (38) |
| (b) |  |  |  |  |  |  |
| Sales\tof\treserves\tin\tplace | (1) | – | – | – | (1) | (3) |
| End\tof\tyear\t–\t2002 | 1,724 | 562 | 653 | – | 2,939 | 379 |
| (b) |  |  |  |  |  |  |
| Purchase\tof\treserves\tin\tplace |  |  |  |  |  |  |
|  | 7 | – | – | – | 7 | – |
| Revisions\tof\tprevious\testimates | 20 | (7) | 36 | – | 49 | – |
| Improved\trecovery | – | – | – | – | – | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 161 | 24 | – | – | 185 | 8 |
| (d) |  |  |  |  |  |  |
| Production | (267) | (95) | (24) | – | (386) | (27) |
| (b) |  |  |  |  |  |  |
| Sales\tof\treserves\tin\tplace | (10) | – | – | – | (10) | (360) |
| End\tof\tyear\t–\t2003 | 1,635 | 484 | 665 | – | 2,784 | – |
| (b) |  |  |  |  |  |  |
| Purchase\tof\treserves\tin\tplace | 1 | – | – | – | 1 | – |
| Revisions\tof\tprevious\testimates | (230) | 7 | 916 | – | 693 |  |
| Improved\trecovery | – | – | – | – | – | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 189 | 150 | 11 | – | 350 |  |
| (d) |  |  |  |  |  |  |
| Production | (231) | (97) | (28) | – | (356) |  |
| (b) |  |  |  |  |  |  |
| Sales\tof\treserves\tin\tplace | – | – | – | – | – | – |
| End\tof\tyear\t–\t2004 | 1,364 | 544 | 1,564 |  | 3,472 | – |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2002 | 1,308 | 473 | – | – | 1,781 | 308 |
| End\tof\tyear\t–\t2002 | 1,206 | 408 | 552 | – | 2,166 | 290 |
| End\tof\tyear\t–\t2003 | 1,067 | 421 | 528 | – | 2,016 | – |
| End\tof\tyear\t–\t2004 | 992 | 376 | 570 | – | 1,938 | – |
| Share\tof\tequity\tinvestees'\tproved\tdeveloped\tand |  |  |  |  |  |  |
| undeveloped\treserves: |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2002 | – | 51 | – | – | 51 | – |
| Revisions\tof\tprevious\testimates | – | 3 | – | – | 3 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | – | 14 | – | – | 14 | – |
| Production | – | (9) | – | – | (9) | – |
| End\tof\tyear\t–\t2002 | – | 59 | – | – | 59 | – |
| Revisions\tof\tprevious\testimates | – | 1 | – | – | 1 | – |
| Production | – | (5) | – | – | (5) | – |
| (b) |  |  |  |  |  |  |
| Sales\tof\treserves\tin\tplace | – | (55) | – | – | (55) | – |
| End\tof\tyear\t–\t2003 | – | – | – | – | – | – |
| End\tof\tyear\t–\t2004 | – | – | – | – | – | – |
| Proved\tdeveloped\treserves:\nBeginning\tof\tyear\t–\t2002 | – | 32 | – | – | 32 | – |

| End	of	year	–	2002 | – | 36 | – | – | 36 | – |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| End\tof\tyear\t–\t2003 | – | – | – | – | – | – |
| End\tof\tyear\t–\t2004 | – | – | – | – | – | – |

(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) Reserves	represent	the	transfer	of	certain	mineral	interests	on	the	dissolution	of	MKM	Partners,	L.P.

(d) Excludes	the	resale	of	purchased	gas	utilized	in	reservoir	management.

# 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	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	also	could	affect	the	amount	of	cash	eventually	realized.

								Future	development	and	production,	transportation	and	administrative	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.	Permanent	differences	in	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 | United<br>States | Europe | Africa | Other<br>Int'l. | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2004: |  |  |  |  |  |
| Future\tcash\tinflows | $12,377 | $7,742 | $5,709 | $750 | $26,578 |
| Future\tproduction,\ttransportation\tand\tadministrative\tcosts | (4,337) | (1,950) | (951) | (565) | (7,803) |
| Future\tdevelopment\tcosts | (585) | (1,801) | (294) | (82) | (2,762) |
| Future\tincome\ttax\texpenses | (2,581) | (1,753) | (1,265) | (16) | (5,615) |
| Future\tnet\tcash\tflows | $4,874 | $2,238 | $3,199 | $87 | $10,398 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (1,740) | (737) | (1,419) | (33) | (3,929) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil |  |  |  |  |  |
| (a) |  |  |  |  |  |
| and\tgas\treserves | $3,134 | $1,501 | $1,780 | $54 | $6,469 |
| 2003: |  |  |  |  |  |
| Future\tcash\tinflows | $13,331 | $3,955 | $4,471 | $1,593 | $23,350 |
| Future\tproduction,\ttransportation\tand\tadministrative\tcosts | (4,919) | (1,050) | (1,161) | (827) | (7,957) |
| Future\tdevelopment\tcosts | (758) | (435) | (175) | (229) | (1,597) |
| Future\tincome\ttax\texpenses | (2,612) | (870) | (780) | (163) | (4,425) |
| Future\tnet\tcash\tflows | 5,042 | 1,600 | 2,355 | 374 | 9,371 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (1,789) | (301) | (1,112) | (168) | (3,370) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil |  |  |  |  |  |
| (a) |  |  |  |  |  |
| and\tgas\treserves | $3,253 | $1,299 | $1,243 | $206 | $6,001 |
| Share\tof\tequity\tinvestee's\tstandardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash |  |  |  |  |  |
| flow | $– | $– | $– | $8 | $8 |
| 2002: |  |  |  |  |  |
| Future\tcash\tinflows | $12,994 | $4,256 | $4,136 | $83 | $21,469 |
| Future\tproduction,\ttransportation\tand\tadministrative\tcosts | (5,103) | (1,218) | (1,097) | (30) | (7,448) |
| Future\tdevelopment\tcosts | (650) | (351) | (324) | (4) | (1,329) |
| Future\tincome\ttax\texpenses | (2,440) | (989) | (753) | (27) | (4,209) |
| Future\tnet\tcash\tflows | 4,801 | 1,698 | 1,962 | 22 | 8,483 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (1,639) | (444) | (954) | (5) | (3,042) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil |  |  |  |  |  |
| (a) |  |  |  |  |  |
| and\tgas\treserves | $3,162 | $1,254 | $1,008 | $17 | $5,441 |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil |  |  |  |  |  |
| and\tgas\treserves\tof\tdiscontinued\toperations | $– | $– | $– | $384 | $384 |
| Share\tof\tequity\tinvestee's\tstandardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash |  |  |  |  |  |
| flows | $456 | $36 | $– | $– | $492 |

(a) Excludes	$0	million,	$(26)	million	and	$(5)	million	of	discounted	future	net	cash	flows	from	the	effects	of	hedging	transactions	for	2004,	2003	and	2002,	respectively.

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

|  | 2004 | 2003 | 2002 |
| :--- | :--- | :--- | :--- |
| Sales\tand\ttransfers\tof\toil\tand\tgas\tproduced,\tnet\tof\tproduction,\ttransportation,\tand\tadministrative\tcosts | $(2,715) | $(2,487) | $(1,983) |
| Net\tchanges\tin\tprices\tand\tproduction,\ttransportation\tand\tadministrative\tcosts\trelated\tto\tfuture\tproduction | 950 | 1,178 | 2,795 |
| Extensions,\tdiscoveries\tand\timproved\trecovery,\tless\trelated\tcosts | 1,352 | 618 | 1,032 |
| Development\tcosts\tincurred\tduring\tthe\tperiod | 711 | 802 | 499 |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | (556) | (478) | (297) |
| Revisions\tof\tprevious\tquantity\testimates | 494 | 348 | 311 |
| Net\tchanges\tin\tpurchases\tand\tsales\tof\tminerals\tin\tplace | 33 | (531) | 737 |
| Net\tchange\tin\texchanges\tof\tminerals\tin\tplace | – | 403 | – |
| Accretion\tof\tdiscount | 790 | 807 | 417 |
| Net\tchange\tin\tincome\ttaxes | (529) | 65 | (1,288) |
| Timing\tand\tother | (62) | (165) | 2 |
| Net\tchange\tfor\tthe\tyear | 468 | 560 | 2,225 |
| Beginning\tof\tyear | 6,001 | 5,441 | 3,216 |
| End\tof\tyear | $6,469 | $6,001 | $5,441 |
| Net\tchange\tfor\tthe\tyear\tfrom\tdiscontinued\toperations | $– | $(384) | $212 |

| Northern | Northern | 25 | 26 | 28 | 29 | 30 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Southern | Southern | 56 | 81 | 89 | 98 | 101 |
| Total\tUnited\tStates | Total\tUnited\tStates | 81 | 107 | 117 | 127 | 131 |
| International |  |  |  |  |  |  |
| Australia | Australia | – | 1 | 1 | – | – |
| Egypt | Egypt | – | – | – | – | 1 |
| Equatorial\tGuinea | Equatorial\tGuinea | 19 | 12 | 8 | – | – |
| Gabon | Gabon | 13 | 15 | 17 | 16 | 16 |
| Norway | Norway | 2 | 1 | 1 | – | – |
| United\tKingdom | United\tKingdom | 38 | 40 | 51 | 46 | 29 |
| Russian\tFederation | Russian\tFederation | 16 | 9 | – | – | – |
| Total\tInternational | Total\tInternational | 88 | 78 | 78 | 62 | 46 |
|  | Consolidated | 169 | 185 | 195 | 189 | 177 |
| Equity\tinvestee | Equity\tinvestee | 1 | 6 | 8 | 9 | 11 |
|  | Total\tContinuing\tOperations | 170 | 191 | 203 | 198 | 188 |
|  | Discontinued\tOperations | – | 3 | 4 | 11 | 19 |
|  | Worldwide\tTotal | 170 | 194 | 207 | 209 | 207 |
| Natural\tgas\tliquids\tincluded\tin\tabove | Natural\tgas\tliquids\tincluded\tin\tabove | 15 | 18 | 20 | 19 | 22 |
|  | (a) |  |  |  |  |  |
| Net\tNatural\tGas\tProduction | (millions\tof\tcubic\tfeet\tper\tday) |  |  |  |  |  |
| United\tStates\t(by\tbusiness\tunit) |  |  |  |  |  |  |
| Northern | Northern | 367 | 392 | 405 | 397 | 363 |
| Southern | Southern | 264 | 340 | 340 | 396 | 368 |
| Total\tUnited\tStates | Total\tUnited\tStates | 631 | 732 | 745 | 793 | 731 |
| International |  |  |  |  |  |  |
| Equatorial\tGuinea | Equatorial\tGuinea | 76 | 66 | 53 | – | – |
| Ireland | Ireland | 58 | 62 | 81 | 79 | 115 |
| Norway | Norway | 27 | 16 | 15 | 5 | – |
| United\tKingdom\t–\tequity | United\tKingdom\t–\tequity | 188 | 184 | 203 | 234 | 212 |
|  | (b) |  |  |  |  |  |
| \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 | \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 | 19 | 23 | 4 | 8 | 11 |
| Total\tInternational | Total\tInternational | 368 | 351 | 356 | 326 | 338 |
|  | Consolidated | 999 | 1,083 | 1,101 | 1,119 | 1,069 |
| Equity\tinvestee | Equity\tinvestee | – | 13 | 25 | 31 | 29 |
|  | Total\tContinuing\tOperations | 999 | 1,096 | 1,126 | 1,150 | 1,098 |
|  | Discontinued\tOperations | – | 74 | 104 | 123 | 143 |
|  | Worldwide\tTotal | 999 | 1,170 | 1,230 | 1,273 | 1,241 |
| Average\tSales\tPrices | (c) |  |  |  |  |  |
| Liquid\tHydrocarbons\t(dollars\tper\tbarrel) |  |  |  |  |  |  |
| United\tStates | United\tStates | $32.76 | $26.92 | $22.18 | $20.62 | $25.55 |
| International | International | 33.82 | 26.45 | 23.86 | 23.74 | 27.72 |
|  | Consolidated | 33.31 | 26.72 | 22.86 | 21.65 | 26.12 |
| Equity\tinvestee | Equity\tinvestee | 21.10 | 25.91 | 24.59 | 23.41 | 29.64 |
|  | Total\tContinuing\tOperations | 33.24 | 26.70 | 22.93 | 21.73 | 26.32 |
|  | Discontinued\tOperations | – | 28.96 | 23.29 | 21.26 | 24.28 |
|  | Worldwide | 33.24 | 26.73 | 22.94 | 21.71 | 26.14 |
| Natural\tGas\t(dollars\tper\tthousand\tcubic\tfeet) |  |  |  |  |  |  |
| United\tStates | United\tStates | $4.89 | $4.53 | $2.87 | $3.69 | $3.49 |
| International | International | 3.33 | 2.77 | 2.30 | 2.78 | 2.57 |
|  | Consolidated | 4.31 | 3.96 | 2.69 | 3.42 | 3.20 |
| Equity\tinvestee | Equity\tinvestee | – | 3.70 | 3.05 | 3.39 | 2.75 |
|  | Total\tContinuing\tOperations | 4.31 | 3.95 | 2.70 | 3.42 | 3.18 |
|  | Discontinued\tOperations | – | 5.43 | 3.30 | 4.17 | 3.89 |
|  | Worldwide | 4.31 | 4.05 | 2.75 | 3.49 | 3.27 |
| Net\tProved\tReserves\tat\tyear-end | (developed\tand\tundeveloped) |  |  |  |  |  |
| Liquid\tHydrocarbons\t(millions\tof\tbarrels) |  |  |  |  |  |  |
| United\tStates | United\tStates | 191 | 210 | 245 | 268 | 458 |
| International | International | 369 | 366 | 292 | 118 | 259 |
|  | Consolidated | 560 | 576 | 537 | 386 | 717 |
| Equity\tinvestee | Equity\tinvestee | – | 2 | 183 | 184 | – |
|  | Total | 560 | 578 | 720 | 570 | 717 |
| Developed\treserves\tas\ta\tpercentage\tof\ttotal\tnet\treserves | Developed\treserves\tas\ta\tpercentage\tof\ttotal\tnet\treserves | 69% | 68% | 82% | 90% | 76% |
| Natural\tGas\t(billions\tof\tcubic\tfeet) |  |  |  |  |  |  |
| United\tStates | United\tStates | 1,364 | 1,635 | 1,724 | 1,793 | 1,914 |
| International | International | 2,108 | 1,149 | 1,594 | 1,014 | 1,091 |
|  | Consolidated | 3,472 | 2,784 | 3,318 | 2,807 | 3,005 |
| Equity\tinvestee | Equity\tinvestee | – | – | 59 | 51 | 89 |
|  | Total | 3,472 | 2,784 | 3,377 | 2,858 | 3,094 |
| Developed\treserves\tas\ta\tpercentage\tof\ttotal\tnet\treserves | Developed\treserves\tas\ta\tpercentage\tof\ttotal\tnet\treserves | 56% | 72% | 74% | 74% | 78% |

(a) Amounts	represent	production	after	royalties,	excluding	the	UK,	Ireland	and	the	Netherlands	where	amounts	are	shown	before	royalties.

(b) Represents	gas	acquired	for	injection	and	subsequent	resale.

(c) Prices	exclude	derivative	gains	and	losses.

|  |  |  | 2004^(a) | 2003^(a) | 2002^(a) | 2001^(a) | 2000^(a) |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Refinery\tOperations\t(thousands\tof\tbarrels\tper\tday) |  |  |  |  |  |  |  |
| In-use\tcrude\toil\tcapacity\tat\tyear-end |  |  | 948 | 935 | 935 | 935 | 935 |
| Refinery\truns\t–\tcrude\toil\trefined | Refinery\truns\t–\tcrude\toil\trefined | Refinery\truns\t–\tcrude\toil\trefined | 939 | 917 | 906 | 929 | 900 |
| \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\tcharge\tand\tblend\tstocks | \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\tcharge\tand\tblend\tstocks | \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\tcharge\tand\tblend\tstocks | 171 | 138 | 148 | 143 | 141 |
| In-use\tcrude\toil\tcapacity\tutilization\trate | In-use\tcrude\toil\tcapacity\tutilization\trate | In-use\tcrude\toil\tcapacity\tutilization\trate | 99% | 98% | 97% | 99% | 96% |
| Source\tof\tCrude\tProcessed\t(thousands\tof\tbarrels\tper\tday) |  |  |  |  |  |  |  |
| United\tStates | United\tStates | United\tStates | 416 | 422 | 433 | 403 | 400 |
| Canada | Canada | Canada | 130 | 122 | 114 | 115 | 102 |
| Middle\tEast\tand\tAfrica | Middle\tEast\tand\tAfrica | Middle\tEast\tand\tAfrica | 276 | 266 | 232 | 347 | 346 |
| Other\tInternational | Other\tInternational | Other\tInternational | 117 | 107 | 127 | 64 | 52 |
| Total | Total | Total | 939 | 917 | 906 | 929 | 900 |
| Refined\tProduct\tYields\t(thousands\tof\tbarrels\tper\tday) |  |  |  |  |  |  |  |
| Gasoline | Gasoline | Gasoline | 608 | 567 | 581 | 581 | 552 |
| Distillates | Distillates | Distillates | 299 | 284 | 285 | 286 | 278 |
| Propane | Propane | Propane | 22 | 21 | 21 | 22 | 20 |
| Feedstocks\tand\tspecial\tproducts | Feedstocks\tand\tspecial\tproducts | Feedstocks\tand\tspecial\tproducts | 94 | 93 | 80 | 69 | 74 |
| Heavy\tfuel\toil | Heavy\tfuel\toil | Heavy\tfuel\toil | 25 | 24 | 20 | 39 | 43 |
| Asphalt | Asphalt | Asphalt | 77 | 72 | 72 | 76 | 74 |
| Total | Total | Total | 1,125 | 1,061 | 1,059 | 1,073 | 1,041 |
| Refined\tProduct\tSales\tVolumes\t(thousands\tof\tbarrels\tper\tday)^(b) |  |  |  |  |  |  |  |
| Gasoline | Gasoline | Gasoline | 807 | 776 | 773 | 748 | 746 |
| Distillates | Distillates | Distillates | 373 | 365 | 346 | 345 | 352 |
| Propane | Propane | Propane | 22 | 21 | 22 | 21 | 21 |
| Feedstocks\tand\tspecial\tproducts | Feedstocks\tand\tspecial\tproducts | Feedstocks\tand\tspecial\tproducts | 92 | 97 | 82 | 71 | 69 |
| Heavy\tfuel\toil | Heavy\tfuel\toil | Heavy\tfuel\toil | 27 | 24 | 20 | 41 | 43 |
| Asphalt | Asphalt | Asphalt | 79 | 74 | 75 | 78 | 75 |
| Total | Total | Total | 1,400 | 1,357 | 1,318 | 1,304 | 1,306 |
| Matching\tbuy/sell\tvolumes\tincluded\tin\tabove |  |  | 71 | 64 | 71 | 45 | 52 |
| Refined\tProducts\tSales\tVolumes\tby\tClass\tof\tTrade | Refined\tProducts\tSales\tVolumes\tby\tClass\tof\tTrade | \t(as\ta\t%\tof\ttotal\tsales\tvolumes) |  |  |  |  |  |
| Wholesale\t&amp;\tSpot\tmarket\t–\tindependent\tprivate-brand |  |  |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tmarketers\tand\tconsumers | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tmarketers\tand\tconsumers | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\tmarketers\tand\tconsumers | 72% | 71% | 69% | 66% | 65% |
| Marathon\tand\tAshland\tbrand\tjobbers\tand\tdealers | Marathon\tand\tAshland\tbrand\tjobbers\tand\tdealers | Marathon\tand\tAshland\tbrand\tjobbers\tand\tdealers | 13 | 13 | 13 | 13 | 12 |
| Speedway\tSuperAmerica\tretail\toutlets | Speedway\tSuperAmerica\tretail\toutlets | Speedway\tSuperAmerica\tretail\toutlets | 15 | 16 | 18 | 21 | 23 |
| Total | Total | Total | 100% | 100% | 100% | 100% | 100% |
| Refined\tProducts\t(dollars\tper\tbarrel) |  |  |  |  |  |  |  |
| Average\tsales\tprice | Average\tsales\tprice | Average\tsales\tprice | $49.53 | $38.55 | $32.26 | $34.54 | $38.24 |
| Average\tcost\tof\tcrude\toil\tthroughput | Average\tcost\tof\tcrude\toil\tthroughput | Average\tcost\tof\tcrude\toil\tthroughput | $39.16 | $29.77 | $25.41 | $23.47 | $29.07 |
| Refining\tand\tWholesale\tMarketing\tMargin | (dollars\tper\tgallon) | (c) | $.0877 | $.0603 | $.0387 | $.1167 | $.0788 |
| Refined\tProduct\tMarketing\tOutlets\tat\tyear-end |  |  |  |  |  |  |  |
| MAP\toperated\tterminals | MAP\toperated\tterminals | MAP\toperated\tterminals | 84 | 88 | 86 | 87 | 89 |
| Retail\t–\tMarathon\tand\tAshland\tbrand | Retail\t–\tMarathon\tand\tAshland\tbrand | Retail\t–\tMarathon\tand\tAshland\tbrand | 3,912 | 3,885 | 3,822 | 3,800 | 3,728 |
| (d) |  |  |  |  |  |  |  |
| \t\t\t\t\t\t\t\t\t\t\t–\tSpeedway\tSuperAmerica | \t\t\t\t\t\t\t\t\t\t\t–\tSpeedway\tSuperAmerica | \t\t\t\t\t\t\t\t\t\t\t–\tSpeedway\tSuperAmerica | 1,669 | 1,775 | 2,006 | 2,104 | 2,148 |
| (d) |  |  |  |  |  |  |  |
| Speedway\tSuperAmerica |  |  |  |  |  |  |  |
| Gasoline\t&amp;\tdistillates\tsales\t(millions\tof\tgallons) | Gasoline\t&amp;\tdistillates\tsales\t(millions\tof\tgallons) | Gasoline\t&amp;\tdistillates\tsales\t(millions\tof\tgallons) | 3,152 | 3,332 | 3,604 | 3,572 | 3,732 |
| Gasoline\t&amp;\tdistillates\tgross\tmargin\t(dollars\tper\tgallon) | Gasoline\t&amp;\tdistillates\tgross\tmargin\t(dollars\tper\tgallon) | Gasoline\t&amp;\tdistillates\tgross\tmargin\t(dollars\tper\tgallon) | $.1186 | $.1229 | $.1007 | $.1206 | $.1261 |
| Merchandise\tsales\t(millions) | Merchandise\tsales\t(millions) | Merchandise\tsales\t(millions) | $2,335 | $2,244 | $2,380 | $2,253 | $2,160 |
| Merchandise\tgross\tmargin\t(millions) | Merchandise\tgross\tmargin\t(millions) | Merchandise\tgross\tmargin\t(millions) | $571 | $555 | $576 | $527 | $510 |
| Petroleum\tInventories\tat\tyear-end\t(thousands\tof\tbarrels) |  |  |  |  |  |  |  |
| Crude\toil,\traw\tmaterials\tand\tnatural\tgas\tliquids | Crude\toil,\traw\tmaterials\tand\tnatural\tgas\tliquids | Crude\toil,\traw\tmaterials\tand\tnatural\tgas\tliquids | 31,577 | 31,862 | 32,600 | 32,741 | 33,884 |
| Refined\tproducts | Refined\tproducts | Refined\tproducts | 38,653 | 37,650 | 37,729 | 36,310 | 34,386 |
| Pipelines\t(miles\tof\tcommon\tcarrier\tpipelines) | (e) |  |  |  |  |  |  |
| Crude\tOil\t–\tgathering\tlines | Crude\tOil\t–\tgathering\tlines | Crude\tOil\t–\tgathering\tlines | 68 | 68 | 200 | 271 | 419 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\ttrunklines | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\ttrunklines | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\ttrunklines | 3,893 | 4,105 | 4,459 | 4,511 | 4,623 |
| Products\t\t\t–\ttrunklines | Products\t\t\t–\ttrunklines | Products\t\t\t–\ttrunklines | 3,850 | 3,861 | 3,732 | 2,847 | 2,834 |
| Total | Total | Total | 7,811 | 8,034 | 8,391 | 7,629 | 7,876 |
| Pipeline\tBarrels\tHandled\t(in\tmillions)^(f) |  |  |  |  |  |  |  |
| Crude\tOil\t–\tgathering\tlines | Crude\tOil\t–\tgathering\tlines | Crude\tOil\t–\tgathering\tlines | .6 | 12.7 | 14.1 | 16.3 | 22.7 |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\ttrunklines | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\ttrunklines | \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\ttrunklines | 564.0 | 583.3 | 575.7 | 570.6 | 563.6 |
| Products\t\t–\ttrunklines | Products\t\t–\ttrunklines | Products\t\t–\ttrunklines | 406.8 | 371.3 | 367.6 | 345.6 | 329.7 |
| Total | Total | Total | 971.4 | 967.3 | 957.4 | 932.5 | 916.0 |
| River\tOperations |  |  |  |  |  |  |  |
| Barges\t–\towned/leased | Barges\t–\towned/leased | Barges\t–\towned/leased | 167 | 155 | 150 | 156 | 158 |
| Boats\t–\towned/leased | Boats\t–\towned/leased | Boats\t–\towned/leased | 9 | 7 | 7 | 8 | 7 |

(b) Total	average	daily	volumes	of	all	refined	product	sales	to	MAP's	wholesale,	branded	and	retail	(SSA)	customers.

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

(d) Excludes	travel	centers	contributed	to	Pilot	Travel	Centers	LLC.	Periods	prior	to	September	1,	2001	have	been	restated.

(e) Pipelines	for	downstream	operations	also	include	non-common	carrier,	leased	and	equity	investees.

(f) Pipeline	barrels	handled	on	owned	common	carrier	pipelines,	excluding	equity	investees.

# (Dollars	in	millions,	except	as	noted)

|  | 2004 | 2003 | 2002 | 2001 | 2000 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Revenues\tand\tOther\tIncome |  |  |  |  |  |
| Revenues\tby\tproduct: |  |  |  |  |  |
| Refined\tproducts | $29,780 | $24,092 | $19,729 | $20,841 | $22,513 |
| Merchandise | 2,489 | 2,395 | 2,521 | 2,506 | 2,441 |
| Liquid\thydrocarbons | 13,860 | 10,500 | 6,517 | 6,502 | 6,697 |
| Natural\tgas | 3,266 | 3,796 | 2,362 | 2,801 | 2,317 |
| Transportation\tand\tother\tproducts | 203 | 180 | 166 | 146 | 151 |
| Total\trevenues | 49,598 | 40,963 | 31,295 | 32,796 | 34,119 |
| Gain\t(loss)\ton\townership\tchange\tin\tMAP | 2 | (1) | 12 | (6) | 12 |
| Other^(a) | 307 | 272 | 248 | 272 | (645) |
| Total\trevenues\tand\tother\tincome | $49,907 | $41,234 | $31,555 | $33,062 | $33,486 |
| Income\tFrom\tOperations |  |  |  |  |  |
| Exploration\tand\tproduction |  |  |  |  |  |
| Domestic | $1,073 | $1,155 | $726 | $1,150 | $1,132 |
| International | 623 | 425 | 333 | 229 | 305 |
| E&amp;P\tsegment\tincome | 1,696 | 1,580 | 1,059 | 1,379 | 1,437 |
| Refining,\tmarketing\tand\ttransportation | 1,406 | 819 | 372 | 1,927 | 1,284 |
| Integrated\tgas | 48 | (3) | 23 | 21 | 10 |
| Segment\tincome | 3,150 | 2,396 | 1,454 | 3,327 | 2,731 |
| Items\tnot\tallocated\tto\tsegments: |  |  |  |  |  |
| Administrative\texpenses | (307) | (227) | (194) | (187) | (154) |
| Gain\ton\tdisposal\tof\tassets | – | 106 | 24 | – | 124 |
| Joint\tventure\tformation\tcharges | – | – | – | – | (931) |
| Inventory\tmarket\tvaluation\tadjustments | – | – | 71 | (71) | – |
| Gain\t(loss)\ton\townership\tchange\tin\tsubsidiaries | 2 | (1) | 12 | (6) | 12 |
| Impairment\tof\tcertain\toil\tand\tgas\tproperties | (44) | – | – | – | (5) |
| Loss\ton\tdissolution\tof\tMKM\tPartners\tLLP | – | (124) | – | – | – |
| Gain\t(loss)\ton\tU.K.\tlong-term\tgas\tcontracts | (99) | (66) | 18 | – | – |
| Corporate\tinsurance\tadjustment | (32) | – | – | – | – |
| Other\titems | – | – | (15) | 45 | (70) |
| Income\tfrom\toperations | 2,670 | 2,084 | 1,370 | 3,108 | 1,707 |
| Minority\tinterest\tin\tincome\tof\tMAP | 532 | 302 | 173 | 704 | 498 |
| Minority\tinterest\tin\tloss\tof\tEGHoldings | (7) | – | – | – | – |
| Net\tinterest\tand\tother\tfinancing\tcosts | 161 | 186 | 321 | 172 | 238 |
| Provision\tfor\tincome\ttaxes | 727 | 584 | 369 | 827 | 536 |
| Income\tFrom\tContinuing\tOperations | $1,257 | $1,012 | $507 | $1,405 | $435 |
| Per\tcommon\tshare\t–\tbasic\t(in\tdollars) | 3.74 | 3.26 | 1.63 | 4.54 | 1.40 |
| \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–\tdiluted\t(in\tdollars) | 3.72 | 3.26 | 1.63 | 4.54 | 1.40 |
| Net\tIncome | 1,261 | 1,321 | 516 | 377 | 432 |
| Per\tcommon\tshare\t–\tbasic\t(in\tdollars) | 3.75 | 4.26 | 1.66 | 1.22 | 1.39 |
| \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–\tdiluted\t(in\tdollars) | 3.73 | 4.26 | 1.66 | 1.22 | 1.39 |
| Balance\tSheet\tPosition\tat\tyear-end |  |  |  |  |  |
| Current\tassets | $8,867 | $6,040 | $4,479 | 4,411 | $4,985 |
| Net\tinvestment\tin\tUnited\tStates\tSteel | – | – | – | – | 1,919 |
| Net\tproperty,\tplant\tand\tequipment | 11,810 | 10,830 | 10,390 | 9,552 | 9,346 |
| Total\tassets | 23,423 | 19,482 | 17,812 | 16,129 | 17,151 |
| Short-term\tdebt | 16 | 272 | 161 | 215 | 228 |
| Other\tcurrent\tliabilities | 5,237 | 3,935 | 3,498 | 3,253 | 3,784 |
| Long-term\tdebt | 4,057 | 4,085 | 4,410 | 3,432 | 1,937 |
| Minority\tinterest\tin\tsubsidiaries | 2,690 | 2,011 | 1,971 | 1,963 | 1,840 |
| Common\tstockholders'\tequity | 8,111 | 6,075 | 5,082 | 4,940 | 6,764 |
| Cash\tFlow\tData\t–\tContinuing\tOperations |  |  |  |  |  |
| Net\tcash\tfrom\toperating\tactivities | $3,730 | $2,665 | $2,331 | $2,749 | $2,947 |
| Capital\texpenditures | 2,237 | 1,892 | 1,520 | 1,533 | 1,296 |
| Disposal\tof\tassets | 76 | 644 | 146 | 83 | 550 |
| Dividends\tpaid | 348 | 298 | 285 | 284 | 274 |
| Dividends\tpaid\tper\tshare | 1.03 | .96 | .92 | .92 | .88 |
| Employee\tData |  |  |  |  |  |
| Marathon: |  |  |  |  |  |
| Total\temployment\tcosts | $1,672 | $1,560 | $1,481 | $1,498 | $1,474 |
| Average\tnumber\tof\temployees | 26,580 | 27,677 | 28,237 | 30,791 | 31,515 |
| Number\tof\tpensioners\tat\tyear-end | 3,117 | 3,291 | 3,122 | 3,105 | 3,255 |
| Speedway\tSuperAmerica\tLLC: |  |  |  |  |  |
| (Included\tin\tMarathon\ttotals) |  |  |  |  |  |
| Total\temployment\tcosts | $446 | $464 | $480 | $496 | $489 |
| Average\tnumber\tof\temployees | 17,077 | 17,911 | 18,943 | 21,449 | 21,649 |
| Number\tof\tpensioners\tat\tyear-end | 245 | 234 | 214 | 205 | 211 |
| Stockholder\tData\tat\tyear-end |  |  |  |  |  |
| Number\tof\tcommon\tshares\toutstanding\t(in\tmillions) | 346.7 | 310.4 | 309.9 | 309.4 | 308.3 |
| Registered\tshareholders\t(in\tthousands) | 58.6 | 61.9 | 66.4 | 69.7 | 65.0 |
| Market\tprice\tof\tcommon\tstock | $37.61 | $33.09 | $21.29 | $30.00 | $27.75 |

(a) Includes	income	from	equity	method	investments,	net	gains	(losses)	on	disposal	of	assets	and	other	income.

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

# Item	9A.	Controls	and	Procedures

# Disclosure	Controls	and	Procedures

								An	evaluation	of	the	effectiveness	of	the	design	and	operation	of	our	disclosure	controls	and	procedures	(as	defined	in	Rules	13a-15(e)	and	15d-15(e)	under	the Securities	and	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,	and	that	there	were	no	significant	changes	in	our	internal	controls	or in	other	factors	that	could	significantly	affect	internal	controls	subsequent	to	the	date	of	their	evaluation.

# Internal	Controls

								See	"Management's	Report	on	Internal	Control	over	Financial	Reporting"	on	page	F-2.

# Item	9B.	Other	Information

# Disclosure	of	Previously	Unreported	Form	8-K	Events

								The	following	disclosures	would	otherwise	have	been	filed	on	Form	8-K	under	the	heading	"Item	1.01.	Entry	into	a	Material	Definitive	Agreement."

								Attached	hereto	as	Exhibit	10.28	and	incorporated	herein	by	reference,	Marathon	is	reporting	a	summary	of	non-employee	director	compensation	effective January	1,	2005.	In	2004,	the	Corporate	Governance	and	Nominating	Committee	commissioned	an	independent	compensation	consulting	firm	to	conduct	a	review	of director	compensation.	Based	on	the	results	of	this	review	and	at	its	meeting	on	September	30,	2004,	the	Board	of	Directors	approved	a	$20,000	increase	to	the	annual non-retainer	common	stock	unit	award	effective	in	2005.

								Attached	hereto	as	Exhibit	10.29	and	incorporated	herein	by	reference,	Marathon	is	reporting	a	summary	of	named	executive	officer	compensation	and	2005 annual	bonus	performance	criteria.	At	its	meeting	on	February	22,	2005,	the	Compensation	Committee	approved	cash	bonus	payments	for	2004	in	accordance	with	the performance-based	bonus	program	established	during	the	first	quarter	of	2004	under	our	stockholder-approved	2003	Incentive	Compensation	Plan.	The	Committee	also approved	base	salaries	effective	April	1,	2005	and	the	performance	criteria	for	the	officers'	2005	annual	bonus	program	under	the	2003	Incentive	Compensation	Plan.

# PART	III

# Item	10.	Directors	and	Executive	Officers	of	The	Registrant

								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	dated	March	10,	2005,	for	the	2005	Annual	Meeting	of	stockholders.

								Marathon's	Board	of	Directors	has	established	the	Audit	Committee	and	determined	our	"Audit	Committee	Financial	Expert."	The	information	required	to	be disclosed	is	incorporated	by	reference	to	the	material	appearing	under	the	sub-heading	"Audit	Committee"	located	under	the	heading	"The	Board	of	Directors	and Governance	Matters"	in	Marathon's	Proxy	Statement	dated	March	10,	2005,	for	the	2005	Annual	Meeting	of	Stockholders.

								Marathon	has	adopted	a	Code	of	Ethics	for	Senior	Financial	Officers.	It	is	available	on	our	website	at	www.marathon.com/Code		Ethics		Sr		Finan		Off/.

# Executive	Officers	of	the	Registrant

								The	executive	officers	of	Marathon	or	its	subsidiaries	and	their	ages	as	of	February	1,	2005,	are	as	follows:

Paul	C.	Reinbolt 49 Vice	President,	Finance	and	Treasurer

William	F.	Schwind,	Jr. 60 Vice	President,	General	Counsel	and	Secretary

								With	the	exception	of	Mr.	Cazalot,	Mr.	Behrman,	Ms.	Clark,	Mr.	Kaplan	and	Mr.	Lowden	mentioned	above,	all	of	the	executive	officers	have	held	responsible management	or	professional	positions	with	Marathon	or	its	subsidiaries	for	more	than	the	past	five	years.

								Mr.	Cazalot	joined	Marathon	Oil	Company	as	president	in	March	2000.	In	January	of	2002,	he	was	appointed	president	and	chief	executive	officer	of	Marathon	Oil Corporation.	Prior	to	joining	Marathon,	Mr.	Cazalot	served	from	1999	to	2000	as	vice	president	of	Texaco	Inc.	and	president	of	Texaco's	worldwide	production operations.

								Prior	to	joining	Marathon	in	September	2000,	Mr.	Behrman	served	from	1996	as	exploration	manager	for	Vastar	Resources	Inc.'s	Gulf	of	Mexico	deepwater division.	During	2000,	Mr.	Behrman	assumed	the	additional	responsibilities	of	acting-vice	president	of	exploration	and	land.

								Ms.	Clark	joined	Marathon	in	January	2004	as	senior	vice	president	and	chief	financial	officer.	Prior	to	joining	Marathon,	she	was	employed	by	Nuevo	Energy Company	from	2001	to	December	2003	as	senior	vice	president	and	chief	financial	officer.	Prior	to	her	employment	with	Nuevo	Energy	Company,	Ms.	Clark	served	as executive	vice	president	of	corporate	development	and	administration	for	Santa	Fe	Snyder	Corporation.

								Mr.	Kaplan	joined	Marathon	in	December	2003	as	vice	president,	major	projects.	Prior	to	joining	Marathon,	he	was	employed	by	Foster	Wheeler	Corporation	since 2001,	with	his	most	recent	position	as	director	of	LNG	for	Foster	Wheeler's	Houston	office.	Prior	thereto	and	since	1995,	he	served	Triton	Energy	Ltd.	(merged	with Amerada	Hess	Corporation)	as	technical	manager	for	the	Thai-Malaysian	development	and	as	project	manager	for	the	Ceiba	field	FPSO	development,	offshore Equatorial	Guinea.

								Prior	to	joining	Marathon	Oil	Company	in	December	2000,	Mr.	Lowden	was	employed	by	Premier	Oil	plc	since	1987,	with	his	most	recent	position	as	director	of commercial	and	business	development	responsible	for	international	business.

# Section	16(a)	Beneficial	Ownership	Reporting	Compliance

								Section	16(a)	of	the	Securities	and	Exchange	Act	of	1934,	as	amended,	requires	that	Marathon's	directors	and	executive	officers,	and	persons	who	own	more	than ten	percent	of	a	registered	class	of	Marathon's	equity	securities,	file	reports	of	beneficial	ownership	on	Form	3	and	changes	in	beneficial	ownership	on	Form	4	or	Form	5 with	the	Securities	and	Exchange	Commission.	Based	solely	on	Marathon's	review	of	the	reporting	forms	and	written	representations	provided	to	Marathon	from	the individuals	required	to	file	reports,	Marathon	believes	that	each	of	its	executive	officers	and	directors	has	complied	with	the	applicable	reporting	requirements	for transactions	in	Marathon's	securities	during	the	fiscal	year	ended	December	31,	2004,	with	the	exception	of	one	late	report	on	Form	4	filed	by	Mr.	Behrman.	This	late report	related	to	the	purchase	of	200	shares	of	common	stock	by	a	family	living	trust,	in	which	Mr.	Behrman's	mother-in-law	is	the	beneficiary	and	his	spouse	is	the trustee	and	has	a	remainder	interest	therein.	Mr.	Behrman	has	disclaimed	beneficial	ownership	of	this	common	stock	to	the	extent	of	his	and/or	his	spouse's	pecuniary interest	therein.

# Item	11.	Executive	Compensation

								Information	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Executive	Compensation	and	Other	Information"	in Marathon's	Proxy	Statement	dated	March	10,	2005,	for	the	2005	Annual	Meeting	of	stockholders.

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

								Information	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	dated	March	10,	2005,	for	the	2005	Annual	Meeting	of	stockholders.

# Equity	Compensation	Plan	Information

								The	following	table	provides	information	as	of	December	31,	2004,	with	respect	to	shares	of	Marathon's	common	stock	that	may	be	issued	under	Marathon's existing	equity	compensation	plans:

# •2003	Incentive	Compensation	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.

•2001	Non-Officer	Restricted	Stock	Plan	–	No	additional	awards	will	be	granted	under	this	plan.

| Plan	category |  | Number	of	securities	to	be<br>issued	upon	exercise	of<br>outstanding	options,<br>warrants	and	rights | Weighted-average<br>exercise	price	of<br>outstanding	options,<br>warrants	and	rights | Number	of	securities	remaining<br>available	for	future	issuance<br>under	equity	compensation<br>plans	(excluding	securities<br>reflected	in	column	(a)) |
| :--- | :--- | :--- | :--- | :--- |
| Equity\tcompensation\tplans |  |  |  |  |
| approved\tby\tstockholders |  | 8,524,265(1) | $29.84 | 15,190,294(2) |
| Equity\tcompensation\tplans\tnot |  |  |  |  |
| approved\tby\tstockholders | (3) | 90,198(4) | N/A | – |
| Total |  | 8,614,463(1) | $29.84 | 15,190,294(2) |

(1) This	number	includes	the	following:

•3,617,193	stock	options	and	SARs	outstanding	under	the	2003	Incentive	Compensation	Plan	(the	"Incentive	Plan")

•476,000	performance	shares	granted	to	officers	under	the	Incentive	Plan	but	not	yet	earned	as	of	December	31,	2004.	The	number	of	shares,	if	any,	to	be	issued	will	be	determined	based	on	a	formula that	measures	Marathon's	total	shareholder	return	over	the	applicable	performance	period	relative	to	the	total	shareholder	return	of	our	industry	peers.

•23,267	phantom	shares	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	Incentive	Plan.	When	a	non-employee	director	leaves	the	Board,	he	or	she	will	be	issued	actual	shares	of	Marathon	common	stock	in	place	of	the	phantom	shares.

•11,750	restricted	stock	phantom	units	granted	to	non-officers	under	the	Incentive	Plan.

The	weighted-average	exercise	price	shown	in	column	(b)	does	not	take	the	officer	performance	shares,	the	phantom	shares	or	restricted	stock	unites	into	account	since	these	awards	have	no	exercise	price.

(2) This	number	reflects	the	shares	available	for	issuance	under	the	Incentive	Plan.	No	more	than	7,380,623	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,	expire	unexercised,	or	settled	in	such	manner	that	all	or	some	of	the	shares	are	not	issued	to	a	participant	shall	immediately	become available	for	issuance.

(3) This	row	reflects	awards	made	under	the	Deferred	Compensation	Plan	for	Non-Employee	Directors	and	the	2001	Non-Officer	Restricted	Stock	Plan	prior	to	April	30,	2003.

•57,243	phantom	shares	that	were	awarded	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	phantom	shares.

•32,955	unvested	phantom	restricted	stock	units	granted	under	the	2001	Non-Officer	Restricted	Stock	Plan	prior	to	April	30,	2003.

								Non-Officer	Restricted	Stock	Plan	–	The	Non-Officer	Restricted	Stock	Plan	was	approved	by	the	Board	effective	January	1,	2001,	to	provide	restricted	stock	and restricted	stock	unit	awards	to	non-officer	employees	of	Marathon	and	its	affiliates.	The	purposes	of	the	plan	are	to	reward	specific	noteworthy	achievements	by	non- officer	employees	and	promote	the	retention	of	outstanding	non-officer	employees.	All	awards	under	this	plan	are	subject	to	a	four-year	time-based	vesting	schedule, with	50	percent	of	the	shares	vesting	two	years	from	the	date	of	grant	and	the	remaining	50	percent	of	the	shares	vesting	four	years	from	the	date	of	grant.	If	a	recipient terminates	employment	other	than	by	reason	of	death,	any	unvested	portion	of	his	or	her	award	will	be	forfeited.	Dividends	are	paid	on	all	awards	made	under	the	plan prior	to	vesting.	Marathon's	authority	to	make	grants	under	this	plan	was	terminated	effective	as	of	April	30,	2003.

								Deferred	Compensation	Plan	for	Non-Employee	Directors	–	Under	the	Deferred	Compensation	Plan	for	Non-Employee	Directors,	all	non-employee	directors	of Marathon	are	required	to	defer	half	of	their	annual	retainers	in	the	form	of	common	stock	units.	On	the	date	the	retainer	would	otherwise	be	payable	to	the	non- employee	director,	Marathon	credits	an	unfunded	bookkeeping	account	for	each	non-employee	director	with	a	number	of	common	stock	units	equal	to	half	of	his	or	her annual	retainer	divided	by	the	fair	market	value	of	Marathon's	common	stock.	The	ongoing	value	of	each	common	stock	unit	equals	the	market	price	of	Marathon's common	stock.	When	dividends	are	paid,	Marathon	credits	each	unfunded	account	with	dividend	equivalents	on	the	number	of	units	then	in	the	individual's	account	in the	form	of	additional	common	stock	units.	When	the	non-employee	director	leaves	the	Board,	he	or	she	is	issued	actual	shares	of	common	stock	equal	to	the	number	of common	stock	units	in	his	or	her	account	at	that	time.	Marathon's	authority	to	make	equity	grants	under	this	plan	was	terminated	effective	as	of	April	30,	2003.

# Item	13.	Certain	Relationships	and	Related	Transactions

								Information	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Certain	Relationships	and	Related	Party	Transactions" in	Marathon's	Proxy	Statement	dated	March	10,	2005,	for	the	2005	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	Public	Auditor's Fees,	Services	and	Independence"	in	Marathon's	Proxy	Statement	dated	March	10,	2005,	for	the	2005	Annual	Meeting	of	stockholders.

# PART	IV

# Item	15.	Exhibits	and	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	listed	under	SEC	rules	but	not	included	in	this	report	are	omitted	because	they	are	not	applicable	or	the	required information	is	contained	in	the	financial	statements	or	notes	thereto.

Schedule	II	–	Valuation	and	Qualifying	Accounts	is	provided	on	page	64.

3. Lists	of	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	December	31,	2001,	the	date	of	the	change	in	the registrant's	name.

# EXHIBIT	INDEX

# 2. Plan	of	Acquisition,	Reorganization,	Arrangement,	Liquidation	or	Succession

2.7 Amendment	No.	2	dated	as	of	March	18,	2004	to	the	Amended	and	Restated	Limited	Liability	Company	Agreement dated	as	of	December	31,	1998	of	Marathon	Ashland	Petroleum	LLC,	by	and	between	Ashland	Inc.	and	Marathon	Oil Company	(incorporated	by	reference	to	Exhibit	2.5	to	Marathon	Oil	Corporation's	Amendment	No.1	to	Form	8-K/A, filed	on	November	29,	2004).

# 3. Articles	of	Incorporation	and	Bylaws

3.1 Restated	Certificate	of	Incorporation	of	Marathon	Oil	Corporation	(incorporated	by	reference	to	Exhibit	3(a)	to Marathon	Oil	Corporation's	Annual	Report	on	Form	10-K	for	the	year	ended	December	31,	2001).

3.2 By-laws	of	Marathon	Oil	Corporation	(incorporated	by	reference	to	Exhibit	3(b)	to	Marathon	Oil	Corporation's	Annual Report	on	Form	10-K	for	the	year	ended	December	31,	2002).

4. Instruments	Defining	the	Rights	of	Security	Holders,	Including	Indentures

4.1 Five	Year	Credit	Agreement	dated	as	of	May	20,	2004	among	Marathon	Oil	Corporation,	the	Co-Agents	and	other Lenders	party	thereto,	Bank	of	America,	N.A.,	as	Syndication	Agent,	ABN	Ambro	Bank	N.V.,	Citibank,	N.A.	and Morgan	Stanley	Bank,	as	Documentation	Agents	and	JPMorgan	Chase	Bank,	as	Administrative	Agent	(incorporated by	reference	to	Exhibit	4.1	to	Marathon	Oil	Corporation's	Form	10-Q	for	the	quarter	ended	June	30,	2004).

4.2 Five	Year	Credit	Agreement	dated	as	of	May	20,	2004	among	Marathon	Ashland	Petroleum	LLC,	the	Co-Agents	and other	Lenders	party	thereto,	Bank	of	America,	N.A.,	as	Syndication	Agent,	ABN	Ambro	Bank	N.V.,	Citibank,	N.A.

and	Morgan	Stanley	Bank,	as	Documentation	Agents	and	JPMorgan	Chase	Bank,	as	Administrative	Agent (incorporated	by	reference	to	Exhibit	4.2	to	Marathon	Oil	Corporation's	Form	10-Q	for	the	quarter	ended	June	30, 2004).

4.3 Senior	Indenture	dated	February	26,	2002	between	Marathon	Oil	Corporation	and	JPMorgan	Chase	Bank,	as	Trustee (incorporated	by	reference	to	Exhibit	4.1	to	Marathon	Oil	Corporation's	Form	8-K,	filed	on	March	4,	2002).

4.4 Senior	Indenture	dated	June	14,	2002	among	Marathon	Global	Funding	Corporation,	as	Issuer,	Marathon	Oil Corporation,	as	Guarantor,	and	JPMorgan	Chase	Bank,	as	Trustee	(incorporated	by	reference	to	Exhibit	4.1	to Marathon	Oil	Corporation's	Form	8-K,	filed	on	June	21,	2002).

4.5 Senior	Supplemental	Indenture	No.	1	dated	as	of	September	5,	2003	among	Marathon	Global	Funding	Corporation,	as Issuer,	Marathon	Oil	Corporation,	as	Guarantor,	and	JPMorgan	Chase	Bank,	as	Trustee	to	the	Indenture	dated	as	of June	14,	2002	(incorporated	by	reference	to	Exhibit	4.2	to	Marathon	Oil	Corporation's	Form	10-Q	for	the	quarter	ended September	30,	2003).

Pursuant	to	CFR	229.601(b)(4)(iii),	instruments	with	respect	to	long-term	debt	issues	have	been	omitted	where	the amount	of	securities	authorized	under	such	instruments	does	not	exceed	10%	of	the	total	consolidated	assets	of Marathon.	Marathon	hereby	agrees	to	furnish	a	copy	of	any	such	instrument	to	the	Commission	upon	its	request.

# 10. Material	Contracts

10.7 Financial	Matters	Agreement	between	USX	Corporation	and	United	States	Steel	LLC	(converted	into	United	States Steel	Corporation)	dated	as	of	December	31,	2001	(incorporated	by	reference	to	Exhibit	99.5	to	Marathon	Oil Corporation's	Form	8-K,	filed	on	January	3,	2002).

10.8 Insurance	Assistance	Agreement	between	USX	Corporation	and	United	States	Steel	LLC	(converted	into	United	States Steel	Corporation)	dated	as	of	December	31,	2001	(incorporated	by	reference	to	Exhibit	99.6	to	Marathon	Oil Corporation's	Form	8-K,	filed	on	January	3,	2002).

10.9 License	Agreement	between	USX	Corporation	and	United	States	Steel	LLC	(converted	into	United	States	Steel Corporation)	dated	as	of	December	31,	2001	(incorporated	by	reference	to	Exhibit	99.7	to	Marathon	Oil	Corporation's Form	8-K,	filed	on	January	3,	2002).

10.10 Marathon	Oil	Corporation	2003	Incentive	Compensation	Plan,	Effective	January	1,	2003	(incorporated	by	reference	to Appendix	C	to	Marathon	Oil	Corporation's	Definitive	Proxy	Statement	on	Schedule	14A	filed	March	10,	2003).

10.13 Form	of	Non-Qualified	Stock	Option	Grant	for	Chief	Executive	Officer	granted	under	Marathon	Oil	Corporation's 1990	Stock	Plan,	as	amended	and	restated	effective	January	1,	2002	(incorporated	by	reference	to	Exhibit	10.2	to Marathon	Oil	Corporation's	Form	10-Q	for	the	quarter	ended	September	30,	2004).

10.14 Form	of	Non-Qualified	Stock	Option	Grant	for	Executive	Officers	granted	under	Marathon	Oil	Corporation's	1990 Stock	Plan,	as	amended	and	restated	effective	January	1,	2002	(incorporated	by	reference	to	Exhibit	10.3	to	Marathon Oil	Corporation's	Form	10-Q	for	the	quarter	ended	September	30,	2004).

10.15 Form	of	Non-Qualified	Stock	Option	with	Tandem	Stock	Appreciation	Right	Award	Agreement	for	Chief	Executive Officer	granted	under	Marathon	Oil	Corporation's	2003	Incentive	Compensation	Plan,	effective	January	1,	2003 (incorporated	by	reference	to	Exhibit	10.4	to	Marathon	Oil	Corporation's	Form	10-Q	for	the	quarter	ended	September 30,	2004).

10.24 Agreement	between	Marathon	Oil	Company	and	Clarence	P.	Cazalot,	Jr.,	executed	February	28,	2000	(incorporated	by reference	to	Exhibit	10(h)	to	Marathon	Oil	Corporation's	Annual	Report	on	Form	10-K	for	the	year	ended	December 31,	2003).

10.27 Letter	Agreement	between	Marathon	Oil	Company	and	Philip	G.	Behrman,	executed	September	19,	2000 (incorporated	by	reference	to	Exhibit	10(l)	to	Marathon	Oil	Corporation's	Annual	Report	on	Form	10-K	for	the	year ended	December	31,	2001).

10.28* Summary	of	non-employee	director	compensation	effective	January	1,	2005.

10.29* Summary	of	Named	Executive	Officer	Compensation	and	Performance	Criteria.

# 12.1* Computation	of	Ratio	of	Earnings	to	Combined	Fixed	Charges	and	Preferred	Stock	Dividends.

# 12.2* Computation	of	Ratio	of	Earnings	to	Fixed	Charges.

# 14.* Code	of	Ethics	for	Senior	Financial	Officers.

# 21.* List	of	Significant	Subsidiaries.

# 23.* Consent	of	Independent	Registered	Public	Accounting	Firm.

# 31.1* Certification	of	President	and	Chief	Executive	Officer	pursuant	to	Rule	13(a)-14	and	15(d)-14	under	the Securities	Exchange	Act	of	1934.

# 31.2* Certification	of	Senior	Vice	President	and	Chief	Financial	Officer	pursuant	to	Rule	13(a)-14	and	15(d)-14	under the	Securities	Exchange	Act	of	1934.

# 32.1* Certification	of	President	and	Chief	Executive	Officer	pursuant	to	18	U.S.C.	Section	1350.

# 32.2* Certification	of	Senior	Vice	President	and	Chief	Financial	Officer	pursuant	to	18	U.S.C.	Section	1350.

Filed	herewith

# Report	of	Independent	Registered	Public	Accounting	Firm	on

# Financial	Statement	Schedule

								Our	audits	of	the	consolidated	financial	statements,	of	management's	assessment	of	the	effectiveness	of	internal	control	over	financial	reporting	and	of	the effectiveness	of	internal	control	over	financial	reporting	referred	to	in	our	report	dated	March	10,	2005,	appearing	in	the	2004	Annual	Report	to	Stockholders	of Marathon	Oil	Corporation	(which	report,	consolidated	financial	statements	and	assessment	are	included	in	this	Annual	Report	on	Form	10-K)	also	included	an	audit	of the	financial	statement	schedule	listed	in	Item	15(a)(2)	of	this	Form	10-K.	In	our	opinion,	this	financial	statement	schedule	presents	fairly,	in	all	material	respects,	the information	set	forth	therein	when	read	in	conjunction	with	the	related	consolidated	financial	statements.

# Schedule	II	–	Valuation	and	Qualifying	Accounts

| (In	millions) | Balance	at<br>Beginning	of<br>Period | Charged	to<br>Cost	and<br>Expenses | Charged<br>to	Other<br>Accounts | Deductions^(a) | Balance	at<br>End	of<br>Period |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tended\tDecember\t31,\t2004 |  |  |  |  |  |
| Reserves\tdeducted\tin\tthe\tbalance\tsheet\tfrom\tthe |  |  |  |  |  |
| assets\tto\twhich\tthey\tapply: |  |  |  |  |  |
| Allowance\tfor\tdoubtful\taccounts\tcurrent | $5 | $13 | $– | $12 | $6 |
| Allowance\tfor\tdoubtful\taccounts\tnoncurrent | 10 | – | – | – | 10 |
| Tax\tvaluation\tallowances: |  |  |  |  |  |
| Federal | 67 | – | – | 10 | 57 |
| State | 73 | – | – | 2 | 71 |
| Foreign | 283 | – | 82(b) | – | 365 |
| Year\tended\tDecember\t31,\t2003 |  |  |  |  |  |
| Reserves\tdeducted\tin\tthe\tbalance\tsheet\tfrom\tthe |  |  |  |  |  |
| assets\tto\twhich\tthey\tapply: |  |  |  |  |  |
| Allowance\tfor\tdoubtful\taccounts\tcurrent | $6 | $10 | $– | $11 | $5 |
| Allowance\tfor\tdoubtful\taccounts\tnoncurrent | 14 | 2 | – | 6 | 10 |
| Tax\tvaluation\tallowances: |  |  |  |  |  |
| Federal | – | – | 67(c) | – | 67 |
| State | 78 | – | – | 5 | 73 |
| (d) |  |  |  |  |  |
| Foreign | 357 | – | – | 74 | 283 |
| Year\tended\tDecember\t31,\t2002 |  |  |  |  |  |
| Reserves\tdeducted\tin\tthe\tbalance\tsheet\tfrom\tthe |  |  |  |  |  |
| assets\tto\twhich\tthey\tapply: |  |  |  |  |  |
| Allowance\tfor\tdoubtful\taccounts\tcurrent | $4 | $13 | $– | $11 | $6 |
| Allowance\tfor\tdoubtful\taccounts\tnoncurrent | 4 | 10 | – | – | 14 |
| Inventory\tmarket\tvaluation\treserve | 72 | – | – | 72 | – |
| Tax\tvaluation\tallowances: |  |  |  |  |  |
| State | 76 | – | 2(b) | – | 78 |
| (d) |  |  |  |  |  |
| Foreign | 259 | – | 98(b) | – | 357 |

(a) Deductions	for	the	allowance	for	doubtful	accounts	and	long-term	receivables	include	amounts	written	off	as	uncollectible,	net	of	recoveries.	Deductions	in	the	inventory	market	valuation	reserve	reflect increases	in	market	prices	and	inventory	turnover,	resulting	in	noncash	credits	to	costs	and	expenses.	Deductions	in	the	state	tax	valuation	allowance	is	due	to	expiring	net	operating	losses.	Deductions	in	the foreign	tax	valuation	allowance	for	2003	relate	to	the	sale	of	the	exploration	and	production	operations	in	western	Canada	and	reduction	in	Norway's	valuation	allowance	due	to	additional	deferred	tax liabilities.	Deductions	in	the	federal	valuation	allowance	reflect	the	amount	of	excess	capital	losses	utilized	during	the	year.

(b) Reflects	valuation	allowances	established	for	deferred	tax	assets	generated	in	the	current	period,	primarily	related	to	net	operating	losses.

(c) Reflects	valuation	allowance	established	for	deferred	tax	assets	generated	in	2003,	resulting	from	excess	capital	losses	related	to	the	sale	of	exploration	and	production	operations	in	western	Canada. (d) In	preparation	of	the	December	31,	2004	consolidated	financial	statements,	Marathon	identified	certain	deferred	tax	liabilities	related	to	Marathon's	Norway	operations	that	were	omitted	from	the	above disclosures	related	to	December	31,	2003,	2002	and	2001.	This	omission	resulted	in	an	understatement	of	the	deferred	tax	liability	primarily	related	to	property,	plant	and	equipment	by	$153	million, $47	million	and	$26	million	at	December	31,	2003,	2002	and	2001	and	a	corresponding	overstatement	of	the	related	valuation	allowance	by	the	same	dollar	amount.	Accordingly,	Marathon	has	revised	the December	31,	2003,	2002	and	2001	presentation	to	increase	the	deferred	tax	liability	by	$153	million,	$47	million	and	$26	million	and	correspondingly	to	decrease	the	valuation	allowance	by	the	same	amount. The	revision	has	no	impact	on	Marathon's	previously	reported	financial	position,	tax	provision,	net	income	or	cash	flow.

								Pursuant	to	the	requirements	of	Section	13	or	15(d)	of	the	Securities	and	Exchange	Act	of	1934,	the	registrant	has	duly	caused	this	report	to	be	signed	on	its	behalf by	the	undersigned,	thereunto	duly	authorized.

March	10,	2005 MARATHON	OIL	CORPORATION

Albert	G.	Adkins

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	March	10,	2005	on	behalf	of	the registrant	and	in	the	capacities	indicated.

Seth	E.	Schofield

/s/		DOUGLAS	C.	YEARLEY

Director

Douglas	C.	Yearley

								The	following	definitions	apply	to	terms	used	in	this	document:



Question: what was the average ending balance in the discounted ending cash flow balance?
Answer: 5970