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TABLE	OF	CONTENTS

Item	8.	Financial	Statements	and	Supplementary	Data

# 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,	2006

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	if	the	registrant	is	a	well-known	seasoned	issuer,	as	defined	in	Rule	405	of	the	Securities	Act.	Yes	þ	No	o

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

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

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

Indicate	by	check	mark	whether	the	registrant	is	a	large	accelerated	filer,	accelerated	filer,	or	a	non-accelerated	filer.	See	definition	of	"accelerated	filer	and large	accelerated	filer"	in	Rule	12b-2	of	the	Exchange	Act.	(Check	one):	Large	accelerated	filer	þ	Accelerated	filer	o	Non-accelerated	filer	o

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

The	aggregate	market	value	of	Common	Stock	held	by	non-affiliates	as	of	June	30,	2006:	$29.924	billion.	This	amount	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	of	the	Securities	Act	of	1933.

There	were	345,862,952	shares	of	Marathon	Oil	Corporation	Common	Stock	outstanding	as	of	January	31,	2007.

# Documents	Incorporated	By	Reference:

Portions	of	the	registrant's	proxy	statement	relating	to	its	2007	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	and	the	Chicago	Stock	Exchange.

								Unless	the	context	otherwise	indicates,	references	in	this	Annual	Report	on	Form	10-K	to	"Marathon,"	"we,"	"our,"	or	"us"	are	references	to	Marathon	Oil Corporation,	including	its	wholly-owned	and	majority-owned	subsidiaries,	and	its	ownership	interests	in	equity	method	investees	(corporate	entities,	partnerships, limited	liability	companies	and	other	ventures	over	which	Marathon	exerts	significant	influence	by	virtue	of	its	ownership	interest,	typically	between	20	and	50	percent). Effective	September	1,	2005,	subsequent	to	the	acquisition	discussed	in	Note	6	to	the	consolidated	financial	statements,	Marathon	Ashland	Petroleum	LLC	changed	its name	to	Marathon	Petroleum	Company	LLC.	References	to	Marathon	Petroleum	Company	LLC	("MPC")	are	references	to	the	entity	formerly	known	as	Marathon Ashland	Petroleum	LLC.

# PART	I

# PART	IV

Exhibits,	Financial	Statement	Schedules

# SIGNATURES

# Disclosures	Regarding	Forward-Looking	Statements

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

								Forward-looking	statements	in	this	Report	may	include,	but	are	not	limited	to,	levels	of	revenues,	gross	margins,	income	from	operations,	net	income	or	earnings per	share;	levels	of	capital,	exploration,	environmental	or	maintenance	expenditures;	the	success	or	timing	of	completion	of	ongoing	or	anticipated	capital,	exploration	or maintenance	projects;	volumes	of	production,	sales,	throughput	or	shipments	of	liquid	hydrocarbons,	natural	gas	and	refined	products;	levels	of	worldwide	prices	of liquid	hydrocarbons,	natural	gas	and	refined	products;	levels	of	reserves,	proved	or	otherwise,	of	liquid	hydrocarbons	and	natural	gas;	the	acquisition	or	divestiture	of assets;	the	effect	of	restructuring	or	reorganization	of	business	components;	the	potential	effect	of	judicial	proceedings	on	our	business	and	financial	condition;	and	the anticipated	effects	of	actions	of	third	parties	such	as	competitors,	or	federal,	foreign,	state	or	local	regulatory	authorities.

# Item	1.	Business

# General

								Marathon	Oil	Corporation	was	originally	organized	in	2001	as	USX	HoldCo,	Inc.,	a	wholly-owned	subsidiary	of	the	former	USX	Corporation.	As	a	result	of	a reorganization	completed	in	July	2001,	USX	HoldCo,	Inc.	(1)	became	the	parent	entity	of	the	consolidated	enterprise	(the	former	USX	Corporation	was	merged	into	a subsidiary	of	USX	HoldCo,	Inc.)	and	(2)	changed	its	name	to	USX	Corporation.	In	connection	with	the	transaction	described	in	the	next	paragraph	(the	"Separation"), USX	Corporation	changed	its	name	to	Marathon	Oil	Corporation.

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

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

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

# Segment	and	Geographic	Information

								Our	operations	consist	of	three	operating	segments:	1)	Exploration	and	Production	("E&P")	–	explores	for,	produces	and	markets	crude	oil	and	natural	gas	on	a worldwide	basis;	2)	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;	and	3)	Integrated	Gas	("IG")	–	markets	and	transports	products	manufactured	from	natural	gas,	such	as	liquefied natural	gas	("LNG")	and	methanol,	on	a	worldwide	basis,	and	is	developing	other	projects	to	link	stranded	natural	gas	resources	with	key	demand	areas.	For	operating segment	and	geographic	financial	information,	see	Note	9	to	the	consolidated	financial	statements.

# Exploration	and	Production

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

								We	conduct	exploration,	development	and	production	activities	in	ten	countries,	with	a	focus	on	international	growth	while	continuing	to	maintain	our	position	in the	United	States.	Principal	exploration	activities	were	in	the	United	States,	Norway,	Angola	and	Indonesia.	Principal	development	and	production	activities	were	in	the United	States,	the	United	Kingdom,	Norway,	Equatorial	Guinea	and	Libya.

								Our	2006	worldwide	net	liquid	hydrocarbon	sales	from	continuing	operations	averaged	223	thousand	barrels	per	day	("mbpd"),	an	increase	of	36	percent	from	2005 levels.	Our	2006	worldwide	net	natural	gas	sales,	including	natural	gas	acquired	for	injection	and	subsequent	resale,	averaged	847	million	cubic	feet	per	day	("mmcfd"), a	decrease	of	9	percent	compared	to	2005.	In	total,	our	2006	worldwide	net	sales	from	continuing	operations	averaged	365	thousand	barrels	of	oil	equivalent	("mboe") per	day,	compared	to	319	mboe	per	day	in	2005.	(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	natural	gas volume	to	obtain	boe.)	In	2007,	our	worldwide	net	production	available	for	sale	is	expected	to	average	390	to	425	mboe	per	day,	excluding	future	acquisitions	and dispositions.

								The	above	projections	of	2007	worldwide	net	liquid	hydrocarbon	and	natural	gas	production	available	for	sale	volumes	are	forward-looking	statements.	Some factors	that	could	potentially	affect	levels	of	production	available	for	sale	include	pricing,	supply	and	demand	for	petroleum	products,	the	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,	inability	to	or	delay	in	obtaining	necessary	government	and	third-party	approvals	and	permits,	unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or terrorist	acts	and	the	governmental	or	military	response,	and	other	geological,	operating	and	economic	considerations.	These	factors	(among	others)	could	cause	actual results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Exploration

								In	the	United	States	during	2006,	we	drilled	33	gross	(16	net)	exploratory	wells	of	which	21	gross	(10	net)	wells	encountered	commercial	quantities	of hydrocarbons.	Of	these	21	wells,	6	gross	(4	net)	wells	were	temporarily	suspended	or	were	in	the	process	of	completing	at	year	end.	Internationally,	we	drilled	21	gross (4	net)	exploratory	wells	of	which	16	gross	(3	net)	wells	encountered	commercial	quantities	of	hydrocarbons.	Of	these	16	wells,	9	gross	(3	net)	wells	were	temporarily suspended	or	were	in	the	process	of	being	completed	at	December	31,	2006.

								United	States		–		The	Gulf	of	Mexico	continues	to	be	a	core	area	for	us.	At	the	end	of	2006,	we	had	interests	in	129	blocks	in	the	Gulf	of	Mexico,	including	100	in the	deepwater	area.

								During	2006,	we	increased	our	interest	from	20	percent	to	30	percent	in	the	Stones	prospect	(Walker	Ridge	Block	508).	An	appraisal	well	is	planned	for	2007	on this	outside-operated	2005	discovery.

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

								A	well	on	the	Flathead	prospect	(Walker	Ridge	Block	30)	in	the	Gulf	of	Mexico	was	suspended	in	2002.	Technical	evaluations	are	complete	and	commercial evaluations	continued	in	2006.	The	drilling	of	this	prospect	is	delayed	due	to	the	shortage	of	available	deepwater	rigs.	We	continue	to	pursue	partnering	opportunities with	other	oil	and	gas	companies	that	have	deepwater	rigs	under	contract.	We	hold	a	100	percent	operated	interest	in	the	Flathead	prospect.

								Norway		–		We	hold	interests	in	over	700,000	gross	acres	offshore	Norway	and	plan	to	continue	our	exploration	effort	there.	In	2006,	we	participated	in	a successful	appraisal	well	on	the	Gudrun	field,	located	120	miles	off	the	coast.	Marathon	holds	a	28	percent	outside-operated	interest	in	Gudrun	where	we	are	primarily focused	on	evaluating	development	scenarios.

								Angola		–		Offshore	Angola,	we	hold	a	10	percent	outside-operated	interest	in	Block	31	and	a	30	percent	outside-operated	interest	in	Block	32.	Through February	2007,	we	have	announced	20	discoveries	on	these	blocks.	We	have

also	participated	in	four	wells	that	have	reached	total	depth,	the	results	of	which	will	be	announced	upon	government	and	partner	approvals.	We	expect	to	participate	in 10	or	11	wells	on	these	blocks	in	2007.

								On	Block	31,	four	previously	announced	discoveries	(Plutao,	Saturno,	Marte	and	Venus)	and	one	successful	appraisal	well	form	a	planned	development	area	in	the northeastern	portion	of	the	block.	Also	on	Block	31,	we	had	five	previously	announced	discoveries	located	in	the	southeastern	portion	of	the	block	(Palas,	Ceres,	Juno, Astraea	and	Hebe).	In	2006	and	early	2007,	we	announced	discoveries	at	Urano,	Titania,	Terra	and	an	unnamed	well.	We	are	integrating	the	results	of	these	wells	with our	previously	announced	discoveries.

								On	Block	32,	we	previously	announced	three	discoveries	(Gindungo,	Canela	and	Gengibre).	In	2006,	we	announced	the	fourth	discovery	on	Block	32,	the Mostarda-1,	and	a	successful	deepwater	delineation	well,	Gengibre-2.	We	also	announced	that	hydrocarbons	were	encountered	in	the	Salsa	well,	but	additional	drilling is	required	to	assess	its	commerciality.	In	early	2007,	we	announced	two	additional	discoveries,	the	Manjericao	and	Caril	wells.	These	discoveries	move	Block	32	closer toward	establishment	of	a	commercial	development.

								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	natural	gas	and	condensate	in	several	pay	zones.	The	Gardenia	discovery	well	is	located	11 miles	southwest	of	the	Alba	Field.	We	are	currently	evaluating	development	scenarios	for	both	the	Deep	Luba	and	Gardenia	discoveries.	We	hold	a	63	percent	operated interest	in	the	Alba	Block.

								In	2004,	we	announced	the	results	of	the	Corona	well	drilled	on	Block	D	offshore	Equatorial	Guinea,	where	we	are	the	operator	with	a	90	percent	working	interest. The	Corona	well	confirmed	an	extension	of	the	Alba	field	on	to	Block	D.	An	application	for	an	Area	of	Commercial	Discovery	was	submitted	prior	to	the	end	of	the production	sharing	contract's	exploration	period,	which	expired	at	the	end	of	2006.	We	are	currently	in	discussions	with	the	Equatorial	Guinea	government	regarding	our rights	to	develop	the	Block	D	extension	of	the	Alba	Field.

								Libya		–		We	hold	a	16	percent	outside-operated	interest	in	the	Waha	concessions,	which	encompass	almost	13	million	acres	located	in	the	Sirte	Basin.	Our exploration	program	in	2006	included	the	drilling	of	12	wells,	nine	of	which	were	successful.	Most	of	these	discoveries	extended	previously	defined	hydrocarbon accumulations.

								Canada		–		We	are	the	operator	and	own	a	30	percent	interest	in	the	Annapolis	lease	offshore	Nova	Scotia,	where	we	continue	to	evaluate	further	drilling.	In	late 2006,	we	decided	to	withdraw	from	the	adjacent	Cortland	lease,	where	we	hold	a	75	percent	interest,	and	the	adjacent	Empire	lease,	where	we	hold	a	50	percent	interest. As	a	result	of	this	withdrawal,	a	charge	equal	to	25	percent	of	the	remaining	work	commitment,	or	$47	million,	was	recorded	as	exploration	expense	in	2006	and	the	cash payment	will	be	due	to	the	Canadian	provincial	government	in	2007.

								Indonesia		–		We	are	the	operator	and	hold	a	70	percent	interest	in	the	Pasangkayu	Block	offshore	Indonesia.	The	1.2	million	acre	block	is	located	mostly	in	deep water,	predominantly	offshore	of	the	island	of	Sulawesi	in	the	Makassar	Strait,	directly	east	of	the	Kutei	Basin	oil	and	natural	gas	production	region.	The	production sharing	contract	with	the	Indonesian	government	was	signed	in	2006.	We	expect	to	begin	collecting	geophysical	data	in	2007,	followed	by	exploratory	drilling	in	2008 and	2009.

# Production	(including	development	activities)

								United	States		–		Our	U.S.	operation	accounted	for	34	percent	of	our	2006	worldwide	net	liquid	hydrocarbon	sales	from	continuing	operations	and	63	percent	of	our worldwide	net	natural	gas	sales.

								During	2006,	our	net	sales	in	the	Gulf	of	Mexico	averaged	35	mbpd	of	liquid	hydrocarbons,	representing	46	percent	of	our	total	U.S.	net	liquid	hydrocarbon	sales, and	43	mmcfd	of	natural	gas,	representing	8	percent	of	our	total	U.S.	net	natural	gas	sales.	Net	liquid	hydrocarbon	sales	in	the	Gulf	of	Mexico	increased	slightly	from	the prior	year,	mainly	due	to	the	effects	of	five	tropical	storms/hurricanes	in	2005.	Net	natural	gas	sales	decreased	by	41	mmcfd	from	the	prior	year	primarily	because natural	gas	sales	from	the	Camden	Hills	field	ended	in	early	2006	as	a	result	of	increased	water	production.	At	year-end	2006,	we	held	interests	in	seven	producing	fields and	eight	platforms	in	the	Gulf	of	Mexico,	of	which	four	platforms	are	operated	by	Marathon.

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

								We	hold	a	30	percent	outside-operated	interest	in	the	Neptune	deepwater	development	on	Atwater	Valley	Blocks	573,	574,	575,	617	and	618	in	the	Gulf	of	Mexico, 120	miles	off	the	coast	of	Louisiana.	The	initial	development	plan	for	Neptune	was	sanctioned	in	2005	and	includes	seven	subsea	wells	tied	back	to	a	stand-alone	mini- tension	leg	platform.	Construction	of	the	platform	and	facility	continued	through	2006	with	first	production	expected	in	early	2008.

								We	are	one	of	the	largest	natural	gas	producers	in	the	Cook	Inlet	and	adjacent	Kenai	Peninsula	of	Alaska.	In	2006,	our	Alaskan	net	natural	gas	sales	averaged	156 mmcfd,	representing	29	percent	of	our	total	U.S.	net	natural	gas	sales.	Our	natural	gas	sales	from	Alaska	are	seasonal	in	nature,	trending	down	during	the	second	and third	quarters	of	each	year	and	increasing	during	the	fourth	and	first	quarters.	In	May	2006,	upon	receipt	of	regulatory	approvals,	we	began	to	produce	and	store	natural gas	in	a	partially	depleted	reservoir	in	the	Kenai	natural	gas	field.	The	natural	gas	in	storage	will	be	used	to	manage	supplies	to	meet	contractual	demand.	In	addition	to our	operations	in	other	established	Alaskan	fields,	production	from	the	Ninilchik	field	began	in	2003	and	development	continues	on	the	field.	Ninilchik	natural	gas	is transported	through	the	35-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	Ninilchik	and	own	a	60	percent	interest	in	it and	the	section	of	the	Kenai	Kachemak	Pipeline	described	above.	Our	2006	development	program	in	the	Cook	Inlet	included	participation	in	the	drilling	of	seven	wells.

								Net	liquid	hydrocarbon	sales	from	our	Wyoming	fields	averaged	21	mbpd	in	2006	and	2005.	Net	natural	gas	sales	from	our	Wyoming	fields	averaged	119	mmcfd in	2006	compared	to	107	mmcfd	in	2005.	The	increase	in	our	Wyoming	net	natural	gas	sales	is	primarily	attributed	to	higher	net	sales	from	the	Powder	River	Basin, which	averaged	77	mmcfd	in	2006	compared	to	66	mmcfd	in	2005	as	a	result	of	2005	drilling	activity.	Development	of	the	Powder	River	Basin	continued	in	2006	with 119	wells	drilled,	which	was	down	from	the	195	wells	drilled	in	2005	due	to	project	delays	primarily	caused	by	regulatory	and	produced	water	management	issues. Additional	development	of	our	southwest	Wyoming	interests	continued	in	2006	where	we	participated	in	the	drilling	of	27	wells.

								Net	natural	gas	sales	from	our	Oklahoma	fields	averaged	87	mmcfd	in	2006	compared	to	77	mmcfd	in	2005	primarily	as	a	result	of	development	and	exploratory drilling.	Our	2006	development	program	continued	to	focus	in	the	Anadarko	Basin	where	we	participated	in	the	drilling	of	75	wells.

								Net	natural	gas	sales	from	our	east	Texas	and	north	Louisiana	fields	averaged	71	mmcfd	in	2006	compared	to	75	mmcfd	in	2005.	This	decrease	is	primarily attributable	to	sour	gas	handling	capacity	limits	at	the	natural	gas	plants	that	purchase	our	east	Texas	natural	gas,	partially	offset	by	development	drilling	results.	Active development	of	the	Mimms	Creek	field	in	east	Texas	continued	in	2006.

								Net	liquid	hydrocarbon	sales	from	the	Permian	Basin	region,	which	extends	from	southeast	New	Mexico	to	west	Texas,	averaged	14	mbpd	in	2006	compared	to	16 mbpd	in	2005.	This	decrease	in	net	sales	was	due	to	natural	field	declines	partially	offset	by	development	project	results	in	the	Indian	Basin	and	Drinkard	areas	of southeast	New	Mexico.

								In	the	first	half	of	2006,	we	completed	leasehold	acquisitions	totaling	approximately	200,000	acres	in	the	Bakken	Shale	oil	play.	The	majority	of	the	acreage	is located	in	North	Dakota	with	the	remainder	in	eastern	Montana.	We	now	own	a	substantial	position	in	the	Bakken	Shale	with	approximately	300	locations	to	be	drilled over	the	next	five	years.	Our	initial	focus	has	been	to	evaluate	our	leasehold	position.

								In	July	2006,	we	completed	a	natural	gas	leasehold	acquisition	in	the	Piceance	Basin	of	Colorado,	located	in	Garfield	County	in	the	Greater	Grand	Valley	field complex.	The	acreage	is	located	near	adjacent	production.	Our	plans	include	drilling	approximately	700	wells	over	the	next	ten	years	with	first	production	expected	in late	2007.

								We	continue	to	assess	our	acreage	position	in	the	Barnett	Shale	gas	play	in	north	central	Texas.	To	date,	we	have	leased	approximately	85,000	net	acres	in	two counties.	One	core	well	and	five	horizontal	wells	have	been	drilled	and	completion	activity	is	underway	on	these	first	wells.	Seismic	data	was	acquired	in	2006	and	is being	evaluated.

								United	Kingdom		–		Our	largest	asset	in	the	U.K.	sector	of	the	North	Sea	is	the	Brae	area	complex	where	we	are	the	operator	and	have	a	42	percent	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	and	West	Brae	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	sales	from	the	Brae	area	averaged	15	mbpd	of	liquid	hydrocarbons	in	2006,	compared	with	18	mbpd	in	2005.	This	reduction	primarily	resulted	from	West	Brae	field decline	and	the	timing	of	sales	of	liquid	hydrocarbons.	Our	share	of	Brae	natural	gas	sales	averaged	151	mmcfd,	which	was	lower	than	the	169	mmcfd	in	2005	as	a	result of	natural	field	declines	in	the	North	and	East	Brae	gas	condensate	fields.

								The	strategic	location	of	the	Brae	platforms	along	with	pipeline	and	onshore	infrastructure	has	generated	third-party	processing	and	transportation	business	since 1986.	Currently,	there	are	28	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	SAGE	pipeline	transports	gas	from	the Brae	and	the	third-party	Beryl	areas	and	has	a	total	wet	natural	gas	capacity	of	1.1	billion	cubic	feet	("bcf")	per	day.	The	SAGE	terminal	at	St.	Fergus	in	northeast Scotland	processes	natural	gas	from	the	SAGE	pipeline	and	almost	1	bcf	per	day	of	third-party	natural	gas	from	the	third-party	Britannia	field.

								In	the	U.K.	Atlantic	Margin,	we	own	an	approximate	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.	Our	share	of	sales	from	the	Foinaven	fields	averaged	17	mbpd	of liquid	hydrocarbons	and	10	mmcfd	of	natural	gas	in	2006,	compared	to	16	mbpd	and	9	mmcfd	in	2005,	primarily	as	a	result	of	increased	liquid	handling	capacity following	facility	modifications,	increased	well	potential	and	improved	operating	efficiency.

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

								During	2006,	net	liquid	hydrocarbon	and	natural	gas	sales	in	Norway	from	the	Heimdal,	Vale	and	Skirne	fields	averaged	2	mbpd	and	36	mmcfd.	We	own	a 24	percent	outside-operated	interest	in	the	Heimdal	field,	a	47	percent	outside-operated	interest	in	the	Vale	field	and	a	20	percent	outside-operated	interest	in	the	Skirne field.

								We	are	the	operator	of	the	Alvheim	complex	located	on	the	Norwegian	Continental	Shelf.	This	development	is	comprised	of	the	Kameleon	and	Kneler	discoveries, in	which	we	have	a	65	percent	interest,	and	the	Boa	discovery,	in	which	we	have	a	58	percent	interest.	During	2004,	we	received	approval	from	the	Norwegian authorities	for	our	Alvheim	plan	for	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	acquired	the	Odin	multipurpose shuttle	tanker	early	in	2005.	The	vessel	is	currently	being	modified	to	serve	as	an	FPSO	and	has	been	renamed	"Alvheim."	In	2004,	the	Alvheim	partners	reached agreement	to	tie-in	the	nearby	Vilje	discovery,	in	which	we	own	a	47	percent	outside-operated	interest,	subject	to	the	approval	of	the	Norwegian	government.	In	2005, the	Norwegian	government	approved	the	Vilje	PDO.	Progress	also	continues	on	the	Vilje	project,	where	the	subsea	preparation	is	98	percent	complete	and	development drilling	is	expected	to	commence	in	the	second	quarter	of	2007.	First	production	from	the	Alvheim/Vilje	development	is	expected	during	the	second	quarter	of	2007. Four	wells	will	be	available	at	first	production	and	drilling	activities	will	continue	into	2008.	A	peak	net	rate	of	approximately	75,000	boepd	is	expected	in	early	2008.

								In	2006,	we	submitted	a	PDO	for	the	Volund	field	to	the	Norwegian	government,	with	a	recommendation	that	the	field	be	developed	as	a	subsea	tie-back	to	the Alvheim	FPSO.	In	December	2006,	the	Ministry	of	Petroleum	and	Energy	forwarded	the	PDO	to	the	Norwegian	King	in	Council	for	approval.	Approval	was	received	in early	2007.	The	Volund	development	will	include	three	producing	wells	and	a	water	injection	well.	The	crude	oil	production	will	be	exported	via	the	shuttle	tankers discussed	above	and	the	associated	natural	gas	will	be	exported	via	the	Alvheim-to-SAGE	pipeline.	The	Volund	development,	in	which	we	own	a	65	percent	interest	and serve	as	operator,	is	expected	to	begin	production	in	the	second	quarter	of	2009.

								Ireland		–		We	own	a	100	percent	interest	in	the	Kinsale	Head,	Ballycotton	and	Southwest	Kinsale	fields	in	the	Celtic	Sea	offshore	Ireland.	In	February	2006,	we acquired	an	87	percent	operated	interest	in	the	Seven	Heads	natural	gas	field.	Previously,	we	processed	and	transported	natural	gas	and	we	provided	field	operating services	to	the	Seven	Heads	group	through	our	existing	Kinsale	Head	facilities.	Net	natural	gas	sales	in	Ireland	were	46	mmcfd	in	2006,	compared	with	50	mmcfd	in 2005.	In	June	2006,	we	were	awarded	the	first	commercial	natural	gas	storage	license	in	Ireland,	which	allows	us	to	provide	full	third-party	storage	services	from	the Southwest	Kinsale	field.	In	2006,	we	began	to	produce	and	hold	in	storage	natural	gas	from	the	Kinsale	Head	field	for	future	delivery	under	a	contract	that	expires	in March	2009.	Additionally,	natural	gas	produced	from	our	other	fields	or	purchased	from	other	parties	can	be	stored	at	Southwest	Kinsale	for	future	sale	to	customers.

								We	own	a	19	percent	interest	in	the	outside-operated	Corrib	natural	gas	development	project,	located	40	miles	off	Ireland's	northwest	coast,	where	five	of	the	seven wells	necessary	to	develop	the	field	have	been	drilled.	During	2004,

An	Bord	Pleanála	(the	Planning	Board)	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	natural	gas	from	the	Corrib	field.	Development	activities	started	in	late	2004	but	were	suspended	to	facilitate	dialogue	and clarification	of	issues	raised	by	opponents	of	the	project.	In	July	2006,	the	partners	in	this	project	accepted	the	findings	of	a	government-commissioned	independent safety	review	and	the	report	of	an	independent	mediator	regarding	the	onshore	pipeline	associated	with	the	proposed	development.	The	onshore	pipeline	will	be	re- routed	and	routing	studies	are	underway.	Construction	of	the	natural	gas	plant	re-commenced	in	the	third	quarter	of	2006.	First	production	from	the	field	is	expected	in 2009.

								Equatorial	Guinea		–		We	own	a	63	percent	operated	interest	in	the	Alba	field	offshore	Equatorial	Guinea	and	a	52	percent	interest	in	an	onshore	liquefied petroleum	gas	("LPG")	processing	plant	held	through	an	equity	method	investee.	During	2006,	net	liquid	hydrocarbon	sales	averaged	48	mbpd	and	net	natural	gas	sales averaged	68	mmcfd,	compared	to	40	mbpd	and	92	mmcfd	in	2005.	A	condensate	expansion	project	ramped	up	to	full	production	and	a	new,	larger	LPG	plant	was completed	in	2005.	Net	sales	in	2006	averaged	36	mbpd	of	condensate	and	12	mbpd	of	LPG.

								We	own	45	percent	of	Atlantic	Methanol	Production	Company	LLC	("AMPCO"),	the	results	of	which	are	included	in	the	Integrated	Gas	segment.	In	2006,	we supplied	a	gross	99	mmcfd	of	dry	gas,	which	remains	after	the	condensate	and	LPG	are	removed,	to	AMPCO,	where	it	was	used	to	manufacture	methanol.	Remaining dry	gas	is	returned	offshore	and	reinjected	into	the	Alba	reservoir	for	later	production	when	the	LNG	production	facility	on	Bioko	Island,	discussed	below	under Integrated	Gas,	is	completed.

								Libya		–		Net	liquid	hydrocarbon	sales	in	Libya	averaged	54	mbpd	in	2006,	of	which	a	total	of	8	mbpd	were	owed	to	our	account	upon	the	resumption	of	our operations	in	Libya.	The	2006	sales	in	Libya	represented	37	percent	of	our	international	liquid	hydrocarbon	sales	from	continuing	operations.	We	continue	to	work	with our	partners	to	define	and	implement	growth	plans	for	this	business.

								Gabon		–		We	are	the	operator	of	the	Tchatamba	South,	Tchatamba	West	and	Tchatamba	Marin	fields	offshore	Gabon	with	a	56	percent	interest.	Net	sales	in	Gabon averaged	10	mbpd	of	liquid	hydrocarbons	in	2006,	compared	with	12	mbpd	in	2005.	Production	from	these	three	fields	is	processed	on	a	single	offshore	facility	at Tchatamba	Marin,	with	processed	oil	being	transported	through	an	offshore	and	onshore	pipeline	to	an	outside-operated	storage	facility.

								Russia		–		During	2003	we	acquired	Khanty	Mansiysk	Oil	Corporation	which	operated	oil	fields	located	in	the	Khanty	Mansiysk	region	of	western	Siberia.	Net liquid	hydrocarbon	sales	were	primarily	from	the	East	Kamennoye	and	Potenay	fields.	In	June	2006,	we	sold	these	Russian	oil	exploration	and	production	businesses.

# Other	Matters

								We	hold	an	interest	in	an	exploration	and	production	license	in	Sudan.	We	suspended	all	operations	in	Sudan	in	1985	due	to	civil	unrest.	We	have	had	no	employees in	the	country	and	have	derived	no	economic	benefit	from	those	interests	since	that	time.	The	U.S.	government	imposed	sanctions	against	Sudan	in	1997	and	we	have not	made	any	payments	related	to	Sudan	since	then.	We	have	abided	and	will	continue	to	abide	by	all	U.S.	sanctions	related	to	Sudan	and	will	not	consider	resuming	any activity	regarding	our	interests	there	until	such	time	as	it	is	permitted	under	U.S.	law.	Our	intention	is	to	exit	this	license	in	2007.

								We	discovered	the	Ash	Shaer	and	Cherrife	gas	fields	in	Syria	in	the	1980s.	We	have	recognized	no	revenues	in	any	period	from	activities	in	Syria	and	we	impaired our	entire	investment	in	Syria	in	1998.	In	July	2006,	the	new	production	sharing	contract	awarded	by	the	Syrian	government	was	signed	into	law.	This	contract	gave	us the	right	to	assign	all	or	part	of	our	interest	in	these	fields	to	a	third	party,	subject	to	the	consent	of	the	Syrian	government,	and	also	resolved	the	previous	disputes between	us,	the	Syrian	Petroleum	Company	and	the	Syrian	government	over	our	interest	in	these	fields.	In	October	2006,	the	Syrian	government	approved	the assignment	of	90	percent	of	our	interest	in	the	Ash	Shaer	and	Cherrife	natural	gas	fields	to	a	non-U.S.	company.	We	closed	the	transaction	on	November	1,	2006,	and received	cash	proceeds	of	$46	million.	While	we	continue	to	hold	a	10	percent	outside-operated	interest,	we	continue	to	comply	with	all	U.S.	sanctions	related	to	Syria. We	expect	to	sell	the	remaining	10	percent	interest	in	2007.

								The	above	discussion	of	the	E&P	segment	includes	forward-looking	statements	with	respect	to	anticipated	future	exploratory	and	development	drilling,	the possibility	of	developing	the	Gudrun	field	offshore	Norway	and	Blocks	31	and	32	offshore	Angola,	the	timing	of	production	from	the	Neptune	development,	the Piceance	Basin,	the	Alvheim/Vilje	development,	the	Volund	field	and	the	Corrib	project.	Some	factors	which	could	potentially	affect	these	forward-looking	statements include	pricing,	supply	and	demand	for	petroleum	products,	the	amount	of	capital	available	for	exploration	and	development,	regulatory	constraints,	drilling	rig availability,	unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response,	and	other	geological,	operating	and

economic	considerations.	Except	for	the	Alvheim/Vilje	and	Volund	developments,	the	foregoing	forward-looking	statements	may	be	further	affected	by	the	inability	to obtain	or	delay	in	obtaining	necessary	government	and	third-party	approvals	and	permits.	The	possible	developments	on	the	Gudrun	field	and	Blocks	31	and	32	could further	be	affected	by	presently	known	data	concerning	size	and	character	of	reservoirs,	economic	recoverability,	future	drilling	success	and	production	experience.	The foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Reserves

								At	December	31,	2006,	our	net	proved	liquid	hydrocarbon	and	natural	gas	reserves	totaled	1.262	billion	boe,	of	which	approximately	40	percent	were	located	in Organization	for	Economic	Cooperation	and	Development	("OECD")	countries.	The	following	table	sets	forth	estimated	quantities	of	net	proved	oil	and	natural	gas reserves	at	the	end	of	each	of	the	last	three	years.

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

|  | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Liquid\tHydrocarbons\t(Millions\tof\tbarrels) |  |  |  |  |  |  |
| United\tStates | 150 | 165 | 171 | 172 | 189 | 191 |
| Europe | 35 | 39 | 41 | 108 | 98 | 107 |
| Africa | 381 | 368 | 147 | 397 | 373 | 223 |
| Worldwide\tContinuing\tOperations | 566 | 572 | 359 | 677 | 660 | 521 |
| (a) |  |  |  |  |  |  |
| Discontinued\tOperations | – | 31 | 27 | – | 44 | 39 |
| WORLDWIDE | 566 | 603 | 386 | 677 | 704 | 560 |
| Developed\treserves\tas\ta\tpercent\tof\ttotal\tnet\tproved\treserves | 84% | 86% | 69% |  |  |  |
| Natural\tGas\t(Billions\tof\tcubic\tfeet) |  |  |  |  |  |  |
| United\tStates | 857 | 943 | 992 | 1,069 | 1,209 | 1,364 |
| Europe | 238 | 326 | 376 | 444 | 486 | 544 |
| Africa | 648 | 638 | 570 | 1,997 | 1,852 | 1,564 |
| WORLDWIDE | 1,743 | 1,907 | 1,938 | 3,510 | 3,547 | 3,472 |
| Developed\treserves\tas\ta\tpercent\tof\ttotal\tnet\tproved\treserves | 50% | 54% | 56% |  |  |  |
| Total\tBOE\t(Millions\tof\tbarrels) |  |  |  |  |  |  |
| United\tStates | 293 | 322 | 336 | 350 | 390 | 418 |
| Europe | 75 | 93 | 104 | 182 | 179 | 198 |
| Africa | 489 | 475 | 242 | 730 | 682 | 484 |
| Worldwide\tContinuing\tOperations | 857 | 890 | 682 | 1,262 | 1,251 | 1,100 |
| (a) |  |  |  |  |  |  |
| Discontinued\tOperations | – | 31 | 27 | – | 44 | 39 |
| WORLDWIDE | 857 | 921 | 709 | 1,262 | 1,295 | 1,139 |
| Developed\treserves\tas\ta\tpercent\tof\ttotal\tnet\tproved\treserves | 68% | 71% | 62% |  |  |  |

(a) Represents	Marathon's	Russian	businesses,	which	were	sold	in	2006.

								Proved	developed	reserves	represented	68	percent	of	total	proved	reserves	as	of	December	31,	2006,	as	compared	to	71	percent	as	of	December	31,	2005.	Of	the 405	million	boe	of	proved	undeveloped	reserves	at	year-end	2006,	less	than	10	percent	of	the	volume	is	associated	with	projects	that	have	been	included	in	proved reserves	for	more	than	three	years	while	11	percent	of	the	proved	undeveloped	reserves	were	added	during	2006.

								During	2006,	we	added	a	total	of	146	million	boe	of	net	proved	reserves,	principally	in	Libya	and	Equatorial	Guinea.	We	disposed	of	45	million	boe,	while producing	134	million	boe.	Of	the	total	net	proved	reserve	additions,	82	million	boe	were	proved	developed	and	64	million	boe	were	proved	undeveloped	reserves. During	2006,	we	transferred	18	million	boe	from	proved	undeveloped	to	proved	developed	reserves.	Costs	incurred	for	the	periods	ended	December	31,	2006,	2005	and 2004	relating	to	the	development	of	proved	undeveloped	oil	and	natural	gas	reserves,	were	$1.010	billion,	$955	million	and	$708	million.	As	of	December	31,	2006, estimated	future	development	costs	relating	to	the	development	of	proved	undeveloped	oil	and	natural	gas	reserves	for	the	years	2007	through	2009	are	projected	to	be $466	million,	$348	million	and	$231	million.

								Our	Libyan	fields	had	the	most	significant	positive	changes,	totaling	69	million	boe.	This	included	positive	revisions	due	to	access	to	additional	data	and	our improved	understanding	of	reservoir	performance	during	the	first	year	after	our	re-entry	and	additions	for	future	development	drilling.	At	the	end	of	2006,	our	proved reserves	associated	with	Libya	totaled	214	million	boe,	or	17	percent	of	our	total	proved	reserves.	Additionally,	21	million	boe	were	added	to	our	proved	reserves	for	the Alba	field	in	Equatorial	Guinea,	primarily	as	a	result	of	expanded	natural	gas	marketing	and	supply	agreements.

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

								For	a	discussion	of	the	proved	reserve	estimation	process,	see	Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	–	Critical Accounting	Estimates	–	Estimated	Net	Recoverable	Quantities	of	Oil	and	Natural	Gas,	and	for	additional	details	of	the	estimated	quantities	of	proved	reserves	at	the	end of	each	of	the	last	three	years,	see	Financial	Statements	and	Supplementary	Data	–	Supplementary	Information	on	Oil	and	Gas	Producing	Activities	–	Estimated Quantities	of	Proved	Oil	and	Natural	Gas	Reserves	on	pages	F-46	through	F-47.	We	filed	reports	with	the	U.S.	Department	of	Energy	("DOE")	for	the	years	2005	and 2004	disclosing	the	year-end	estimated	oil	and	natural	gas	reserves.	We	will	file	a	similar	report	for	2006.	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	local	utility	companies,	which	obligate	us	to	supply	124	bcf	of	natural	gas	over	the	remaining	lives	of	these contracts,	which	terminate	in	2012	and	2018.	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	43	bcf	through	the	remaining	life	of	the	contract,	which	terminates	in	2009.	These commitments	are	structured	with	variable-pricing	terms.	Our	production	from	various	natural	gas	fields	in	the	Cook	Inlet	supply	the	natural	gas	to	service	these contracts.	Our	proved	reserves	in	the	Cook	Inlet	are	sufficient	to	meet	these	contractual	obligations.

								In	the	U.K.,	we	have	two	long-term	sales	contracts	with	utility	companies,	which	obligate	us	to	supply	125	bcf	of	natural	gas	through	the	remaining	lives	of	these contracts,	which	terminate	in	2009.	Our	Brae	area	proved	reserves,	acquired	natural	gas	contracts	and	estimated	production	rates	are	sufficient	to	meet	these	contractual obligations.	Pricing	under	these	natural	gas	sales	contracts	is	variable.	See	Note	18	to	the	consolidated	financial	statements	for	further	discussion	of	these	contracts.

# Oil	and	Natural	Gas	Net	Sales

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

# Net	Liquid	Hydrocarbon	Sales (a)

# (Thousands	of	barrels	per	day)

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

(b) Represents	net	sales	from	leasehold	ownership,	after	royalties	and	interests	of	others.

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

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

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

(f) Excludes	volumes	acquired	from	third	parties	for	injection	and	subsequent	resale	of	46	mmcfd,	38	mmcfd	and	19	mmcfd	in	2006,	2005	and	2004.

# Productive	and	Drilling	Wells

# Gross	and	Net	Wells

|  | Gross | Net | Gross | Net | Gross | Net |  | Gross |  | Net |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2006 |  |  |  |  |  |  |  |  |  |  |
| United\tStates | 5,661 | 2,068 | 5,554 | 4,063 | 2,729 | 834 |  |  | 39 | 21 |
| Europe | 51 | 19 | 75 | 41 | 31 | 12 |  |  | 2 | 1 |
| Africa | 925 | 155 | 13 | 9 | 100 | 19 |  |  | 10 | 2 |
| Other\tInternational | – | – | – | – | – | – |  |  | – | – |
| WORLDWIDE | 6,637 | 2,242 | 5,642 | 4,113 | 2,860 | 865 |  |  | 51 | 24 |
| 2005 |  |  |  |  |  |  |  |  |  |  |
| United\tStates | 5,724 | 2,029 | 5,254 | 3,696 | 2,723 | 827 | 827 |  |  |  |
| Europe | 51 | 19 | 68 |  | 37 | 29 | 10 |  |  |  |
| Africa | 926 | 155 | 13 |  | 8 | 97 | 18 |  |  |  |
| Other\tInternational | 156 | 156 | – |  | – | 50 | 50 |  |  |  |
| WORLDWIDE | 6,857 | 2,359 | 5,335 | 3,741 | 2,899 | 905 | 905 |  |  |  |
| 2004 |  |  |  |  |  |  |  |  |  |  |
| United\tStates | 5,604 | 2,022 | 4,860 | 3,702 | 2,749 | 845 | 845 |  |  |  |
| Europe | 54 | 20 | 66 |  | 35 | 28 | 10 |  |  |  |
| Africa | 9 | 5 | 13 |  | 9 | 3 | 1 |  |  |  |
| Other\tInternational | 116 | 116 | – |  | – | 23 | 23 |  |  |  |
| WORLDWIDE | 5,783 | 2,163 | 4,939 | 3,746 | 2,803 | 879 | 879 |  |  |  |

(a) Includes	active	wells	and	wells	temporarily	shut-in.	Of	the	gross	productive	wells,	wells	with	multiple	completions	operated	by	Marathon	totaled	294,	278	and	273	in	2006,	2005	and	2004.	Information	on wells	with	multiple	completions	operated	by	others	is	unavailable	to	us.

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

(c) Consists	of	exploratory	and	development	wells.

# Drilling	Activity

								The	following	table	sets	forth,	by	geographic	area,	the	number	of	net	productive	and	dry	development	and	exploratory	wells	completed	in	each	of	the	last	three years.

|  |  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- | :--- |
| United\tStates |  |  |  |  |
| (b)\nDevelopment | -\tOil | 32 | 46 | 13 |
|  | -\tNatural\tGas | 186 | 288 | 167 |
|  | -\tDry | 5 | 4 | – |
|  | Total | 223 | 338 | 180 |
| Exploratory | -\tOil | 3 | 2 | 1 |
|  | -\tNatural\tGas | 8 | 17 | 8 |
|  | -\tDry | 3 | 2 | 6 |
|  | Total | 14 | 21 | 15 |
|  | Total\tUnited\tStates | 237 | 359 | 195 |
| International |  |  |  |  |
| (b)\nDevelopment | -\tOil | 51 | 68 | 27 |
|  | -\tNatural\tGas | 1 | 2 | 3 |
|  | -\tDry | – | 1 | 1 |
|  | Total | 52 | 71 | 31 |
| Exploratory | -\tOil | 19 | 2 | 2 |
|  | -\tNatural\tGas | – | – | – |
|  | -\tDry | 6 | 4 | 7 |
|  | Total | 25 | 6 | 9 |
|  | Total\tInternational | 77 | 77 | 40 |
|  | WORLDWIDE | 314 | 436 | 235 |

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

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

# Oil	and	Natural	Gas	Acreage

								The	following	table	sets	forth,	by	geographic	area,	the	developed	and	undeveloped	oil	and	natural	gas	acreage	that	we	held	as	of	December	31,	2006.

# Gross	and	Net	Acreage

|  | Gross | Net | Gross | Net | Gross | Net |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| United\tStates | 1,183 | 733 | 2,813 | 1,366 | 3,996 | 2,099 |
| Europe | 467 | 367 | 972 | 401 | 1,439 | 768 |
| Africa | 12,977 | 2,150 | 2,901 | 745 | 15,878 | 2,895 |
| Other\tInternational | – | – | 2,577 | 1,684 | 2,577 | 1,684 |
| WORLDWIDE | 14,627 | 3,250 | 9,263 | 4,196 | 23,890 | 7,446 |

# Refining,	Marketing	and	Transportation

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

# Refining

								We	own	and	operate	seven	refineries	with	an	aggregate	refining	capacity	of	974	mbpd	of	crude	oil.	During	2006,	our	refineries	processed	980	mbpd	of	crude	oil and	234	mbpd	of	other	charge	and	blend	stocks	for	a	crude	oil	capacity	utilization	rate	of	101	percent.	The	table	below	sets	forth	the	location	and	daily	throughput capacity	of	each	of	our	refineries	as	of	December	31,	2006.

# Crude	Oil	Refining	Capacity

| Garyville,	Louisiana | 245 |
| :--- | :--- |
| Catlettsburg,\tKentucky | 222 |
| Robinson,\tIllinois | 192 |
| Detroit,\tMichigan | 100 |
| Canton,\tOhio | 73 |
| Texas\tCity,\tTexas | 72 |
| St.\tPaul\tPark,\tMinnesota | 70 |
| TOTAL | 974 |

								Our	refineries	include	crude	oil	atmospheric	and	vacuum	distillation,	fluid	catalytic	cracking,	catalytic	reforming,	desulfurization	and	sulfur	recovery	units.	The refineries	can	process	a	wide	variety	of	crude	oils	and	produce	typical	refinery	products,	including	reformulated	and	low	sulfur	gasolines	and	ultra-low	sulfur	diesel	fuel. We	also	produce	asphalt	cements,	polymerized	asphalt,	asphalt	emulsions	and	industrial	asphalts.	We	manufacture	petroleum	pitch,	primarily	used	in	the	graphite electrode,	clay	target	and	refractory	industries.	Additionally,	we	manufacture	aromatics,	aliphatic	hydrocarbons,	cumene,	base	lube	oil,	polymer	grade	propylene,	maleic anhydride	and	slack	wax.

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

								Planned	maintenance	activities	requiring	temporary	shutdown	of	certain	refinery	operating	units,	or	turnarounds,	are	periodically	performed	at	each	refinery.	We completed	a	major	turnaround	at	our	Catlettsburg	refinery	in	2006.

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

# Refined	Product	Yields

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Gasoline | 661 | 644 | 608 |
| Distillates | 323 | 318 | 299 |
| Propane | 23 | 21 | 22 |
| Feedstocks\tand\tSpecial\tProducts | 107 | 96 | 94 |
| Heavy\tFuel\tOil | 26 | 28 | 25 |
| Asphalt | 89 | 85 | 77 |
| TOTAL | 1,229 | 1,192 | 1,125 |

								We	completed	all	of	our	ultra-low	sulfur	diesel	fuel	modifications	required	by	the	U.S.	Environmental	Protection	Agency	prior	to	its	June	1,	2006	deadline.	These modifications	were	completed	on	time	and	under	budget.

								In	2006,	our	Board	of	Directors	approved	a	projected	$3.2	billion	expansion	of	our	Garyville,	Louisiana	refinery	by	180	mbpd	to	425	mbpd,	which	will	increase our	total	refining	capacity	to	1.154	million	barrels	per	day	("mmbpd").	We	recently	received	air	permit	approval	from	the	Louisiana	Department	of	Environmental Quality	for	this	project	and	construction	is	expected	to	begin	in	mid-2007,	with	startup	planned	for	the	fourth	quarter	of	2009.

								We	have	also	commenced	front-end	engineering	and	design	("FEED")	for	a	potential	heavy	oil	upgrading	project	at	our	Detroit	refinery,	which	would	allow	us	to process	increased	volumes	of	Canadian	oil	sands	production,	and	are	undertaking	a	feasibility	study	for	a	similar	upgrading	project	at	our	Catlettsburg	refinery.

# Marketing

								We	are	a	supplier	of	gasoline	and	distillates	to	resellers	and	consumers	within	our	market	area	in	the	Midwest,	the	upper	Great	Plains	and	southeastern	United States.	In	2006,	our	refined	product	sales	volumes	(excluding	matching	buy/sell	transactions)	totaled	21.5	billion	gallons,	or	1.401	mmbpd.	The	average	sales	price	of our	refined	products	in	aggregate	was	$77.76	per	barrel	for	2006.	The	following	table	sets	forth	our	refined	product	sales	by	product	group	and	our	average	sales	price for	each	of	the	last	three	years.

# Refined	Product	Sales

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Gasoline | 804 | 836 | 807 |
| Distillates | 375 | 385 | 373 |
| Propane | 23 | 22 | 22 |
| Feedstocks\tand\tSpecial\tProducts | 106 | 96 | 92 |
| Heavy\tFuel\tOil | 26 | 29 | 27 |
| Asphalt | 91 | 87 | 79 |
| (a)\nTOTAL | 1,425 | 1,455 | 1,400 |
| Average\tsales\tprice\t($\tper\tbarrel) | $77.76 | $66.42 | $49.53 |

(a) Includes	matching	buy/sell	volumes	of	24	mbpd,	77	mbpd	and	71	mbpd	in	2006,	2005	and	2004.	On	April	1,	2006,	we	changed	our	accounting	for	matching	buy/sell	arrangements	as	a	result	of	a	new accounting	standard.	This	change	resulted	in	lower	refined	product	sales	volumes	for	the	remainder	of	2006	than	would	have	been	reported	under	the	previous	accounting	practices.	See	Note	2	to	the consolidated	financial	statements.

								The	wholesale	distribution	of	petroleum	products	to	private	brand	marketers	and	to	large	commercial	and	industrial	consumers	and	sales	in	the	spot	market accounted	for	71	percent	of	our	refined	product	sales	volumes	in	2006.	We	sold	52	percent	of	our	gasoline	volumes	and	89	percent	of	our	distillates	volumes	on	a wholesale	or	spot	market	basis.	Half	of	our	propane	is	sold	into	the	home	heating	market,	with	the	balance	being	purchased	by	industrial	consumers.	Propylene,	cumene, aromatics,	aliphatics,	and	sulfur	are	domestically	marketed	to	customers	in	the	chemical	industry.	Base	lube	oils,	maleic	anhydride,	slack	wax,	extract	and	pitch	are	sold throughout	the	United	States	and	Canada,	with	pitch	products	also	being	exported	worldwide.	We	market	asphalt	through	owned	and	leased	terminals	throughout	the Midwest,	the	upper	Great	Plains	and	southeastern	United	States.	Our	customer	base	includes	approximately	800	asphalt-paving	contractors,	government	entities	(states, counties,	cities	and	townships)	and	asphalt	roofing	shingle	manufacturers.

								We	blended	35	mbpd	of	ethanol	into	gasoline	in	2006.	In	2005	and	2004,	we	blended	35	mbpd	and	30	mbpd	of	ethanol.	The	expansion	or	contraction	of	our	ethanol blending	program	will	be	driven	by	the	economics	of	the	ethanol	supply	and	changes	in	government	regulations.	We	sell	reformulated	gasoline	in	parts	of	our	marketing territory,	primarily	Chicago,	Illinois;	Louisville,	Kentucky;	northern	Kentucky;	and	Milwaukee,	Wisconsin,	and	we	sell	low-vapor-pressure	gasoline	in	nine	states.

								As	of	December	31,	2006,	we	supplied	petroleum	products	to	about	4,200	Marathon	branded	retail	outlets	located	primarily	in	Ohio,	Michigan,	Indiana,	Kentucky and	Illinois.	Branded	retail	outlets	are	also	located	in	Florida,	Georgia,	Minnesota,	Wisconsin,	West	Virginia,	Tennessee,	Virginia,	North	Carolina,	Pennsylvania, Alabama	and	South	Carolina.	Sales	to	Marathon	brand	jobbers	and	dealers	accounted	for	14	percent	of	our	refined	product	sales	volumes	in	2006.

								SSA	sells	gasoline	and	diesel	fuel	through	company-operated	retail	outlets.	Sales	of	refined	products	through	these	SSA	retail	outlets	accounted	for	15	percent	of our	refined	product	sales	volumes	in	2006.	As	of	December	31,	2006,	SSA	had	1,636	retail	outlets	in	nine	states	that	sold	petroleum	products	and	convenience	store merchandise	and	services,	primarily	under	the	brand	names	"Speedway"	and	"SuperAmerica."	SSA's	revenues	from	the	sale	of	non-petroleum	merchandise	totaled $2.7	billion	in	2006,	compared	with	$2.5	billion	in	2005.	Profit	levels	from	the	sale

of	such	merchandise	and	services	tend	to	be	less	volatile	than	profit	levels	from	the	retail	sale	of	gasoline	and	diesel	fuel.	SSA	also	operates	60	Valvoline	Instant	Oil Change	retail	outlets	located	in	Michigan	and	northwest	Ohio.

								Pilot	Travel	Centers	LLC	("PTC"),	our	joint	venture	with	Pilot	Corporation	("Pilot"),	is	the	largest	operator	of	travel	centers	in	the	United	States	with	269	locations in	37	states	and	Canada	at	December	31,	2006.	In	2006,	PTC	expanded	internationally	with	the	opening	of	a	site	in	Ontario,	Canada.	The	travel	centers	offer	diesel	fuel, gasoline	and	a	variety	of	other	services,	including	on-premises	brand-name	restaurants	at	many	locations.	Pilot	and	Marathon	each	own	a	50	percent	interest	in	PTC.

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

# Supply	and	Transportation

								We	obtain	most	of	the	crude	oil	we	refine	from	negotiated	contracts	and	purchases	or	exchanges	on	the	spot	market.	In	2006,	U.S.	sourced	crude	oil	averaged	470 mbpd,	or	48	percent	of	the	crude	oil	processed	at	our	refineries,	including	a	net	14	mbpd	from	our	production	operations.	In	2006,	Canada	was	the	source	for	13	percent, or	130	mbpd	of	crude	oil	processed	and	other	foreign	sources	supplied	39	percent,	or	380	mbpd,	of	the	crude	oil	processed	by	our	refineries,	including	198	mbpd	from the	Middle	East.	This	crude	oil	was	acquired	from	various	foreign	national	oil	companies,	producing	companies	and	trading	companies.	The	following	table	provides information	on	the	sources	of	crude	for	each	of	the	last	three	years.

# Sources	of	Crude	Oil	Refined

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| United\tStates | 470 | 447 | 416 |
| Canada | 130 | 111 | 130 |
| Middle\tEast\tand\tAfrica | 266 | 301 | 276 |
| Other\tInternational | 114 | 114 | 117 |
| TOTAL | 980 | 973 | 939 |
| Average\tcost\tof\tcrude\toil\tthroughput\t($\tper\tbarrel) | $61.15 | $51.85 | $39.16 |

								We	operate	a	system	of	pipelines,	terminals	and	barges	to	provide	crude	oil	to	our	refineries	and	refined	products	to	our	marketing	areas.	At	December	31,	2006,	we owned,	leased,	operated	or	held	equity	method	investments	in	68	miles	of	crude	oil	gathering	lines,	3,718	miles	of	crude	oil	trunk	lines	and	3,855	miles	of	refined product	trunk	lines.

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

# Pipeline	Barrels	Handled

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Crude\toil\tgathering\tlines | 6 | 7 | 7 |
| Crude\toil\ttrunk\tlines | 542 | 591 | 569 |
| Refined\tproducts\ttrunk\tlines | 402 | 445 | 407 |
| TOTAL | 950 | 1,043 | 983 |

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

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

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

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

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

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

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

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

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

								Our	87	owned	and	operated	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	trucks.	Our	marine	transportation	operations	include	towboats	(15	owned)	and	barges	(180	owned,	4 leased)	that	transport	refined	products	on	the	Ohio,	Mississippi	and	Illinois	rivers,	their	tributaries	and	the	Intercoastal	Waterway.	We	lease	and	own	over	2,000	rail	cars of	various	sizes	and	capacities	for	movement	and	storage	of	petroleum	products	and	over	100	tractors	and	tank	trailers.

# Ethanol	Production

								In	2006,	we	signed	a	definitive	agreement	forming	a	50/50	joint	venture	that	will	construct	and	operate	one	or	more	ethanol	production	plants.	Our	partner	in	the joint	venture	will	provide	the	day-to-day	management	of	the	plants,	as	well	as	grain	procurement,	distillers	dried	grain	marketing	and	ethanol	management	services.	This venture	will	enable	us	to	maintain	the	reliability	of	a	portion	of	our	future	ethanol	supplies.	Together	with	our	partner,	we	selected	the	venture's	initial	plant	site, Greenville,	Ohio,	and	construction	has	commenced	on	a	110	million	gallon	per	year	ethanol	facility.	The	facility	is	expected	to	be	operational	as	soon	as	the	first	quarter of	2008.

								The	above	discussion	of	the	RM&T	segment	includes	forward-looking	statements	concerning	the	planned	expansion	of	the	Garyville	refinery,	potential	heavy	oil refining	upgrading	projects	and	a	joint	venture	that	would	construct	and	operate	ethanol	plants.	Some	factors	that	could	affect	the	Garyville	expansion	project	and	the ethanol	plant	construction,	management	and	development	include	necessary	government	and	third	party	approvals,	transportation	logistics,	availability	of	materials	and labor,	unforeseen	hazards	such	as	weather	conditions	and	other	risks	customarily	associated	with	construction	projects.	The	Garyville	project	may	be	further	affected	by crude	oil	supply.	These	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.	Factors	that	could affect	the	heavy	oil	refining	upgrading	projects	include	unforeseen	difficulty	in	negotiation	of	definitive	agreements,	results	of	front-end	engineering	and	design	work, approval	of	our	Board	of	Directors,	inability	or	delay	in	obtaining	necessary	government	and	third-party	approvals,	continued	favorable	investment	climate,	and	other geological,	operating	and	economic	considerations.

# Other

								The	Energy	Policy	Act	of	2005	established	a	Renewable	Fuel	Standard	("RFS")	providing	that	all	gasoline	sold	in	the	United	States	contain	a	minimum	of 4.0	billion	gallons	of	renewable	fuel	in	2006.	The	RFS	increases	gradually	each	year	until	2012,	when	the	RFS	will	be	7.5	billion	gallons	of	renewable	fuel.	The	U.S. Environmental	Protection	Agency	("EPA")	has	published	a	proposed	rule	to	implement	the	RFS,	and	we	anticipate	that	a	final	rule	will	be	published	in	mid-2007. Federal	legislation	may	be	proposed	in	2007	which	may	require	even	greater	quantities	of	renewable	fuels.	Marathon	intends	to	comply	with	all	regulations	that	are adopted.

# Integrated	Gas

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

# Alaska	LNG

								We	own	a	30	percent	interest	in	a	Kenai,	Alaska,	natural	gas	liquefaction	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.	This	contract	continues	through	March	2009,	with	2006	LNG	deliveries	totaling	61	gross	bcf	(19	net bcf).	In	January	2007,	along	with	our	partner,	we	filed	a	request	with	the	U.S.	Department	of	Energy	to	extend	the	export	license	for	this	natural	gas	liquefaction	plant through	March	2011.

# Equatorial	Guinea	LNG

								In	2004,	we	and	our	partner,	Compania	Nacional	de	Petroleos	de	Guinea	Ecuatorial	(the	National	Oil	Company	of	Equatorial	Guinea	or	"GEPetrol"),	through Equatorial	Guinea	LNG	Holdings	Limited	("EGHoldings"),	began	construction	of	a	3.7	million	metric	ton	per	annum	("mmtpa")	LNG	production	facility	on	Bioko Island.	We	expect	to	begin	delivering	3.4	mmtpa,	or	460	mmcfd,	during	the	second	quarter	of	2007	under	a	17-year	sales	and	purchase	agreement.	The	purchaser	under this	agreement	will	take	delivery	of	the	LNG	facility's	production	on	an	FOB	Bioko	Island	basis	with	pricing	linked	principally	to	the	Henry	Hub	index,	regardless	of destination.	This	project	will	allow	us	to	monetize	our	natural	gas	reserves	from	the	Alba	field,	as	natural	gas	for	the	production	facility	will	be	purchased	from	the	Alba field	participants	under	a	long-term	natural	gas	supply	agreement.	We	are	currently	seeking	additional	natural	gas	supplies	to	allow	full	utilization	of	this	LNG	facility, which	is	designed	to	have	a	higher	capacity	and	a	longer	life	than	the	current	17-year	sales	and	purchase	agreement.

								In	July	2005,	Marathon	and	GEPetrol	entered	into	agreements	under	which	Mitsui	&	Co.,	Ltd.	("Mitsui")	and	a	subsidiary	of	Marubeni	Corporation	("Marubeni") acquired	8.5	percent	and	6.5	percent	interests	in	EGHoldings.	In	November	2006,	GEPetrol	transferred	its	25	percent	interest	to	Sociedad	Nacional	de	Gas	de	Guinea Ecuatorial	("SONAGAS"),	which	is	also	controlled	by	the	government	of	Equatorial	Guinea.	Following	these	transaction,	we	hold	a	60	percent	interest	in	EGHoldings, with	SONAGAS	holding	a	25	percent	interest	and	Mitsui	and	Marubeni	holding	the	remaining	interests.

								In	2006,	with	our	project	partners,	we	awarded	a	FEED	contract	for	initial	work	related	to	a	potential	second	LNG	production	facility	on	Bioko	Island,	Equatorial Guinea.	The	FEED	work	is	expected	to	be	completed	during	2007.	The	scope	of	the	FEED	work	for	the	potential	4.4	mmtpa	LNG	project	includes	feed	gas	metering, liquefaction,	refrigeration,	ethylene	storage,	boil	off	gas	compression,	product	transfer	to	storage	and	LNG	product	metering.	A	final	investment	decision	is	expected	in early	2008.

# Elba	Island	LNG

								In	April	2004,	we	began	delivering	LNG	cargoes	at	the	Elba	Island,	Georgia	LNG	regasification	terminal	pursuant	to	an	LNG	sales	and	purchase	agreement.	Under the	terms	of	the	agreement,	we	have	the	right	to	deliver	and	sell	up	to	58	bcf	of	natural	gas	(as	LNG)	per	year,	through	March	31,	2021	with	a	possible	extension	to November	30,	2023.

								In	September	2004,	we	signed	an	agreement	under	which	we	will	be	supplied	with	58	bcf	of	natural	gas	per	year,	as	LNG,	for	a	minimum	period	of	five	years.	The agreement	allows	for	delivery	of	LNG	at	the	Elba	Island	LNG	regasification	terminal	with	pricing	linked	to	the	Henry	Hub	index.	This	supply	agreement	enables	us	to fully	utilize	our	rights	at	Elba	Island	during	the	period	of	this	agreement,	while	affording	us	the	flexibility	to	commercialize	other	stranded	natural	gas	resources	beyond the	term	of	this	contract.	The	agreement	commenced	in	2005.

# Methanol

								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	our	natural gas	production	in	the	Alba	field.	Methanol	sales	totaled	733,680	gross	metric	tons	(330,156	net	metric	tons)	in	2006.	Production	from	the	plant	is	used	to	supply customers	in	Europe	and	the	United	States.

# Gas	Technology

								We	invest	in	natural	gas	technology	research,	including	gas-to-liquids	("GTL")	technology	which	offers	the	ability	to	convert	natural	gas	into	premium	fuels.	In addition	to	GTL,	we	continue	to	evaluate	application	of	gas	technologies	accessible	through	licenses,	including	methanol-to-power	and	compressed	natural	gas.	We	also continue	to	develop	a

proprietary	gas-to-fuels	("GTF")	technology,	which	can	be	configured	to	convert	natural	gas	resources	into	premium	fuels.

								The	above	discussion	of	the	integrated	gas	segment	contains	forward	looking	statements	with	respect	to	the	timing	and	levels	of	production	associated	with	the LNG	production	facility	and	the	possible	expansion	thereof.	Factors	that	could	affect	the	LNG	production	facility	include	unforeseen	problems	arising	from commissioning	of	the	facilities,	unforeseen	hazards	such	as	weather	conditions	and	other	operating	considerations	such	as	shipping	the	LNG.	In	addition	to	these	factors, other	factors	that	could	potentially	affect	the	possible	expansion	of	the	current	LNG	production	facility	and	the	development	of	additional	LNG	capacity	through additional	projects	include	partner	approvals,	access	to	sufficient	natural	gas	volumes	through	exploration	or	commercial	negotiations	with	other	resource	owners	and access	to	sufficient	regasification	capacity.	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,	as	well	as	national	oil	companies,	for	the	acquisition	of	oil	and	natural	gas	leases	and	other	properties.	We	compete with	these	companies	for	the	equipment	and	labor	required	to	develop	and	operate	those	properties	and	in	the	marketing	of	oil	and	natural	gas	to	end-users.	Many	of	our competitors	have	financial	and	other	resources	greater	than	those	available	to	us.	Acquiring	the	more	attractive	exploration	opportunities	frequently	requires	competitive bids	involving	front-end	bonus	payments	or	commitments-to-work	programs.	We	also	compete	in	attracting	and	retaining	personnel,	including	geologists,	geophysicists and	other	specialists.	Based	on	industry	sources,	we	currently	rank	ninth	among	U.S.-based	petroleum	companies	on	the	basis	of	2005	worldwide	liquid	hydrocarbon and	natural	gas	production.

								We	must	also	compete	with	a	large	number	of	other	companies	to	acquire	crude	oil	for	refinery	processing	and	in	the	distribution	and	marketing	of	a	full	array	of petroleum	products.	We	rank	fifth	among	U.S.	petroleum	companies	on	the	basis	of	U.S.	crude	oil	refining	capacity	as	of	December	31,	2006.	We	compete	in	four distinct	markets	–	wholesale,	spot,	branded	and	retail	distribution	–	for	the	sale	of	refined	products.	We	believe	we	compete	with	about	40	companies	in	the	wholesale distribution	of	petroleum	products	to	private	brand	marketers	and	large	commercial	and	industrial	consumers;	about	70	companies	in	the	sale	of	petroleum	products	in the	spot	market;	nine	refiner/marketers	in	the	supply	of	branded	petroleum	products	to	dealers	and	jobbers;	and	approximately	260	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	the	refining	and	wholesale	marketing	gross	margin	may be	adversely	affected	by	crude	oil	price	increases.	Price	differentials	between	sweet	and	sour	crude	oil	also	affect	operating	results.	Market	conditions	in	the	oil	and	gas industry	are	cyclical	and	subject	to	global	economic	and	political	events	and	new	and	changing	governmental	regulations.

# The	Separation

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

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

•USX	Corporation	changed	its	name	to	Marathon	Oil	Corporation.

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

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

# Financial	Matters	Agreement

								Under	the	financial	matters	agreement,	United	States	Steel	has	assumed	and	agreed	to	discharge	all	of	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.

								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	lease	obligations	without	the	prior	consent	of	Marathon	other	than	extensions	set	forth	in	the	terms	of	the	assumed	leases,	other	than extensions	set	forth	in	the	terms	of	any	of	the	assumed	leases.

								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	of	United	States	Steel's	obligations	under	a	partnership	agreement	between	United	States	Steel,	as	general	partner,	and General	Electric	Credit	Corporation	of	Delaware	and	Southern	Energy	Clairton,	LLC,	as	limited	partners.	United	States	Steel	may	dissolve	the	partnership	under	certain circumstances,	including	if	it	is	required	to	fund	accumulated	cash	shortfalls	of	the	partnership	in	excess	of	$150	million.	In	addition	to	the	normal	commitments	of	a general	partner,	United	States	Steel	has	indemnified	the	limited	partners	for	certain	income	tax	exposures.

								The	financial	matters	agreement	requires	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	payments	on	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.	During	2006,	the	Internal	Revenue Service	completed	its	review	of	all	federal	income	tax	returns	filed	by	USX	Corporation	for	taxable	periods	ending	on	or	prior	to	the	date	of	the	Separation.	Marathon and	United	States	Steel	have	settled	all	matters	related	to	federal	income	taxes	under	this	agreement.	Remaining	matters	related	to	state	and	local	income	taxes	are	not expected	to	have	any	significant	effect	on	Marathon.

# Obligations	Associated	with	the	Separation	as	of	December	31,	2006

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

# Environmental	Matters

								The	Corporate	Governance	and	Nominating	Committee	of	our	Board	of	Directors	is	responsible	for	overseeing	our	position	on	public	issues	identified	by management,	including	environmental	matters.	Our	Corporate	Responsibility	organization	has	the	responsibility	to	ensure	that	our	operating	organizations	maintain environmental	compliance	systems	that	are	in	accordance	with	applicable	laws	and	regulations.	Committees	comprised	of	certain	of	our	officers	review	our	overall performance	with	various	environmental	compliance	programs.	We	also	have	a	Crisis	Management	Team,	composed	primarily	of	senior	management,	which	oversees the	response	to	any	major	emergency,	environmental	or	other	incident	involving	Marathon	or	any	of	our	properties.

								Legislation	and	regulations	pertaining	to	climate	change	and	greenhouse	gas	emissions	have	the	potential	to	impact	us.	The	Kyoto	Protocol,	effective	in	2005,	has been	ratified	by	countries	in	which	we	have	or	in	the	future	may	have	operations.	Other	climate	change	legislation	and	regulations	both	in	the	United	States	and	abroad are	in	various	stages	of	development.	Although	there	may	be	financial	impact	(including	compliance	costs)	associated	with	any	legislation	or	regulation,	the	extent	and magnitude	of	impact	cannot	be	reliably	or	accurately	estimated	due	to	the	present	uncertainty	of	these	measures.	As	part	of	our	commitment	to	environmental stewardship,	we	estimate	and	publicly	report	greenhouse	gas	emissions	from	our	operations.	We	are	working	to	continuously	improve	the	accuracy	and	completeness	of these	estimates.	In	addition,	we	continuously	strive	to	improve	operational	and	energy	efficiencies	through	resource	and	energy	conservation	where	practicable	and	cost effective.

								Our	businesses	are	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.	New	laws	are	being	enacted	and	regulations	are	being	adopted	by	various regulatory	agencies	on	a	continuing	basis,	and	the	costs	of	compliance	with	these	new	rules	can	only	be	broadly	appraised	until	their	implementation	becomes	more accurately	defined.	In	some	cases,	they	can	impose	liability	for	the	entire	cost	of	cleanup	on	any	responsible	party	without	regard	to	negligence	or	fault	and	impose liability	on	us	for	the	conduct	of	others	or	conditions	others	have	caused,	or	for	our	acts	that	complied	with	all	applicable	requirements	when	we	performed	them.	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"	and	"Legal	Proceedings."

								Of	particular	significance	to	our	refining	operations	were	U.S.	EPA	regulations	that	required	reduced	sulfur	levels	starting	in	2004	for	gasoline	and	2006	for	diesel fuel.	We	achieved	compliance	with	these	regulations	and	began	production	of	ultra-low	sulfur	diesel	fuel	for	on-road	use	prior	to	the	June	1,	2006	deadline.	The	cost	of achieving	compliance	with	these	regulations	was	approximately	$850	million.	Marathon	will	also	be	spending	approximately	$250	million	from	2006	through	2010	to produce	ultra-low	sulfur	diesel	fuel	for	off-road	use.	Further,	Marathon	estimates	that	it	will	spend	approximately	$400	million	over	a	four-year	period	beginning	in	2008 to	comply	with	Mobile	Source	Air	Toxics	II	regulations	relating	to	benzene.	This	is	a	preliminary	estimate	as	the	Mobile	Source	Air	Toxics	II	regulations	should	be finalized	in	the	first	half	of	2007.

								The	EPA	has	finalized	new	and	revised	National	Ambient	Air	Quality	Standards	("NAAQS")	for	fine	particulate	emissions	and	ozone.	In	connection	with	these new	standards,	the	EPA	will	designate	certain	areas	as	"nonattainment,"	meaning	that	the	air	quality	in	such	areas	does	not	meet	the	NAAQS.	To	address	these nonattainment	areas,	in	January	2004,	the	EPA	proposed	a	rule	called	the	Interstate	Air	Quality	Rule	("IAQR")	that	would	require	significant	reductions	of	SO2	and NOx	emissions	in	numerous	states.	The	final	rule	was	promulgated	on	May	12,	2005,	and	the	rule	was	renamed	the	Clean	Air	Interstate	Rule	("CAIR").	While	the	EPA expects	that	states	will	meet	their	CAIR	obligations	by	requiring	emissions	reductions	from	Electric	Generating	Units	("EGUs"),	states	will	have	the	final	say	on	what sources	they	regulate	to	meet	attainment	criteria.	Our	refinery	operations	are	located	in	affected	states	and	some	states	may	choose	to	propose	more	stringent	fuels requirements	to	meet	the	CAIR

requirements;	however	we	cannot	reasonably	estimate	the	final	financial	impact	of	the	state	actions	to	implement	the	CAIR	until	the	states	have	taken	further	action.

# Water

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

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

# 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.	We	have	ongoing	RCRA	treatment	and	disposal	operations	at	one	of our	RM&T	facilities	and	primarily	utilize	offsite	third-party	treatment	and	disposal	facilities.	Ongoing	RCRA-related	costs	are	not	expected	to	be	material.

# Remediation

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

# Employees

								We	had	28,195	active	employees	as	of	December	31,	2006.	Of	that	number,	19,132	were	employees	of	SSA,	most	of	whom	were	employed	at	our	retail	marketing outlets.

								Certain	hourly	employees	at	our	Catlettsburg	and	Canton	refineries	are	represented	by	the	United	Steel,	Paper	and	Forestry,	Rubber,	Manufacturing,	Energy,	Allied Industrial	and	Service	Workers	Union	under	labor	agreements	that	expire	on	January	31,	2009.	The	same	union	represents	certain	hourly	employees	at	our	Texas	City refinery	under	a	labor	agreement	that	expires	on	March	31,	2009.	The	International	Brotherhood	of	Teamsters	represents	certain	hourly	employees	under	labor agreements	that	are	scheduled	to	expire	on	May	31,	2009	at	our	St.	Paul	Park	refinery	and	January	31,	2010	at	our	Detroit	refinery.

# 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/Our	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	Annual	Report	on	Form	10-K	or	other	securities	filings.

# Item	1A.	Risk	Factors

								Marathon	is	subject	to	various	risks	and	uncertainties	in	the	course	of	its	business.	The	following	summarizes	some,	but	not	all,	of	the	risks	and	uncertainties	that may	adversely	affect	our	business,	financial	condition	or	results	of	operations.

# A	substantial	or	extended	decline	in	oil	or	natural	gas	prices,	as	well	as	refined	product	gross	margins,	would	reduce	our	operating	results	and	cash	flows	and could	adversely	impact	our	future	rate	of	growth	and	the	carrying	value	of	our	assets.

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

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

•the	cost	of	exploring	for,	developing	and	producing	oil,	natural	gas	and	refined	products;

•the	ability	of	the	members	of	the	Organization	of	Petroleum	Exporting	Countries	to	agree	to	and	maintain	production	controls;

•political	instability	or	armed	conflict	in	oil-producing	regions;

•changes	in	weather	patterns	and	climatic	changes;

•natural	disasters	such	as	hurricanes	and	tornados;

•the	price	and	availability	of	alternative	and	competing	fuels;

•domestic	and	foreign	governmental	regulations	and	taxes;	and

# •general	economic	conditions	worldwide.

								The	long-term	effects	of	these	and	other	factors	on	the	prices	of	oil	and	natural	gas,	as	well	as	on	refined	product	gross	margins,	are	uncertain.

								Lower	oil	and	natural	gas	prices,	as	well	as	lower	refined	product	gross	margins,	may	reduce	the	amount	of	these	commodities	that	we	produce,	which	may	reduce our	revenues,	operating	income	and	cash	flows.	Significant	reductions	in	oil	and	natural	gas	prices	or	refined	product	gross	margins	could	require	us	to	reduce	our	capital expenditures	and	impair	the	carrying	value	of	our	assets.

Estimates	of	oil	and	natural	gas	reserves	depend	on	many	factors	and	assumptions,	including	various	assumptions	that	are	based	on	conditions	in	existence	as of	the	dates	of	the	estimates.	Any	material	changes	in	those	conditions	or	other	factors	affecting	those	assumptions	could	impair	the	quantity	and	value	of	our oil	and	natural	gas	reserves.

								The	proved	oil	and	natural	gas	reserves	information	related	to	Marathon	included	in	this	report	has	been	derived	from	engineering	estimates.	Those	estimates	were prepared	by	our	in-house	teams	of	reservoir	engineers	and	geoscience	professionals	and	reviewed,	on	a	selected	basis,	by	our	Corporate	Reserves	Group	and/or	third- party	consultants	we	have	retained.	The	estimates	were	calculated	using	oil	and	natural	gas	prices	in	effect	as	of	December	31,	2006,	as	well	as	other	conditions	in existence	as	of	that	date.	Any	significant	future	price	changes	will	have	a	material	effect	on	the	quantity	and	present	value	of	our	proved	reserves.	Future	reserve revisions	could	also	result	from	changes	in,	among	other	things,	governmental	regulation	and	severance	and	other	production	taxes.

								Reserve	estimation	is	a	subjective	process	that	involves	estimating	volumes	to	be	recovered	from	underground	accumulations	of	oil	and	natural	gas	that	cannot	be directly	measured.	Estimates	of	economically	recoverable	oil	and	natural	gas	reserves	and	of	future	net	cash	flows	depend	upon	a	number	of	variable	factors	and assumptions,	including:

•location,	size	and	shape	of	the	accumulation	as	well	as	fluid,	rock	and	producing	characteristics	of	the	accumulation;

•historical	production	from	the	area,	compared	with	production	from	other	comparable	producing	areas;

•the	assumed	effects	of	regulation	by	governmental	agencies;

•assumptions	concerning	future	oil	and	natural	gas	prices;	and

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

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

•the	amount	and	timing	of	oil	and	natural	gas	production;

•the	revenues	and	costs	associated	with	that	production;	and

•the	amount	and	timing	of	future	development	expenditures.

								The	discounted	future	net	revenues	from	our	proved	reserves	reflected	in	this	report	should	not	be	considered	as	the	market	value	of	the	reserves	attributable	to	our properties.	As	required	by	SEC	Rule	4-10	of	Regulation	S-X,	the	estimated	discounted	future	net	revenues	from	our	proved	reserves	are	based	on	prices	and	costs	as	of the	date	of	the	estimate,	while	actual	future	prices	and	costs	may	be	materially	higher	or	lower.

								In	addition,	the	10	percent	discount	factor	required	by	the	applicable	rules	of	the	SEC	to	be	used	to	calculate	discounted	future	net	revenues	for	reporting	purposes is	not	necessarily	the	most	appropriate	discount	factor	based	on	our	cost	of	capital	and	the	risks	associated	with	our	business	and	the	oil	and	natural	gas	industry	in general.

# If	we	are	unsuccessful	in	acquiring	or	finding	additional	reserves,	our	future	oil	and	natural	gas	production	would	decline,	thereby	reducing	our	cash	flows and	results	of	operations	and	impairing	our	financial	condition.

								The	rate	of	production	from	oil	and	natural	gas	properties	generally	declines	as	reserves	are	depleted.	Except	to	the	extent	we	acquire	interests	in	additional properties	containing	proved	reserves,	conduct	successful	exploration	and	development	activities	or,	through	engineering	studies,	optimize	production	performance, identify	additional	reservoirs	not	currently	producing	or	secondary	recovery	reserves,	our	proved	reserves	will	decline	materially	as	oil	and	natural	gas	is	produced. Accordingly,	to	the	extent	we	are	not	successful	in	replacing	the	oil	and	natural	gas	we	produce,	our	future	revenues	will	decline.	Creating	and	maintaining	an	inventory of	prospects	for	future	production	depends	on	many	factors,	including:

•obtaining	rights	to	explore	for,	develop	and	produce	oil	and	natural	gas	in	promising	areas;

•drilling	success;

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

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

# Increases	in	crude	oil	prices	and	environmental	regulations	may	reduce	our	refined	product	gross	margins.

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

								In	addition,	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	our	refining,	marketing	and	transportation	operations,	which	may	reduce	our	refined	product	gross	margins.

# If	we	do	not	compete	successfully	with	our	competitors,	our	future	operating	performance	and	profitability	could	materially	decline.

								We	compete	with	major	integrated	and	independent	oil	and	gas	companies,	as	well	as	national	oil	companies,	for	the	acquisition	of	oil	and	natural	gas	leases	and other	properties.	We	compete	with	these	companies	for	the	equipment	and	labor	required	to	develop	and	operate	those	properties	and	in	the	marketing	of	oil	and	natural gas	to	end-users.	In	addition,	in	implementing	our	integrated	gas	strategy,	we	compete	with	major	integrated	energy	companies	in

bidding	for	and	developing	liquefied	natural	gas	projects,	which	are	very	capital	intensive.	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	acquiring	additional	properties	and	bidding	for	and	developing	additional	projects,	such as	LNG	production	facilities.	Many	of	our	larger	competitors	in	the	LNG	market	can	complete	more	projects	than	we	have	the	capacity	to	complete,	which	could	lead those	competitors	to	realize	economies	of	scale	that	we	are	unable	to	realize.	In	addition,	many	of	our	larger	competitors	may	be	better	able	to	respond	to	factors	that affect	the	demand	for	oil	and	natural	gas,	such	as	changes	in	worldwide	prices	and	levels	of	production,	the	cost	and	availability	of	alternative	fuels	and	the	application of	government	regulations.

# We	will	continue	to	incur	substantial	capital	expenditures	and	operating	costs	as	a	result	of	compliance	with,	and	changes	in	environmental	laws	and regulations,	and,	as	a	result,	our	profitability	could	be	materially	reduced.

								Our	businesses	are	subject	to	numerous	laws	and	regulations	relating	to	the	protection	of	the	environment.	We	have	incurred	and	will	continue	to	incur	substantial capital,	operating	and	maintenance,	and	remediation	expenditures	as	a	result	of	these	laws	and	regulations.	To	the	extent	these	expenditures,	as	with	all	costs,	are	not ultimately	reflected	in	the	prices	of	our	products	and	services,	our	operating	results	will	be	adversely	affected.	The	specific	impact	of	these	laws	and	regulations	on	us and	our	competitors	may	vary	depending	on	a	number	of	factors,	including	the	age	and	location	of	operating	facilities,	marketing	areas	and	production	processes.	We may	also	be	required	to	make	material	expenditures	to	modify	operations,	install	pollution	control	equipment,	perform	site	cleanups	or	curtail	operations.	We	may become	subject	to	liabilities	that	we	currently	do	not	anticipate	in	connection	with	new,	amended	or	more	stringent	requirements,	stricter	interpretations	of	existing requirements	or	the	future	discovery	of	contamination.	In	addition,	any	failure	by	us	to	comply	with	existing	or	future	laws	could	result	in	civil	or	criminal	fines	and other	enforcement	actions	against	us.

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

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

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

								Local	political	and	economic	factors	in	international	markets	could	have	a	material	adverse	effect	on	us.	Approximately	56	percent	of	our	oil	and	natural	gas production	in	2006	was	derived	from	production	outside	the	United	States	and	approximately	72	percent	of	our	proved	reserves	as	of	December	31,	2006,	were	located outside	the	United	States.

								There	are	many	risks	associated	with	operations	in	international	markets,	including	changes	in	foreign	governmental	policies	relating	to	crude	oil,	natural	gas	or refined	product	pricing	and	taxation,	other	political,	economic	or	diplomatic	developments	and	international	monetary	fluctuations.	These	risks	include:

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

•the	possibility	that	a	foreign	government	may	seize	our	property	with	or	without	compensation,	may	attempt	to	renegotiate	or	revoke	existing	contractual arrangements	or	may	impose	additional	taxes	or	royalty	burdens;	and

•fluctuating	currency	values,	hard	currency	shortages	and	currency	controls.

								Continued	hostilities	in	the	Middle	East	and	the	occurrence	or	threat	of	future	terrorist	attacks	could	adversely	affect	the	economies	of	the	United	States	and	other developed	countries.	A	lower	level	of	economic	activity	could	result	in	a	decline	in	energy	consumption,	which	could	cause	our	revenues	and	margins	to	decline	and limit	our	future	growth	prospects.	These	risks	could	lead	to	increased	volatility	in	prices	for	crude	oil,	natural	gas	and	refined	products.	In	addition,	these	risks	could increase	instability	in	the	financial	and	insurance	markets	and	make	it	more	difficult	for	us	to	access	capital	and	to	obtain	the	insurance	coverage	that	we	consider adequate.

								Actions	of	the	U.S.	government	through	tax	and	other	legislation,	executive	order	and	commercial	restrictions	could	reduce	our	operating	profitability	both	in	the United	States	and	abroad.	The	U.S.	government	can	prevent	or	restrict	us	from	doing	business	in	foreign	countries.	These	restrictions	and	those	of	foreign	governments have	in	the

past	limited	our	ability	to	operate	in,	or	gain	access	to,	opportunities	in	various	countries.	Actions	by	both	the	United	States	and	host	governments	have	affected operations	significantly	in	the	past	and	will	continue	to	do	so	in	the	future.

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

								Our	exploration	and	production	operations	are	subject	to	unplanned	occurrences,	including	blowouts,	explosions,	fires,	loss	of	well	control,	spills,	hurricanes	and other	adverse	weather,	labor	disputes	and	accidents.	In	addition,	our	refining,	marketing	and	transportation	operations	are	subject	to	business	interruptions	due	to scheduled	refinery	turnarounds	and	unplanned	events	such	as	explosions,	fires,	pipeline	ruptures	or	other	interruptions,	crude	oil	or	refined	product	spills,	inclement weather	and	labor	disputes.	Our	operations	are	also	subject	to	the	additional	hazards	of	pollution,	releases	of	toxic	gas	and	other	environmental	hazards	and	risks,	as	well as	hazards	of	marine	operations,	such	as	capsizing,	collision	and	damage	or	loss	from	severe	weather	conditions.	These	hazards	could	result	in	loss	of	human	life, significant	damage	to	property	and	equipment,	environmental	pollution,	impairment	of	operations	and	substantial	losses	to	us.	Certain	hazards	have	adversely	affected	us in	the	past,	and	litigation	arising	from	a	catastrophic	occurrence	in	the	future	involving	us	or	any	of	our	assets	or	operations	may	result	in	our	being	named	as	a	defendant in	one	or	more	lawsuits	asserting	potentially	large	claims	or	being	assessed	potentially	substantial	fines	by	governmental	authorities.

								We	maintain	insurance	against	many,	but	not	all,	potential	losses	or	liabilities	arising	from	these	operating	hazards	in	amounts	that	we	believe	to	be	prudent. Uninsured	losses	and	liabilities	arising	from	operating	hazards	could	reduce	the	funds	available	to	us	for	exploration,	drilling	and	production	and	could	materially	reduce our	profitability.	Historically,	we	have	maintained	insurance	coverage	for	physical	damage	and	resulting	business	interruption	to	our	major	onshore	and	offshore facilities.	Due	to	hurricane	activity	in	recent	years,	the	availability	of	insurance	coverage	for	our	offshore	facilities	for	windstorms	in	the	Gulf	of	Mexico	region	has	been reduced	or,	in	many	instances,	it	is	prohibitively	expensive.	As	a	result,	our	exposure	to	losses	from	future	windstorm	activity	in	the	Gulf	of	Mexico	region	has	increased.

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

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

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

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

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

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

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

Basket	One	–	This	applies	to	the	first	$30	million	of	contingent	liability	deductions	(increased	by	inflation	each	year	up	to	a	maximum	of	$60	million)	that	we	may claim	in	each	year	for	the	first	20	years	following	the	acquisition.	The	benefit	of	Basket	One	deductions	is	determined	by	multiplying	the	amount	of	the	deduction	by 32%	(or,	if	different,	by	a	percentage	equal	to	three	percentage	points	less	than	the	highest	federal	income	tax	rate	during	the	applicable	tax	year).	We	are	obligated	to pay	this	amount	to	Ashland.	The	computation	and	payment	of	Basket	One	amounts	does	not	depend	on	our	ability	to	generate	actual	tax	savings	from	the	use	of	the contingent	liability	deductions	in	Basket	One.	Upon	specified	events	related	to	Ashland	(or	after	20	years),	the	contingent	liability	deductions	that	would

otherwise	have	been	compensated	under	Basket	One	will	be	taken	into	account	in	Basket	Two.	In	addition,	Basket	One	applies	only	for	federal	income	tax	purposes; state,	local	or	foreign	tax	benefits	attributable	to	specified	liability	deductions	will	be	compensated	only	under	Basket	Two.

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

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

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

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

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

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

•the	transferor:

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

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

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

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

valuation	of	any	business	and	a	determination	of	the	solvency	of	any	entity	involve	numerous	assumptions	and	uncertainties,	and	it	is	possible	that	a	court	could	disagree with	our	conclusions.

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

								In	connection	with	the	separation	of	United	States	Steel	from	Marathon,	United	States	Steel	agreed	to	hold	Marathon	harmless	from	and	against	various	liabilities. While	we	cannot	estimate	some	of	these	liabilities,	the	portion	of	these	liabilities	that	we	can	estimate	amounts	to	$564	million	as	of	December	31,	2006,	including accrued	interest	of	$11	million.	If	United	States	Steel	fails	to	satisfy	any	of	those	obligations,	we	would	be	required	to	satisfy	them	and	seek	indemnification	from United	States	Steel.	In	that	event,	our	indemnification	claims	against	United	States	Steel	would	constitute	general	unsecured	claims,	effectively	subordinate	to	the	claims of	secured	creditors	of	United	States	Steel.

								Under	applicable	law	and	regulations,	we	also	may	be	liable	for	any	defaults	by	United	States	Steel	in	the	performance	of	its	obligations	to	fund	its	ERISA	pension plans	and	pay	other	obligations	related	to	periods	prior	to	the	effective	date	of	the	separation.

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

If	the	transfer	of	ownership	of	various	assets	and	operations	by	Marathon's	former	parent	entity	to	Marathon	was	held	to	be	a	fraudulent	conveyance	or transfer,	United	States	Steel's	creditors	may	be	able	to	obtain	recovery	from	us	or	other	relief	detrimental	to	the	holders	of	our	common	stock.

								In	July	2001,	USX	Corporation	("Old	USX")	effected	a	reorganization	of	the	ownership	of	its	businesses	in	which	it	created	Marathon	as	its	publicly	owned	parent holding	company	and	transferred	ownership	of	various	assets	and	operations	to	Marathon,	and	it	merged	into	a	newly	formed	subsidiary	which	survived	as	United	States Steel.

								If	a	court	in	a	bankruptcy	case	regarding	United	States	Steel	or	a	lawsuit	brought	by	its	creditors	or	their	representative	were	to	find	that,	under	the	applicable fraudulent	conveyance	or	transfer	law:

•the	transfer	by	Old	USX	to	Marathon	or	related	transactions	were	undertaken	by	Old	USX	with	the	intent	of	hindering,	delaying	or	defrauding	its	existing or	future	creditors;	or

•Old	USX	received	less	than	reasonably	equivalent	value	or	fair	consideration,	or	no	value	or	consideration,	in	connection	with	those	transactions,	and either	it	or	United	States	Steel

•was	insolvent	or	rendered	insolvent	by	reason	of	those	transactions,

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

•intended	to	incur,	or	believed	that	it	would	incur,	debts	beyond	its	ability	to	pay	as	they	mature,

then	that	court	could	determine	those	transactions	entitled	one	or	more	classes	of	creditors	of	United	States	Steel	to	equitable	relief	from	us.	Such	a	determination	could permit	the	unpaid	creditors	to	obtain	recovery	from	us	or	could	result	in	other	actions	detrimental	to	the	holders	of	our	common	stock.	The	measure	of	insolvency	for purposes	of	these	considerations	would	vary	depending	on	the	law	of	the	jurisdiction	being	applied.

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

								Our	restated	certificate	of	incorporation	authorizes	us	to	issue,	without	the	approval	of	our	stockholders,	one	or	more	classes	or	series	of	preferred	stock	having such	preferences,	powers	and	relative,	participating,	optional	and	other	rights,	including	preferences	over	our	common	stock	respecting	dividends	and	distributions,	as our	Board	of	Directors	generally	may	determine.	The	terms	of	one	or	more	classes	or	series	of	preferred	stock	could	dilute	the	voting	power	or	reduce	the	value	of	our common	stock.	For	example,	we	could	grant	holders	of	preferred	stock	the	right	to	elect	some	number	of	our	directors	in	all	events	or	on	the	happening	of	specified events	or	the	right	to	veto	specified	transactions.	Similarly,	the	repurchase	or	redemption	rights	or	liquidation	preferences	we	could	assign	to	holders	of	preferred	stock could	affect	the	residual	value	of	the	common	stock.

# Item	1B.	Unresolved	Staff	Comments

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

# Item	2.	Properties

								The	location	and	general	character	of	the	principal	oil	and	gas	properties,	refineries,	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	"Financial	Statements	and	Supplementary	Data	–	Supplementary	Information	on	Oil	and	Gas	Producing Activities	–	Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves"	on	pages	F-46	through	F-47.

# 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."

# Item	3.	Legal	Proceedings

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

# Natural	Gas	Royalty	Litigation

								As	of	December	31,	2005,	Marathon	had	been	served	in	two	qui	tam	cases,	which	allege	that	federal	and	Indian	lessees	violated	the	False	Claims	Act	with	respect to	the	reporting	and	payment	of	royalties	on	natural	gas	and	natural	gas	liquids.	The	Department	of	Justice	has	announced	that	it	would	intervene	or	has	reserved judgment	on	whether	to	intervene	against	specified	oil	and	gas	companies	and	also	announced	that	it	would	not	intervene	against	certain	other	defendants	including Marathon.	One	of	the	cases,	U.S.	ex	rel	Jack	J.	Grynberg	v.	Alaska	Pipeline	Co.,	et	al,	which	was	primarily	a	gas	measurement	case,	was	dismissed	as	to	Marathon	on October	20,	2006	on	jurisdictional	grounds.	The	second	case,	U.S.	ex	rel	Harrold	E.	Wright	v.	Agip	Petroleum	Co.	et	al,	is	primarily	a	gas	valuation	case.	The	Wright case	is	in	the	discovery	phase.

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

# Powder	River	Basin	Litigation

								The	U.S.	Bureau	of	Land	Management	("BLM")	completed	multi-year	reviews	of	potential	environmental	impacts	from	coal	bed	methane	development	on	federal lands	in	the	Powder	River	Basin,	including	those	in	Wyoming.	The	BLM	signed	a	Record	of	Decision	("ROD")	on	April	30,	2003	supporting	increased	coal	bed	methane development.	Plaintiff	environmental	and	other	groups	filed	suit	in	May	2003	in	federal	court	against	the	BLM	to	stop	coal	bed	methane	development	on	federal	lands	in the	Powder	River	Basin	until	the	BLM	conducted	additional	environmental	impact	studies.	Marathon	intervened	as	a	party	in	the	ongoing	litigation	before	the	Wyoming Federal	District	Court.

								As	these	lawsuits	to	delay	energy	development	in	the	Powder	River	Basin	progress	through	the	courts,	the	Wyoming	BLM	continues	to	process	permits	to	drill under	the	ROD.

								In	May	2004,	plaintiff	environmental	groups	Environmental	Defense	et	al	filed	suit	against	the	U.S.	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	the	BLM	be	ordered	to	cease	issuing	leases	and	permits	for	energy	development,	until	additional	analysis	of predicted	air	impacts	is	conducted.	Marathon	and	its	subsidiary	Pennaco	Energy,	Inc.	intervened	in	this	litigation.

# MTBE	Litigation

								Marathon	is	a	defendant	along	with	many	other	refining	companies	in	over	40	cases	in	11	states	alleging	methyl	tertiary-butyl	ether	("MTBE")	contamination	in groundwater.	All	of	these	cases	have	been	consolidated	in	a	multi-district	litigation	in	the	Southern	District	of	New	York	for	preliminary	proceedings.	The	judge	in	this multi-district	litigation	ruled	on	April	20,	2005	that	some	form	of	market	share	liability	would	apply.	Market	share	liability	enables	a	plaintiff	to	sue	manufacturers	who represent	a	substantial	share	of	a	market	for	a	particular	product	and	shift	the	burden	of	identification	of	who	actually	made	the	product	to	the	defendants,	effectively forcing	a	defendant	to	show	that	it	did	not	produce	the	MTBE	which	allegedly	caused	the	damage.	The	judge	further	allowed	cases	to	go	forward	in	New	York	and	11 other	states,	based	upon	varying	theories	of	collective	liability,	and	predicted	that	a	new	theory	of	market	share	liability	would	be	recognized	in	Connecticut,	Indiana	and Kansas.	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	the	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	Marathon's	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.	Marathon	stopped	producing	MTBE	at	its	refineries	in	October	2002.	The	potential	impact of	these	recent	cases	and	future	potential	similar	cases	is	uncertain.	The	Company	will	defend	these	cases	vigorously.

# Product	Contamination	Litigation

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

# Environmental	Proceedings

# U.S.	EPA	Litigation

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

								In	September	2006,	Marathon	and	other	oil	and	gas	companies	joined	the	State	of	Wyoming	in	filing	a	Petition	for	Review	against	the	U.S.	EPA	in	the	U.S.	District Court	for	the	District	of	Wyoming.	These	actions	seek	a	Court	order	mandating	the	EPA	to	disapprove	Montana's	2006	amended	water	quality	standards,	on	grounds	that the	standards	lack	sound	scientific	justification,	they	are	arbitrary	and	capricious,	and	were	adopted	contrary	to	law.	These	September	2006	actions	have	been consolidated	with	our	pending	April	2006	action	against	the	U.S.	EPA	in	the	same	Court.	The	water	quality	amendments	at	issue,	if	approved,	could	require	more stringent	discharge	limits	and	have	the	potential	to	require	certain	Wyoming	coal	bed	methane	operations	to	perform	more	costly	water	treatment	or	inject	produced water.	Approval	of	these	standards	could	delay	or	prevent	obtaining	permits	needed	to	discharge	produced	water	to	streams	flowing	from	Wyoming	into	Montana.	The Court	has	stayed	this	case,	and	another	filed	in	April	2006,	until	August	2007	while	the	U.S.	EPA	mediates	the	matter	between	Montana,	Wyoming	and	the	Northern Cheyenne	tribe.

# Montana	Litigation

								In	June	2006,	Marathon	filed	a	complaint	for	declaratory	judgment	in	Montana	State	District	Court	against	the	Montana	Board	of	Environmental	Review	("MBER") and	the	Montana	Department	of	Environmental	Quality,	seeking	to	set	aside	and	declare	invalid	certain	regulations	of	the	MBER	that	single	out	the	coal	bed	natural	gas industry	and	a	few	streams	in	eastern	Montana	for	excessively	severe	and	unjustified	restrictions	for	surface	water	discharges	of	produced	water	from	coal	bed	methane operations.	None	of	the	streams	affected	by	the	regulations	suffers	impairment	from	coal	bed	natural	gas	discharges.

# Wyoming	Proceedings

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

# Other	Proceedings

								The	following	is	a	summary	of	proceedings	involving	Marathon	that	were	pending	or	contemplated	as	of	December	31,	2006	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	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.

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

								As	of	December	31,	2006,	Marathon	had	been	identified	as	a	PRP	at	a	total	of	nine	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	six	of	these	sites	will	be	under $1	million	per	site	(with	three	of	these	six	sites	being	under	$100,000	each).	As	to	the	remaining	three	sites	of	the	nine,	Marathon	believes	that	its	liability	for	cleanup and	remediation	costs	in	connection	with	two	of	these	sites	will	be	under	$4	million	per	site	with	the	last	site	having	costs	that	cannot	be	estimated	at	this	time.

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

								There	are	also	119	sites,	excluding	retail	marketing	outlets,	related	to	Marathon	where	remediation	is	being	sought	under	other	environmental	statutes,	both	federal and	state,	or	where	private	parties	are	seeking	remediation	through	discussions	or	litigation.	Based	on	currently	available	information,	which	is	in	many	cases preliminary	and	incomplete,	Marathon	believes	that	its	liability	for	cleanup	and	remediation	costs	in	connection	with	27	of	these	sites	will	be	under	$100,000	per	site, that	45	sites	have	potential	costs	between	$100,000	and	$1	million	per	site	and	that	19

sites	may	involve	remediation	costs	between	$1	million	and	$5	million	per	site.	Eleven	sites	have	incurred	remediation	costs	of	more	than	$5	million	per	site	and	there are	17	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	30	years,	Marathon	anticipates	spending	approximately	$7	million	at	this	site.	In	2007,	interim remediation	measures	will	occur	and	appropriate	site	characterization	and	risk-based	assessments	necessary	for	closure	will	be	refined	and	may	change	the	estimated future	expenditures	for	this	site.	The	closure	strategy	being	developed	for	this	site	and	ongoing	work	at	the	site	are	subject	to	approval	by	the	MDEQ.	Expenditures	in 2006	and	2005	were	$488,000	and	$540,000,	with	expenditures	in	2007	expected	to	be	approximately	$2	million.

								MPC	has	had	a	pending	enforcement	matter	with	the	Illinois	Environmental	Protection	Agency	and	the	Illinois	Attorney	General's	Office	since	2002	concerning self-reporting	of	possible	emission	exceedences	and	permitting	issues	related	to	storage	tanks	at	the	Robinson,	Illinois	refinery.

								In	2005,	MPC	received	a	Notice	of	Violation	from	the	U.S.	EPA	alleging	33	violations	of	Clean	Air	Act	fuels	requirements.	The	alleged	violations	largely	resulted from	MPC's	attest	engagements	submitted	to	the	Agency	under	the	Reformulated	Gasoline	and	Anti	Dumping	programs.	In	2006,	MPC	reached	an	administrative settlement	with	the	U.S.	EPA	where	MPC	paid	a	civil	penalty	of	$139,000	and	resolved	this	Notice	of	Violation.

								MPC	received	an	enforcement	action	from	the	Minnesota	Pollution	Control	Agency	("MPCA")	in	the	fourth	quarter	of	2006	where	the	MPCA	seeks	a	civil	penalty of	$121,800	for	a	release	of	catalyst	from	the	fluid	catalytic	cracking	unit	at	the	St.	Paul	Park	refinery	in	2004	and	other	alleged	violations.	Discussions	will	be	held	with the	MPCA	in	2007	and	the	Company	expects	to	resolve	the	matter	within	the	year.

# SEC	Investigation	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	followed	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.	Marathon	voluntarily	produced	documents	requested	by	the	SEC	in	that	inquiry.	On	August	1,	2005,	Marathon	received	a	subpoena issued	by	the	SEC	pursuant	to	a	formal	order	of	investigation	requiring	the	production	of	the	documents	that	had	already	been	produced	or	that	were	in	the	process	of being	identified	and	produced	in	response	to	the	SEC's	prior	requests,	and	requesting	the	production	of	additional	materials.	Marathon	has	been	and	intends	to	continue cooperating	with	the	SEC	in	this	investigation.

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

# PART	II

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

								The	principal	market	on	which	Marathon's	common	stock	is	traded	is	the	New	York	Stock	Exchange.	Marathon's	common	stock	is	also	traded	on	the	Chicago Stock	Exchange.	Information	concerning	the	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-42.

								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	consolidated	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	quarter	ended	December	31,	2006	of	equity	securities that	are	registered	by	Marathon	pursuant	to	Section	12	of	the	Exchange	Act:

# ISSUER	PURCHASES	OF	EQUITY	SECURITIES

|  | Total	Number |  | Part	of	Publicly | Approximate	Dollar	Value	of |
| :--- | :--- | :--- | :--- | :--- |
|  | of\tShares | Average\tPrice | Announced\tPlans | Shares\tthat\tMay\tYet\tBe |
| Period | Purchased^(a)(b) | Paid\tper\tShare | or\tPrograms^(d) | Purchased\tUnder\tthe\tPlans\tor |
|  |  |  |  | Programs^(d) |
| 10/01/06\t–\t10/31/06 | 2,317,869 | $79.90 | 2,302,642 | $664,177,964 |
| 11/01/06\t–\t11/30/06 | 2,214,981 | $89.01 | 2,212,358 | $467,266,675 |
| 12/01/06\t–\t12/31/06 | 1,859,740(c) | $94.13 | 1,815,000 | $296,427,158 |
| Total | 6,392,590 | $87.19 | 6,330,000 |  |

(a) 46,872	shares	of	restricted	stock	were	delivered	by	employees	to	Marathon,	upon	vesting,	to	satisfy	tax	withholding	requirements.

(b) Under	the	terms	of	the	Acquisition,	Marathon	paid	Ashland	shareholders	cash	in	lieu	of	issuing	fractional	shares	of	Marathon's	common	stock	to	which	such	holder	would	otherwise	be	entitled.	Marathon acquired	7	shares	due	to	Acquisition	exchanges	and	Ashland	share	transfers	pending	at	the	time	of	closing	of	the	Acquisition.

(c) 15,711	shares	were	repurchased	in	open-market	transactions	to	satisfy	the	requirements	for	dividend	reinvestment	under	the	Marathon	Oil	Corporation	Dividend	Reinvestment	and	Direct	Stock	Purchase	Plan (the	"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.

(d) In	January	2006,	we	announced	a	$2	billion	share	repurchase	program.	In	January	2007,	our	Board	of	Directors	authorized	the	extension	of	this	program	by	an	additional	$500	million.	As	of	February	21,	2007, the	Company	had	repurchased	24.2	million	common	shares	at	a	cost	of	$2	billion.

# Item	6.	Selected	Financial	Data

# (In	millions,	except	per	share	data)

|  | (a) | (a) |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- |
|  | 2006 | 2005 | 2004 | 2003 | 2002 |
| Statement\tof\tIncome\tData: |  |  |  |  |  |
| (b)\nRevenues | $64,896 | $62,986 | $49,465 | $40,907 | $31,295 |
| Income\tfrom\tcontinuing\toperations | 4,957 | 3,006 | 1,294 | 1,010 | 507 |
| Net\tincome | 5,234 | 3,032 | 1,261 | 1,321 | 516 |
| Basic\tper\tshare\tdata: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $13.85 | $8.44 | $3.85 | $3.26 | $1.63 |
| Net\tincome | $14.62 | $8.52 | $3.75 | $4.26 | $1.66 |
| Diluted\tper\tshare\tdata: |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $13.73 | $8.37 | $3.83 | $3.25 | $1.63 |
| Net\tincome | $14.50 | $8.44 | $3.73 | $4.26 | $1.66 |
| Statement\tof\tCash\tFlows\tData: |  |  |  |  |  |
| Capital\texpenditures\tfrom\tcontinuing\toperations | $3,433 | $2,796 | $2,141 | $1,873 | $1,520 |
| Dividends\tpaid | 547 | 436 | 348 | 298 | 285 |
| Dividends\tpaid\tper\tshare | $1.53 | $1.22 | $1.03 | $0.96 | $0.92 |
| Balance\tSheet\tData\tas\tof\tDecember\t31: |  |  |  |  |  |
| Total\tassets | $30,831 | $28,498 | $23,423 | $19,482 | $17,812 |
| Total\tlong-term\tdebt,\tincluding\tcapitalized\tleases | 3,061 | 3,698 | 4,057 | 4,085 | 4,410 |

(a) On	June	30,	2005,	Marathon	acquired	the	38	percent	ownership	interest	in	MPC	previously	held	by	Ashland,	making	it	wholly-owned	by	Marathon.	See	Note	6	to	the	consolidated	financial	statements. (b) Effective	April	1,	2006,	Marathon	changed	its	accounting	for	matching	buy/sell	transactions.	This	change	had	no	effect	on	income	from	continuing	operations	or	net	income,	but	the	revenues	and	cost	of revenues	recognized	after	April	1,	2006	are	less	than	the	amounts	that	would	have	been	recognized	under	previous	accounting	practices.	See	Note	2	to	the	consolidated	financial	statements.

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

								Marathon	is	engaged	in	worldwide	exploration,	production	and	marketing	of	crude	oil	and	natural	gas;	domestic	refining,	marketing	and	transportation	of	crude	oil and	petroleum	products,	primarily	in	the	Midwest,	the	upper	Great	Plains	and	southeastern	United	States;	and	worldwide	marketing	and	transportation	of	products manufactured	from	natural	gas,	such	as	LNG	and	methanol,	and	development	of	other	projects	to	link	stranded	natural	gas	resources	with	key	demand	areas.

Management's	Discussion	and	Analysis	of	Financial	Condition	and	Results	of	Operations	should	be	read	in	conjunction	with	Item	1.	Business,	Item	1A.	Risk	Factors, 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	business.	These	statements	typically	contain	words	such	as	"anticipates,"	"believes,"	"estimates,"	"expects,"	"targets,"	"plans," "projects,"	"could,"	"may,"	"should,"	"would"	or	similar	words	indicating	that	future	outcomes	are	uncertain.	In	accordance	with	"safe	harbor"	provisions	of	the	Private Securities	Litigation	Reform	Act	of	1995,	these	statements	are	accompanied	by	cautionary	language	identifying	important	factors,	though	not	necessarily	all	such factors,	which	could	cause	future	outcomes	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

								Unless	specifically	noted,	amounts	for	the	refining,	marketing	and	transportation	segment	include	the	38	percent	interest	in	MPC	held	by	Ashland	prior	to	the Acquisition	on	June	30,	2005,	and	amounts	for	the	integrated	gas	segment	include	the	25	percent	interest	held	by	SONAGAS	(previously	held	by	GEPetrol)	in	all periods	and	the	8.5	percent	interest	held	by	Mitsui	and	the	6.5	percent	interest	held	by	Marubeni	since	July	25,	2005.

								Effective	January	1,	2006,	we	revised	our	measure	of	segment	income	to	include	the	effects	of	minority	interests	and	income	taxes	related	to	the	segments.	In addition,	the	results	of	activities	primarily	associated	with	the	marketing	of	our	equity	natural	gas	production,	which	had	been	presented	as	part	of	the	Integrated	Gas segment	prior	to	2006,	are	now	included	in	the	Exploration	and	Production	segment.	Segment	results	for	all	periods	presented	reflect	these	changes.

# Overview

								Exploration	and	production	segment	revenues	correlate	closely	with	prevailing	prices	for	the	various	qualities	of	crude	oil	and	natural	gas	we	produce.	The	increase in	our	E&P	segment	revenues	in	2006	is	primarily	related	to	increased	production,	particularly	from	Libya	where	the	first	liquid	hydrocarbon	sales	occurred	in	the	first quarter	of	2006;	however,	our	2006	revenues	also	tracked	the	changes	in	market	prices	for	commodities.	Higher	prices	for	crude	oil	early	in	2006	reflected	concerns about	international	supply	due	to	unrest	in	oil-producing	countries	and	the	potential	for	hurricane	damage	in	the	U.S.	Gulf	of	Mexico.	As	hurricane	season	came	to	an end	without	a	major	storm	in	the	Gulf	of	Mexico	and	in	the	absence	of	significant	international	supply	shortfalls	or	disruptions,	crude	oil	prices	declined.	The	average spot	price	during	2006	for	West	Texas	Intermediate	("WTI"),	a	benchmark	crude	oil,	was	$66.25	per	barrel,	up	from	an	average	of	$56.70	in	2005,	and	ended	the	year	at $61.05.	The	average	differential	between	WTI	and	Brent	(an	international	benchmark	crude	oil)	narrowed	to	$1.07	in	2006	from	$2.18	in	2005.	Our	domestic	crude	oil production	is	on	average	heavier	and	higher	in	sulfur	content	than	light	sweet	WTI.	Heavier	and	higher	sulfur	crude	oil	(commonly	referred	to	as	heavy	sour	crude	oil) sells	at	a	discount	to	light	sweet	crude	oil.	Our	international	crude	oil	production	is	relatively	sweet	and	is	generally	sold	in	relation	to	the	Brent	crude	benchmark.

								Natural	gas	prices	were	lower	in	2006	compared	to	2005.	A	significant	portion	of	our	United	States	lower	48	natural	gas	production	is	sold	at	bid-week	prices	or first-of-month	indices	relative	to	our	specific	producing	areas.	The	average	Henry	Hub	first-of-month	price	index	was	$1.41	per	mcf	lower	in	2006	than	the	2005 average.	Our	natural	gas	prices	in	Alaska	are	largely	contractual,	while	natural	gas	sales	there	are	seasonal	in	nature,	trending	down	during	the	second	and	third	quarters of	each	year	and	increasing	during	the	fourth	and	first	quarters.	Our	other	major	natural	gas-producing	regions	are	Europe	and	Equatorial	Guinea,	where	large	portions of	our	natural	gas	are	sold	at	contractual	prices,	making	realized	prices	in	these	areas	less	volatile.

								For	information	on	commodity	price	risk	management,	see	"Item	7A.	Quantitative	and	Qualitative	Disclosures	about	Market	Risk."

								E&P	segment	income	during	2006	was	up	approximately	6	percent	from	2005	levels,	impacted	by	increased	liquid	hydrocarbon	sales	volumes,	primarily	due	to	the resumption	of	production	in	Libya,	and	the	higher	liquid

hydrocarbon	prices	discussed	above,	partially	offset	by	higher	income	taxes,	primarily	in	Libya,	operating	costs	and	exploration	expenses	and	decreases	in	natural	gas sales	volumes.

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

								The	refining	and	wholesale	marketing	gross	margin	is	the	difference	between	the	prices	of	refined	products	sold	and	the	costs	of	crude	oil	and	other	charge	and blendstocks	refined,	the	costs	of	purchased	products	and	manufacturing	expenses,	including	depreciation.	We	purchase	crude	oil	to	satisfy	our	refineries'	throughput requirements.	As	a	result,	our	refining	and	wholesale	marketing	gross	margin	could	be	adversely	affected	by	rising	crude	oil	and	other	charge	and	blendstock	prices	that are	not	recovered	in	the	marketplace.	The	crack	spread,	which	is	generally	a	measure	of	the	difference	between	spot	market	gasoline	and	distillate	prices	and	spot	market crude	oil	costs,	is	a	commonly	used	industry	indicator	of	refining	margins.	In	addition	to	changes	in	the	crack	spread,	our	refining	and	wholesale	marketing	gross	margin is	impacted	by	the	types	of	crude	oil	and	other	charge	and	blendstocks	we	process,	the	selling	prices	we	realize	for	all	the	refined	products	we	sell,	the	cost	of	purchased product	and	our	level	of	manufacturing	costs.	We	process	significant	amounts	of	sour	crude	oil	which	enhances	our	competitive	position	in	the	industry	as	sour	crude	oil typically	can	be	purchased	at	a	discount	to	sweet	crude	oil.	Over	the	last	three	years,	approximately	60	percent	of	the	crude	oil	throughput	at	our	refineries	has	been	sour crude	oil.	As	one	of	the	largest	U.S.	producers	of	asphalt,	our	refining	and	wholesale	marketing	gross	margin	is	also	impacted	by	the	selling	price	of	asphalt.	Sales	of asphalt	increase	during	the	highway	construction	season	in	our	market	area,	which	is	typically	in	the	second	and	third	quarters	of	each	year.	The	selling	price	of	asphalt is	dependent	on	the	cost	of	crude	oil,	the	price	of	alternative	paving	materials	and	the	level	of	construction	activity	in	both	the	private	and	public	sectors.	We	supplement our	refining	production	by	purchasing	gasolines	and	distillates	in	the	spot	market	to	resell	at	wholesale.	In	addition,	we	purchase	ethanol	for	blending	with	gasoline.	Our refining	and	wholesale	marketing	gross	margin	is	impacted	by	the	cost	of	these	purchased	products,	which	varies	with	available	supply	and	demand.	Finally,	our	refining and	wholesale	marketing	gross	margin	is	impacted	by	changes	in	manufacturing	costs	from	period	to	period,	which	are	primarily	driven	by	the	level	of	maintenance activities	at	the	refineries	and	the	price	of	purchased	natural	gas	used	for	plant	fuel.	Our	refining	and	wholesale	marketing	gross	margin	has	been	historically	volatile	and varies	with	the	level	of	economic	activity	in	our	various	marketing	areas,	the	regulatory	climate,	logistical	capabilities	and	expectations	regarding	the	adequacy	of refined	product,	ethanol	and	raw	material	supplies.

								Together	with	our	June	30,	2005	acquisition	of	the	38	percent	minority	interest	in	MPC,	our	improved	refining	and	wholesale	marketing	gross	margin	in	2006	was the	key	driver	of	the	72	percent	increase	in	RM&T	segment	income	over	2005.	The	average	refining	and	wholesale	marketing	gross	margin	increased	to	22.88	cents	per gallon	in	2006	from	15.82	cents	per	gallon	in	2005.

								Our	seven	refineries	have	an	aggregate	refining	capacity	of	974	mbpd	of	crude	oil.	During	2006,	our	refineries	processed	980	mbpd	of	crude	oil	and	234	mbpd	of other	charge	and	blend	stocks	for	a	crude	oil	capacity	utilization	rate	of	101	percent.

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

								The	profitability	of	our	pipeline	transportation	operations	is	primarily	dependent	on	the	volumes	shipped	through	the	pipelines.	The	volume	of	crude	oil	that	we transport	is	directly	affected	by	the	supply	of,	and	refiner	demand	for,	crude	oil	in	the	markets	served	directly	by	our	crude	oil	pipelines.	Key	factors	in	this	supply	and demand	balance	are	the	production	levels	of	crude	oil	by	producers,	the	availability	and	cost	of	alternative	modes	of	transportation,	and	refinery	and	transportation system	maintenance	levels.	The	volume	of	refined	products	that	we	transport	is	directly	affected	by	the	production	levels	of,	and	user	demand	for,	refined	products	in	the markets	served

by	our	refined	product	pipelines.	In	most	of	our	markets,	demand	for	gasoline	peaks	during	the	summer	driving	season,	which	extends	from	May	through	September	of each	year,	and	declines	during	the	fall	and	winter	months.	The	seasonal	pattern	for	distillates	is	the	reverse	of	this,	helping	to	level	overall	variability	on	an	annual	basis. As	with	crude	oil,	other	transportation	alternatives	and	system	maintenance	levels	influence	refined	product	movements.

								Our	long-term	integrated	gas	strategy	is	to	link	stranded	natural	gas	resources	with	areas	where	a	supply	gap	is	emerging	due	to	declining	production	and	growing demand.	LNG,	particularly	in	regard	to	our	operations	in	Equatorial	Guinea,	is	a	key	component	of	this	integrated	gas	strategy.	Our	integrated	gas	operations	include marketing	and	transportation	of	products	manufactured	from	natural	gas,	such	as	LNG	and	methanol,	primarily	in	the	United	States,	Europe	and	West	Africa.	Also included	in	the	financial	results	of	the	IG	segment	are	the	costs	associated	with	ongoing	development	of	certain	integrated	gas	projects.	Methanol	spot	pricing	is	volatile largely	because	global	methanol	demand	is	35	million	tons	and	any	major	unplanned	shutdown	of	or	addition	to	production	capacity	can	have	a	significant	impact	on	the supply-demand	balance.

# 2006	Operating	Highlights

•We	announced	seven	discoveries	in	Angola	and	Norway	and	continued	our	major	development	projects,	enhancing	our	E&P	operations	by:

•Resuming	operations	and	achieving	first	crude	oil	liftings	in	Libya;

•Acquiring	leasehold	positions	in	the	Bakken	Shale	in	North	Dakota	and	eastern	Montana	and	the	Piceance	Basin	of	Colorado	and	adding	acreage in	the	Barnett	Shale	in	north	central	Texas;

•Progressing	the	Alvheim/Vilje	development	offshore	Norway	and	receiving	Norwegian	Government	approval	of	the	Volund	field	plan	for development	and	operation	that	includes	its	tie-back	to	Alvheim;

•Progressing	the	Neptune	deepwater	Gulf	of	Mexico	development;

•Signing	a	production	sharing	contract	for	the	1.2	million	acre	Pasangkayu	exploration	block	in	Indonesia;	and

•Completing	the	sale	of	our	Russian	oil	exploration	and	production	businesses	at	a	gain.

•We	added	net	proved	oil	and	natural	gas	reserves	of	146	million	boe,	excluding	45	million	boe	of	dispositions,	while	producing	134	million	boe	during 2006.	Over	the	past	three	years,	we	have	added	net	proved	reserves	of	648	million	boe,	excluding	dispositions	of	approximately	46	million	boe,	while producing	approximately	380	million	boe.

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

•Authorizing	the	projected	$3.2	billion	expansion	of	our	Garyville	refinery;

•Completing	the	Tier	II	ultra-low	sulfur	diesel	fuel	projects	on	time	and	under	budget;

•Forming	an	ethanol	joint	venture	and	beginning	construction	of	the	venture's	first	ethanol	plant	in	Greenville,	Ohio;

•Awarding	a	FEED	contract	at	the	Detroit	refinery	and	launching	a	feasibility	study	at	the	Catlettsburg	refinery	for	potential	heavy	oil	upgrading projects;	and

•Acquiring	strategic	marine	and	terminal	assets.

•We	increased	Marathon	Brand	gasoline	and	diesel	sales	volumes	6	percent	in	2006.

•We	increased	Speedway	SuperAmerica's	(SSA)	same	store	gasoline	and	diesel	sales	volume	2	percent	and	merchandise	sales	8	percent	over	2005.

•We	advanced	our	integrated	gas	strategy	by:

•Progressing	our	Equatorial	Guinea	LNG	production	facility	to	near	completion,	with	commissioning	begun	in	late	2006;	and

•Awarding	a	FEED	contract	to	evaluate	a	possible	second	LNG	production	facility	in	Equatorial	Guinea.

•We	issued	a	request	for	proposals	for	a	potential	Canadian	oil	sands	venture.

# Critical	Accounting	Estimates

								The	preparation	of	financial	statements	in	accordance	with	generally	accepted	accounting	principles	requires	us	to	make	estimates	and	assumptions	that	affect	the reported	amounts	of	assets	and	liabilities	and	the	disclosure	of	contingent	assets	and	liabilities	as	of	the	date	of	the	consolidated	financial	statements	and	the	reported amounts	of	revenues	and	expenses	during	the	respective	reporting	periods.	Actual	results	could	differ	from	the	estimates	and	assumptions	used.

								Certain	accounting	estimates	are	considered	to	be	critical	if	(1)	the	nature	of	the	estimates	and	assumptions	is	material	due	to	the	levels	of	subjectivity	and	judgment necessary	to	account	for	highly	uncertain	matters	or	the	susceptibility	of	such	matters	to	change;	and	(2)	the	impact	of	the	estimates	and	assumptions	on	financial condition	or	operating	performance	is	material.

# Estimated	Net	Recoverable	Quantities	of	Oil	and	Natural	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	oil	and	natural	gas	reserves,	both	developed	and	undeveloped.	The	existence	and	the	estimated	amount	of	proved	reserves	affect,	among	other	things,	whether certain	costs	are	capitalized	or	expensed,	the	amount	and	timing	of	costs	depreciated,	depleted	or	amortized	into	net	income	and	the	presentation	of	supplemental information	on	oil	and	gas	producing	activities.	Both	the	expected	future	cash	flows	to	be	generated	by	oil	and	gas	producing	properties	used	in	testing	such	properties for	impairment	and	the	expected	future	taxable	income	available	to	realize	deferred	tax	assets	also	rely,	in	part,	on	estimates	of	net	recoverable	quantities	of	oil	and natural	gas.

								Proved	reserves	are	the	estimated	quantities	of	oil	and	natural	gas	that	geologic	and	engineering	data	demonstrate	with	reasonable	certainty	to	be	recoverable	in future	years	from	known	reservoirs	under	existing	economic	and	operating	conditions.	Estimates	of	proved	reserves	may	change,	either	positively	or	negatively,	as additional	information	becomes	available	and	as	contractual,	economic	and	political	conditions	change.	During	2006,	net	revisions	of	previous	estimates	increased	total proved	reserves	by	83	million	boe	(6	percent	of	the	beginning-of-the-year	reserves	estimate).	Positive	revisions	of	98	million	boe	were	partially	offset	by	15	million	boe in	negative	revisions.

								Our	estimation	of	net	recoverable	quantities	of	oil	and	natural	gas	is	a	highly	technical	process	performed	by	in-house	teams	of	reservoir	engineers	and	geoscience professionals.	All	estimates	prepared	by	these	teams	are	made	in	compliance	with	SEC	Rule	4-10(a)(2),(3)	and	(4)	of	Regulation	S-X	and	Statement	of	Financial Accounting	Standards	("SFAS")	No.	25,	"Suspension	of	Certain	Accounting	Requirements	for	Oil	and	Gas	Producing	Companies	(an	Amendment	of	FASB	Statement No.	19),"	and	disclosed	in	accordance	with	the	requirements	of	SFAS	No.	69,	"Disclosures	about	Oil	and	Gas	Producing	Activities	(an	Amendment	of	FASB	Statements 19,	25,	33	and	39)."	All	reserve	estimates	are	reviewed	and	approved	by	members	of	our	Corporate	Reserves	Group.	Any	change	to	proved	reserves	estimates	in	excess of	2.5	million	boe	on	a	total-field	basis,	within	a	single	month,	must	be	approved	by	the	Director	of	Corporate	Reserves,	who	reports	to	our	Chief	Financial	Officer.	The Corporate	Reserves	Group	may	also	perform	separate,	detailed	technical	reviews	of	reserve	estimates	for	significant	fields	that	were	acquired	recently	or	for	properties with	problematic	indicators	such	as	excessively	long	lives,	sudden	changes	in	performance	or	changes	in	economic	or	operating	conditions.

								Third-party	consultants	are	engaged	to	prepare	independent	reserve	estimates	for	fields	that	make	up	80	percent	of	our	reserves	over	a	rolling	four-year	period.	At December	31,	2006	we	had	met	this	goal.	For	2006,	Marathon	established	a	tolerance	level	of	10	percent	for	third-party	reserve	estimates	such	that	the	third-party consultants	discontinue	their	estimation	activities	once	their	results	are	within	10	percent	of	Marathon's	internal	estimates.	Should	the	third-party	consultants'	initial analysis	fail	to	reach	our	tolerance	level,	the	consultants	re-examine	the	information	provided,	request	additional	data	and	refine	their	analysis	if	appropriate.	If,	after this	re-examination,	the	third-party	consultants	cannot	arrive	at	estimates	within	our	tolerance,	we	would	adjust	our	reserve	estimates	as	necessary.	This	independent third-party	reserve	estimation	process	did	not	result	in	significant	changes	to	our	reserve	estimates	in	2006,	2005	or	2004.

								The	reserves	of	the	Alba	field	in	Equatorial	Guinea	comprise	approximately	40	percent	of	our	total	proved	oil	and	natural	gas	reserves	as	of	December	31,	2006. The	next	five	largest	oil	and	gas	producing	asset	groups	–	the	Waha	concessions	in	Libya,	the	Alvheim	development	offshore	Norway,	the	Brae	area	complex	offshore the	United	Kingdom,	the	Kenai	field	in	Alaska	and	the	Oregon	Basin	field	in	the	Rocky	Mountain	area	of	the	United	States	–	comprise	a	total	of	approximately 30	percent	of	our	total	proved	oil	and	natural	gas	reserves.

								Depreciation	and	depletion	of	producing	oil	and	natural	gas	properties	is	determined	by	the	units-of-production	method	and	could	change	with	revisions	to estimated	proved	developed	reserves.	The	change	in	the	depreciation	and	depletion	rate	over	the	past	three	years	due	to	revisions	of	previous	reserve	estimates	has	not been	significant.	A	five	percent	increase	in	the	amount	of	oil	and	natural	gas	reserves	would	change	the	depreciation	and	depletion	rate	from	$6.92	per	barrel	to	$6.59 per	barrel,	which	would	increase	pretax	income	by	approximately	$45	million	annually,	based	on	2006	production.	A	five	percent	decrease	in	the	amount	of	oil	and natural	gas	reserves	would	change	the	depreciation	and	depletion	rate	from	$6.92	per	barrel	to	$7.28	per	barrel	and	would	result	in	a	decrease	in	pretax	income	of approximately	$50	million	annually,	based	on	2006	production.

# Fair	Value	Estimates

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

								Under	the	purchase	method	of	accounting,	the	purchase	price	paid	to	acquire	a	business	is	allocated	to	its	assets	and	liabilities	based	on	the	estimated	fair	values	of the	assets	acquired	and	liabilities	assumed	as	of	the	date	of	acquisition.	The	excess	of	the	purchase	price	over	the	fair	value	of	the	net	tangible	and	identifiable	intangible assets	acquired	is	recorded	as	goodwill.	The	most	difficult	estimations	of	individual	fair	values	are	those	involving	property,	plant	and	equipment	and	identifiable intangible	assets.	We	use	all	available	information	to	make	these	fair	value	determinations	and,	for	certain	acquisitions,	engage	third-party	consultants	for	assistance. During	2005,	we	made	two	significant	acquisitions	with	an	aggregate	purchase	price	of	$3.156	billion	that	was	allocated	to	the	assets	acquired	and	liabilities	assumed based	on	their	estimated	fair	values.	See	Note	6	to	the	consolidated	financial	statements	for	information	on	these	acquisitions.	We	did	not	make	any	significant acquisitions	in	2006.	As	of	December	31,	2006,	our	recorded	goodwill	was	$1.398	billion.	Such	goodwill	is	not	amortized,	but	rather	is	tested	for	impairment	annually, and	when	events	or	changes	in	circumstances	indicate	that	the	fair	value	of	a	reporting	unit	with	goodwill	has	been	reduced	below	its	carrying	value.

								The	fair	values	used	to	allocate	the	purchase	price	of	an	acquisition	and	to	test	goodwill	for	impairment	are	often	estimated	using	the	expected	present	value	of future	cash	flows	method,	which	requires	us	to	project	related	future	revenues	and	expenses	and	apply	an	appropriate	discount	rate.	The	estimates	used	in	determining fair	values	are	based	on	assumptions	believed	to	be	reasonable	but	which	are	inherently	uncertain	and	unpredictable.	Accordingly,	actual	results	may	differ	from	the projected	results	used	to	determine	fair	value.

								Long-lived	assets	used	in	operations	are	assessed	for	impairment	whenever	changes	in	facts	and	circumstances	indicate	that	the	carrying	value	of	the	assets	may	not be	recoverable.	For	purposes	of	impairment	evaluation,	long-lived	assets	must	be	grouped	at	the	lowest	level	for	which	independent	cash	flows	can	be	identified,	which generally	is	field-by-field	for	E&P	assets,	refinery	and	associated	distribution	system	level	or	pipeline	system	level	for	refining	and	transportation	assets,	or	site	level	for retail	stores.	If	the	sum	of	the	undiscounted	estimated	pretax	cash	flows	is	less	than	the	carrying	value	of	an	asset	group,	the	carrying	value	is	written	down	to	the estimated	fair	value.

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

								We	evaluate	our	unproved	property	investment	for	impairment	based	on	time	or	geologic	factors	in	addition	to	the	use	of	an	undiscounted	future	net	cash	flow approach.	Information	such	as	drilling	results,	reservoir	performance,	seismic	interpretation	or	future	plans	to	develop	acreage	are	also	considered.	The	expected	future cash	flows	from	our	RM&T	assets	require	assumptions	about	matters	such	as	future	refined	product	prices,	future	crude	oil	and	other	feedstock	costs,	estimated remaining	lives	of	the	assets	and	future	expenditures	necessary	to	maintain	the	assets'	existing	service	potential.

								During	2006,	we	recorded	impairments	of	$25	million,	including	$20	million	related	to	the	Camden	Hills	field	in	the	Gulf	of	Mexico	and	the	associated	Canyon Express	pipeline.	Natural	gas	production	from	the	Camden	Hills	field	ended	during	2006	as	a	result	of	increased	water	production	from	the	well.	We	did	not	have significant	impairment	charges	during	2005.	During	2004,	we	recorded	an	impairment	of	$32	million	related	to	unproved	properties	and	$12	million	related	to producing	properties	primarily	as	a	result	of	unsuccessful	developmental	drilling	activity	in	Russia.

								We	record	all	derivative	instruments	at	fair	value.	We	have	two	long-term	contracts	for	the	sale	of	natural	gas	in	the	United	Kingdom	that	are	accounted	for	as derivative	instruments.	These	contracts	expire	in	September	2009.	These	contracts	were	entered	into	in	the	early	1990s	in	support	of	our	investments	in	the	East	Brae field	and	the	SAGE	pipeline.	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	natural	gas	prices.	The	fair	value	of	these	contracts	is determined	by	applying	the	difference	between	the	contract	price	and	the	U.K.	forward	natural	gas	strip	price	to	the	expected	sales	volumes	under	these	contracts	for	the next	18	months.	Adjustments	to	the	fair	value	of	these	contracts	result	in	non-cash	charges	or	credits	to	income	from	operations.	The	difference	between	the	contract price	and	the	U.K.	forward	natural	gas	strip	price	may	fluctuate	widely	from	time	to	time	and	may	significantly	affect	income	from	operations.	In	2006,	the	non-cash gains	related	to	changes	in	fair	value	recognized	in	income	from	operations	were	$454	million.	Non-cash	losses	of	$386	million	and	$99	million	were	recognized	in	2005 and	2004.	These	effects	are	primarily	due	to	the	U.K.	18-month	forward	natural	gas	price	curve	weakening	44	percent	in	2006,	while	it	strengthened	90	percent	and 36	percent	during	2005	and	2004.

# 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,	2006,	we	reported	net deferred	tax	assets	of	$1.865	billion,	which	represented	gross	assets	of	$2.554	billion	net	of	valuation	allowances	of	$689	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	natural	gas	prices)	and	future	financial	conditions.	The	estimates	and	assumptions	used	in determining	future	taxable	income	are	consistent	with	those	used	in	our	internal	budgets,	forecasts	and	strategic	plans.

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

								Additionally,	we	must	consider	any	prudent	and	feasible	tax	planning	strategies	that	might	minimize	the	amount	of	deferred	tax	liabilities	recognized	or	the	amount of	any	valuation	allowance	recognized	against	deferred	tax	assets,	if	we	can	implement	these	strategies	and	if	we	expect	to	implement	these	strategies	in	the	event	the forecasted	conditions	actually	occurred.	The	principal	tax	planning	strategy	available	to	us	relates	to	the	permanent	reinvestment	of	the	earnings	of	our	foreign subsidiaries.	Assumptions	related	to	the	permanent	reinvestment	of	the	earnings	of	our	foreign	subsidiaries	are	reconsidered	quarterly	to	give	effect	to	changes	in	our portfolio	of	producing	properties	and	in	our	tax	profile.

# Pensions	and	Other	Postretirement	Benefit	Obligations

								Accounting	for	pension	and	other	postretirement	benefit	obligations	involves	numerous	assumptions,	the	most	significant	of	which	relate	to	the	following:

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

•the	expected	long-term	return	on	plan	assets;

•the	rate	of	future	increases	in	compensation	levels;	and

•health	care	cost	projections.

								We	develop	our	demographics	and	utilize	the	work	of	third-party	actuaries	to	assist	in	the	measurement	of	these	obligations.	We	have	selected	different	discount rates	for	our	funded	U.S.	pension	plans	and	our	unfunded	U.S.	retiree	health	plans	due	to	the	different	projected	liability	durations	of	9	years	and	13	years.	In determining	the	assumed	discount	rates,	our	methods	include	a	review	of	market	yields	on	high-quality	corporate	debt	and	use	of	our	third-party	actuary's	discount	rate modeling	tool.	This	tool	applies	a	yield	curve	to	the	projected	benefit	plan	cash	flows	using	a	hypothetical	Aa	yield	curve.	The	yield	curve	represents	a	series	of annualized	individual	discount	rates	from	1.5	to	30	years.	The	bonds	used	are	rated	Aa	or	higher	by	a	recognized	rating	agency	and	only	non-callable	bonds	are	included. Each	issue	is	required	to	have	at	least	$150	million	par	value	outstanding.	The	top	quartile	bonds	are	selected	within	each	maturity	group	to	construct	the	yield	curve.

								The	asset	rate	of	return	assumption	considers	the	asset	mix	of	the	plans	(currently	targeted	at	approximately	75	percent	equity	securities	and	25	percent	debt securities	for	the	funded	pension	plans),	past	performance	and	other	factors.	Certain	components	of	the	asset	mix	are	modeled	with	various	assumptions	regarding inflation,	debt	returns	and	stock	yields.	Our	assumptions	are	compared	to	those	of	peer	companies	and	to	historical	returns	for	reasonableness	and	appropriateness.

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

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

								Note	24	to	the	consolidated	financial	statements	includes	detailed	information	about	the	assumptions	used	to	calculate	the	components	of	our	defined	benefit pension	and	other	postretirement	plan	expense	for	2006,	2005	and	2004,	as	well	as	the	obligations	and	accumulated	other	comprehensive	income	reported	on	the	balance sheets	as	of	December	31,	2006	and	2005.

								Of	the	assumptions	used	to	measure	the	December	31,	2006	obligations	and	estimated	2007	net	periodic	benefit	cost,	the	discount	rate	has	the	most	significant effect	on	the	periodic	benefit	cost	reported	for	the	plans.	A	0.25	percent	decrease	in	the	discount	rates	of	5.80	percent	for	our	U.S.	pension	plans	and	5.90	percent	for	our other	U.S.	postretirement	benefit	plans	would	increase	pension	obligations	and	other	postretirement	benefit	plan	obligations	by	$93	million	and	$28	million	and	would increase	defined	benefit	pension	expense	and	other	postretirement	plan	expense	by	$13	million	and	$2	million.

								In	2006,	we	made	certain	plan	design	changes	which	included	an	update	of	the	mortality	table	used	in	the	plans'	definition	of	actuarial	equivalence	and	lump	sum calculations	and	a	20	percent	retiree	cost	of	living	adjustment	for	annuitants.	This	change	increased	our	benefit	obligations	by	$117	million.	In	2005,	we	decreased	our retirement	age	assumption	by	two	years	and	also	increased	our	lump	sum	election	rate	from	90	percent	to	96	percent	based	on	changing	trends	in	our	experience.	This change	increased	our	benefit	obligations	by	$109	million.

# 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	many	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	of	the	amount	of	damages.	Similarly,	liabilities	for environmental	remediation	may	vary	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.

								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	cost	of revenues	or	selling,	general	and	administrative	expenses	in	the	consolidated	statements	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."

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

# Management's	Discussion	and	Analysis	of	Results	of	Operations

# Change	in	Accounting	for	Matching	Buy/Sell	Transactions

								Matching	buy/sell	transactions	arise	from	arrangements	in	which	we	agree	to	buy	a	specified	quantity	and	quality	of	crude	oil	or	refined	product	to	be	delivered	to	a specified	location	while	simultaneously	agreeing	to	sell	a	specified	quantity	and	quality	of	the	same	commodity	at	a	specified	location	to	the	same	counterparty.	Prior	to April	1,	2006,	all	matching	buy/sell	transactions	were	recorded	as	separate	sale	and	purchase	transactions,	or	on	a	"gross"	basis.	Effective	for	contracts	entered	into	or modified	on	or	after	April	1,	2006,	the	income	effects	of	matching	buy/sell

transactions	are	reported	in	cost	of	revenues,	or	on	a	"net"	basis.	Transactions	under	contracts	entered	into	before	April	1,	2006	will	continue	to	be	reported	on	a	"gross" basis.

								Each	purchase	and	sale	transaction	has	the	characteristics	of	a	separate	legal	transaction,	including	separate	invoicing	and	cash	settlement.	Accordingly,	we	believed that	we	were	required	to	account	for	these	transactions	separately.	An	accounting	interpretation	clarified	the	circumstances	under	which	a	matching	buy/sell	transaction should	be	viewed	as	a	single	transaction	involving	the	exchange	of	inventory.	For	a	further	description	of	the	accounting	requirements	and	how	they	apply	to	matching buy/sell	transactions,	see	Note	2	to	the	consolidated	financial	statements.

								This	accounting	change	had	no	effect	on	net	income	but	the	amounts	of	revenues	and	cost	of	revenues	recognized	after	April	1,	2006	are	less	than	the	amounts	that would	have	been	recognized	under	previous	accounting	practices.

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

# Consolidated	Results	of	Operations

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| E&P | $9,010 | $8,009 | $6,412 |
| RM&T | 55,941 | 56,003 | 43,630 |
| IG | 179 | 236 | 190 |
| Segment\trevenues | 65,130 | 64,248 | 50,232 |
| Elimination\tof\tintersegment\trevenues | (688) | (876) | (668) |
| Gain\t(loss)\ton\tlong-term\tU.K.\tgas\tcontracts | 454 | (386) | (99) |
| Total\trevenues | $64,896 | $62,986 | $49,465 |
| Items\tincluded\tin\tboth\trevenues\tand\tcosts\tand\texpenses: |  |  |  |
| Consumer\texcise\ttaxes\ton\tpetroleum\tproducts\tand\tmerchandise | $4,979 | $4,715 | $4,463 |
| Matching\tcrude\toil\tand\trefined\tproduct\tbuy/sell\ttransactions\tsettled\tin\tcash: |  |  |  |
| E&P | $16 | $123 | $167 |
| RM&T | 5,441 | 12,513 | 9,075 |
| Total\tbuy/sell\ttransactions\tincluded\tin\trevenues | $5,457 | $12,636 | $9,242 |

								E&P	segment	revenues	increased	$1.001	billion	in	2006	from	2005	and	$1.597	billion	in	2005	from	2004.	The	2006	increase	was	primarily	in	international revenues	due	to	higher	realized	liquid	hydrocarbon	prices	and	sales	volumes	as	illustrated	in	the	table	below.	The	largest	liquid	hydrocarbon	sales	volume	increase	was	in Libya,	where	the	first	crude	oil	sales	occurred	in	the	first	quarter	of	2006	and	where	sales	volumes	averaged	54	mbpd	in	2006,	including	a	total	of	8	mbpd	that	were	owed to	our	account	upon	the	resumption	of	our	operations	there.	Revenues	from	domestic	operations	were	flat	from	year	to	year.	An	8	percent	decrease	in	domestic	net natural	gas	sales	volumes,	primarily	as	the	result	of	the	Camden	Hills	field	in	the	Gulf	of	Mexico	ceasing	production	in	early	2006,	almost	completely	offset	the	benefit of	higher	liquid	hydrocarbon	prices	in	2006.

								The	2005	increase	in	E&P	segment	revenues	over	2004	was	primarily	the	result	of	higher	worldwide	liquid	hydrocarbon	and	natural	gas	prices	and	international liquid	hydrocarbon	sales	volumes	partially	offset	by	lower	domestic	natural	gas	and	liquid	hydrocarbon	sales	volumes	as	illustrated	in	the	table	below.	The	decline	in domestic

volumes	in	2005	resulted	primarily	from	weather-related	downtime	in	the	Gulf	of	Mexico	and	natural	declines	in	field	production	rates.

| United	States | 76 | 76 | 81 |
| :--- | :--- | :--- | :--- |
| Europe | 35 | 36 | 40 |
| Africa | 112 | 52 | 32 |
| (b)\nTotal\tInternational | 147 | 88 | 72 |
| Worldwide\tContinuing\tOperations | 223 | 164 | 153 |
| (c)\nDiscontinued\tOperations | 12 | 27 | 17 |
| Worldwide | 235 | 191 | 170 |
| (d)(e) |  |  |  |
| Net\tNatural\tGas\tSales\t(mmcfd) |  |  |  |
| United\tStates | 532 | 578 | 631 |
| Europe | 243 | 262 | 292 |
| Africa | 72 | 92 | 76 |
| Total\tInternational | 315 | 354 | 368 |
| Worldwide | 847 | 932 | 999 |
| Total\tWorldwide\tSales\t(mboepd) |  |  |  |
| Continuing\toperations | 365 | 319 | 320 |
| Discontinued\toperations | 12 | 27 | 17 |
| Worldwide | 377 | 346 | 337 |
| (f) |  |  |  |
| Average\tRealizations |  |  |  |
| Liquid\tHydrocarbons\t($per\tbbl) |  |  |  |
| United\tStates | $54.41 | $45.41 | $32.76 |
| Europe | 64.02 | 52.99 | 37.16 |
| Africa | 59.83 | 46.27 | 35.11 |
| Total\tInternational | 60.81 | 49.04 | 36.24 |
| Worldwide\tContinuing\tOperations | 58.63 | 47.35 | 34.40 |
| Discontinued\tOperations | 38.38 | 33.47 | 22.65 |
| Worldwide | $57.58 | $45.42 | $33.31 |
| Natural\tGas\t($per\tmcf) |  |  |  |
| United\tStates | $5.76 | $6.42 | $4.89 |
| Europe | 6.74 | 5.70 | 4.13 |
| Africa | 0.27 | 0.25 | 0.25 |
| Total\tInternational | 5.27 | 4.28 | 3.33 |
| Worldwide | $5.58 | $5.61 | $4.31 |

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

(c) Represents	Marathon's	Russian	oil	exploration	and	production	businesses	that	were	sold	in	June	2006.

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

(e) Includes	natural	gas	acquired	for	injection	and	subsequent	resale	of	46,	38,	and	19	mmcfd	in	2006,	2005	and	2004,	respectively.	Effective	July	1,	2005,	the	methodology	for	allocating	sales	volumes	between natural	gas	produced	from	the	Brae	complex	and	third-party	natural	gas	production	was	modified,	resulting	in	an	increase	in	volumes	representing	natural	gas	acquired	for	injection	and	subsequent	resale.

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

								E&P	segment	revenues	included	derivative	gains	of	$25	million	and	$7	million	in	2006	and	2005,	and	derivative	losses	of	$152	million	in	2004.	Excluded	from E&P	segment	revenues	were	gains	of	$454	million	in	2006	and	losses	of	$386	million	and	$99	million	in	2005	and	2004	related	to	long-term	natural	gas	sales	contracts in	the	United	Kingdom	that	are	accounted	for	as	derivative	instruments.	See	"Item	7A.	Quantitative	and	Qualitative	Disclosures	about	Market	Risk"	on	page	56.

								RM&T	segment	revenues	decreased	by	$62	million	in	2006	from	2005	and	increased	by	$12.373	billion	in	2005	from	2004.	The	portion	of	RM&T	revenues reported	for	matching	buy/sell	transactions	decreased	$7.072	billion	and	increased	$3.438	billion	in	the	same	periods.	The	decrease	in	revenues	from	matching	buy/sell transactions	in	2006	was	a	result	of	the	change	in	accounting	for	these	transactions	effective	April	1,	2006,	discussed	above.	Excluding	matching	buy/sell	transactions, 2006	revenues	increased	primarily	as	a	result	of	higher	refined	product	prices	and

sales	volumes.	The	2005	increase	primarily	reflected	higher	refined	product	and	crude	oil	prices	and	increased	refined	product	sales	volumes,	partially	offset	by decreased	crude	oil	sales	volumes.

# 								For	additional	information	on	segment	results	see	page	43.

								Income	from	equity	method	investments	increased	by	$126	million	in	2006	from	2005	and	increased	by	$98	million	in	2005	from	2004.	Income	from	our	LPG operations	in	Equatorial	Guinea	increased	in	both	periods	due	to	higher	sales	volumes	as	a	result	of	the	plant	expansions	completed	in	2005.	The	increase	in	2005	also included	higher	PTC	income	as	a	result	of	higher	distillate	gross	margins.

								Cost	of	revenues	increased	$4.609	billion	in	2006	from	2005	and	$7.106	billion	in	2005	from	2004.	In	both	periods	the	increases	were	primarily	in	the	RM&T segment	and	resulted	from	increases	in	acquisition	costs	of	crude	oil,	refinery	charge	and	blend	stocks	and	purchased	refined	products.	The	increase	in	both	periods	was also	impacted	by	higher	manufacturing	expenses,	primarily	the	result	of	higher	contract	services	and	labor	costs	in	2006	and	higher	purchased	energy	costs	in	2005.

								Purchases	related	to	matching	buy/sell	transactions	decreased	$6.968	billion	in	2006	from	2005	and	increased	$3.314	billion	in	2005	from	2004,	mostly	in	the RM&T	segment.	The	decrease	in	2006	was	primarily	related	to	the	change	in	accounting	for	matching	buy/sell	transactions	discussed	above.	The	increase	in	2005	was primarily	due	to	increased	crude	oil	prices.

								Depreciation,	depletion	and	amortization	increased	$215	million	in	2006	from	2005	and	$125	million	in	2005	from	2004.	RM&T	segment	depreciation	expense increased	in	both	years	as	a	result	of	the	increase	in	asset	value	recorded	for	our	acquisition	of	the	38	percent	interest	in	MPC	on	June	30,	2005.	In	addition,	the	Detroit refinery	expansion	completed	in	the	fourth	quarter	of	2005	contributed	to	the	RM&T	depreciation	expense	increase	in	2006.	E&P	segment	depreciation	expense	for	2006 included	a	$20	million	impairment	of	capitalized	costs	related	to	the	Camden	Hills	field	in	the	Gulf	of	Mexico	and	the	associated	Canyon	Express	pipeline.	Natural	gas production	from	the	Camden	Hills	field	ended	in	2006	as	a	result	of	increased	water	production	from	the	well.

								Selling,	general	and	administrative	expenses	increased	$73	million	in	2006	from	2005	and	$134	million	in	2005	from	2004.	The	2006	increase	was	primarily because	personnel	and	staffing	costs	increased	throughout	the	year	primarily	as	a	result	of	variable	compensation	arrangements	and	increased	business	activity.	Partially offsetting	these	increases	were	reductions	in	stock-based	compensation	expense.	The	increase	in	2005	was	primarily	a	result	of	increased	stock-based	compensation expense,	due	to	the	increase	in	our	stock	price	during	that	year	as	well	as	an	increase	in	equity-based	awards,	which	was	partially	offset	by	a	decrease	in	expense	as	a result	of	severance	and	pension	plan	curtailment	charges	and	start-up	costs	related	to	EGHoldings	in	2004.

								Exploration	expenses	increased	$148	million	in	2006	from	2005	and	$59	million	in	2005	from	2004.	Exploration	expense	related	to	dry	wells	and	other	write-offs totaled	$166	million,	$111	million	and	$47	million	in	2006,	2005	and	2004.	Exploration	expense	in	2006	also	included	$47	million	for	exiting	the	Cortland	and	Empire leases	in	Nova	Scotia.

								Net	interest	and	other	financing	costs	(income)	reflected	a	net	$37	million	of	income	for	2006,	a	favorable	change	of	$183	million	from	the	net	$146	million expense	in	2005.	Net	interest	and	other	financing	costs	decreased	$16	million	in	2005	from	2004.	The	favorable	changes	in	2006	included	increased	interest	income	due to	higher	interest	rates	and	average	cash	balances,	foreign	currency	exchange	gains,	adjustments	to	interest	on	tax	issues	and	greater	capitalized	interest.	The	decrease	in expense	for	2005	was	primarily	a	result	of	increased	interest	income	on	higher	average	cash	balances	and	greater	capitalized	interest,	partially	offset	by	increased	interest on	potential	tax	deficiencies	and	higher	foreign	exchange	losses.	Included	in	net	interest	and	other	financing	costs	(income)	are	foreign	currency	gains	of	$16	million, losses	of	$17	million	and	gains	of	$9	million	for	2006,	2005	and	2004.

								Provision	for	income	taxes	increased	$2.308	billion	in	2006	from	2005	and	$979	million	in	2005	from	2004,	primarily	due	to	the	$4.259	billion	and	$2.691	billion increases	in	income	from	continuing	operations	before	income	taxes.	The	increase	in	our	effective	income	tax	rate	in	2006	was	primarily	a	result	of	the	income	taxes related	to	our	Libyan	operations,	where	the	statutory	income	tax	rate	is	in	excess	of	90	percent.	The	following	is	an	analysis	of	the	effective	income	tax	rates	for continuing	operations	for	2006,	2005	and	2004.	See	Note	11	to	the	consolidated	financial	statements	for	further	discussion.

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Statutory\tU.S.\tincome\ttax\trate | 35.0% | 35.0% | 35.0% |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 9.9 | (0.8) | 0.5 |
| State\tand\tlocal\tincome\ttaxes\tnet\tof\tfederal\tincome\ttax\teffects | 1.9 | 2.5 | 1.6 |
| Other\ttax\teffects | (2.0) | (0.4) | (0.9) |
| Effective\tincome\ttax\trate\tfor\tcontinuing\toperations | 44.8% | 36.3% | 36.2% |

								Discontinued	operations	for	all	periods	reflects	the	operations	of	our	former	Russian	oil	exploration	and	production	businesses	which	were	sold	in	June	2006.	An after-tax	gain	on	the	disposal	of	$243	million	is	included	in	discontinued	operations	for	2006.	See	Note	7	to	the	consolidated	financial	statements	for	additional information.	Also	included	in	2004	is	a	$4	million	adjustment	to	the	gain	on	the	2003	sale	of	our	exploration	and	production	operations	in	western	Canada.

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

# Segment	Results

								As	discussed	in	Note	7	to	the	consolidated	financial	statements,	we	sold	our	Russian	oil	exploration	and	production	businesses	during	2006.	The	activities	of	these operations	have	been	reported	as	discontinued	operations	and	therefore	are	excluded	from	segment	results	for	all	periods	presented.

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| E&P |  |  |  |
| Domestic | $873 | $983 | $674 |
| International | 1,130 | 904 | 416 |
| E&P\tsegment\tincome | 2,003 | 1,887 | 1,090 |
| RM&T | 2,795 | 1,628 | 568 |
| IG | 16 | 55 | 37 |
| Segment\tincome | 4,814 | 3,570 | 1,695 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |  |
| Corporate\tand\tother\tunallocated\titems | (212) | (377) | (327) |
| (a) |  |  |  |
| Gain\t(loss)\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts | 232 | (223) | (57) |
| Discontinued\toperations | 277 | 45 | (33) |
| Gain\ton\tdisposition\tof\tSyria\tinterest | 31 | – | – |
| Deferred\tincome\ttaxes\t–\ttax\tlegislation\tchanges | 21 | 15 | – |
| (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\t\t\t\t\t\t\t\t\t\t\t\t\t–\tother\tadjustments | 93 | – | – |
| Loss\ton\tearly\textinguishment\tof\tdebt | (22) | – | – |
| Gain\ton\tsale\tof\tminority\tinterests\tin\tEGHoldings | – | 21 | – |
| (c) |  |  |  |
| Corporate\tinsurance\tadjustment | – | – | (17) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | (19) | – |
| Net\tincome | $5,234 | $3,032 | $1,261 |

(a) Amounts	relate	to	long-term	natural	gas	contracts	in	the	United	Kingdom	that	are	accounted	for	as	derivative	instruments	and	recorded	at	fair	value.	See	"Critical	Accounting	Estimates	–	Fair	Value	Estimates" on	page	37	for	further	discussion.

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

(c) Insurance	expense	in	2004	related	to	estimated	future	obligations	to	make	certain	insurance	premium	payments	related	to	past	loss	experience.

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

								U.S.	E&P	income	increased	$309	million	in	2005	from	2004.	This	was	the	result	of	a	$917	million	pretax	income	increase	primarily	due	to	higher	revenues	as discussed	above.	The	effective	income	tax	rate	was	37	percent	in	both

years.	Our	cost	of	storm-related	repairs	as	a	result	of	2005	hurricane	activity	in	the	Gulf	of	Mexico	was	not	significant	and	our	Gulf	of	Mexico	production	quickly returned	to	pre-storm	levels.	In	late	September	2004,	certain	production	platforms	in	the	Gulf	of	Mexico	were	evacuated	due	to	hurricane	activity.	All	facilities	were back	on	line	by	October	1,	2004	with	the	exception	of	the	Petronius	platform	which	came	back	on	line	in	March	2005.	As	a	result	of	the	damage	to	the	Petronius platform,	we	recorded	expense	of	$11	million	in	2004	representing	repair	costs	incurred,	partially	offset	by	the	net	effects	of	the	property	damage	insurance	recoveries and	the	related	retrospective	insurance	premiums.	We	recorded	income	of	$53	million	in	2005	and	$34	million	in	2004	for	business	interruption	insurance	recoveries.

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

								International	E&P	income	increased	$488	million	in	2005	from	2004,	reflecting	an	increase	in	pretax	income	of	$740	million	and	an	effective	income	tax	rate	of 37	percent	in	both	years.	The	revenue	increase	discussed	above	had	the	most	significant	impact	on	pretax	income.	Increases	in	production	costs	and	depletion, depreciation	and	amortization	related	primarily	to	increased	production	partially	offset	the	benefit	of	higher	revenue.	Exploration	expenses	were	also	higher	in	2005.

								RM&T	segment	income	increased	$1.167	billion	in	2006	from	2005	and	$1.060	billion	in	2005	from	2004.	Segment	income	in	2006	and	2005	benefited	from	the 38	percent	minority	interest	in	MPC	that	we	acquired	on	June	30,	2005.	Pre-tax	income	increased	by	$1.802	billion	in	2006	from	2005	and	$1.766	billion	in	2005	from 2004.	The	pretax	earnings	reduction	related	to	the	minority	interest	was	$376	million	in	2005	and	$539	million	in	2004.	The	key	driver	of	the	increase	in	RM&T	pretax income	in	both	years	was	our	refining	and	wholesale	marketing	gross	margin	which	averaged	22.88	cents	per	gallon	in	2006	compared	to	15.82	cents	in	2005	and	8.77 cents	in	2004.	The	increase	in	the	margin	for	2006	reflected	wider	crack	spreads,	improved	refined	product	sales	realizations,	the	favorable	effects	of	our	ethanol blending	program	and	increased	refinery	throughputs.	In	2005,	the	margin	improved	initially	due	to	wider	sweet/sour	crude	oil	differentials	and	later	due	to	the temporary	impact	that	Hurricanes	Katrina	and	Rita	had	on	refined	product	prices	and	concerns	about	the	adequacy	of	distillate	supplies	heading	into	that	winter.

								Included	in	the	refining	and	wholesale	marketing	gross	margin	were	pretax	gains	of	$400	million	in	2006	and	pretax	losses	of	$238	million	in	2005	and $272	million	in	2004	related	to	derivatives	utilized	primarily	to	manage	price	risk.	These	derivative	gains	and	losses	are	largely	offset	by	gains	and	losses	on	the	physical commodity	transactions	related	to	these	derivative	positions.	The	change	from	derivative	losses	to	derivative	gains	reflects	both	improvements	in	the	realized	effects	of our	derivatives	programs	as	well	as	unrealized	effects	as	a	result	of	marking	open	derivatives	positions	to	market.	See	further	discussion	under	"Item	7A.	Quantitative and	Qualitative	Disclosures	about	Market	Risk."

								We	averaged	980	mbpd	of	crude	oil	throughput	in	2006,	or	101	percent	of	system	capacity.	We	averaged	973	mbpd	of	crude	oil	throughput	in	2005	and	939	mbpd in	2004,	representing	102	percent	and	99	percent	of	system	capacity	for	those	years.	Our	capacity	increased	in	2005	as	a	result	of	the	Detroit	refinery	expansion	from	74 to	100	mbpd.

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| RM&T\tOPERATING\tSTATISTICS |  |  |  |
| (a) |  |  |  |
| Refining\tand\twholesale\tmarketing\tgross\tmargin\t($per\tgallon) | $0.2288 | $0.1582 | $0.0877 |
| (b)(c) |  |  |  |
| Refined\tproducts\tsales\tvolumes\t(mbpd) | 1,425 | 1,455 | 1,400 |
| (c) |  |  |  |
| Matching\tbuy/sell\tvolumes\tincluded\tin\trefined\tproducts\tsales\tvolumes\t(mbpd) | 24 | 77 | 71 |

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

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

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

								IG	segment	income	decreased	$39	million	in	2006	from	2005	compared	to	an	increase	of	$18	million	in	2005	from	2004.	In	2006,	a	$17	million	pretax	loss	was recognized	as	a	result	of	the	renegotiation	of	a	technology	agreement	and	income	from	our	equity	method	investment	in	AMPCO	was	lower	due	to	plant	downtime during	a	planned	turnaround	and	subsequent	compressor	repair,	partially	offset	by	higher	realized	methanol	prices.	The	provision	for	income	taxes	also	increased $15	million	in	2006.

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

# Financial	Condition

								Net	property,	plant	and	equipment	increased	$1.642	billion	in	2006	primarily	as	a	result	of	the	capital	expenditures	and	the	additional	capitalized	asset	retirement costs	discussed	below.	Net	property,	plant	and	equipment	as	of	the	end	of	the	last	two	years	is	summarized	in	the	following	table.

|  | 2006 | 2005 |
| :--- | :--- | :--- |
| E&P |  |  |
| Domestic | $3,636 | $2,811 |
| International | 4,879 | 4,737 |
| Total\tE&P | 8,515 | 7,548 |
| RM&T | 6,452 | 6,113 |
| IG | 1,378 | 1,145 |
| Corporate | 308 | 205 |
| Total | $16,653 | $15,011 |

								Asset	retirement	obligations	increased	$333	million	in	2006	from	2005	primarily	due	to	upward	revisions	of	previous	estimates	related	to	increasing	cost	estimates, primarily	in	the	United	Kingdom,	and	to	the	accrual	of	obligations	for	new	properties,	primarily	the	Alvheim/Vilje	development	in	Norway	and	the	LNG	production facility	in	Equatorial	Guinea.

# Cash	Flows

								Net	cash	provided	from	operating	activities	totaled	$5.488	billion	in	2006,	compared	with	$4.738	billion	in	2005	and	$3.766	billion	in	2004.	The	$750	million increase	in	2006	primarily	reflects	the	impact	of	higher	net	income,	partially	offset	by	contributions	of	$635	million	to	our	funded	defined	benefit	pension	plans	and working	capital	changes.	The	2005	increase	mainly	resulted	from	higher	net	income,	partially	offset	by	the	effects	of	receivables	which	were	transferred	to	Ashland	at the	Acquisition	date.

								Net	cash	used	in	investing	activities	totaled	$2.955	billion	in	2006,	compared	with	$3.127	billion	in	2005	and	$2.324	billion	in	2004.	Significant	investing activities	include	capital	expenditures,	acquisitions	of	businesses	and	asset	disposals.

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| E&P |  |  |  |
| Domestic | $1,302 | $638 | $405 |
| International | 867 | 728 | 435 |
| Total\tE&P | 2,169 | 1,366 | 840 |
| RM&T | 916 | 841 | 794 |
| IG | 307 | 571 | 488 |
| Corporate | 41 | 18 | 19 |
| Total | $3,433 | $2,796 | $2,141 |

								The	$637	million	increase	in	capital	expenditures	in	2006	over	2005	primarily	resulted	from	increased	spending	in	the	E&P	segment	and	primarily	relates	to significant	acreage	acquisitions	in	the	Bakken	Shale	in	North	Dakota	and	eastern	Montana	and	the	Piceance	Basin	of	Colorado,	as	well	as	to	continued	work	on	the Alvheim/Vilje	development	offshore	Norway	and	the	Neptune	development	in	the	Gulf	of	Mexico.	The	$264	million	decrease	in	integrated	gas	spending	reflects	the	fact that	the	LNG	production	facility	in	Equatorial	Guinea	is	nearing	completion.	The	$655	million	increase	in	2005	capital	expenditures	over	2004	mainly	resulted	from increased	spending	related	to	the	Alvheim	development	and	the	Equatorial	Guinea	LNG	production	facility.

								Acquisitions	in	2006	primarily	included	cash	payments	of	$718	million	associated	with	our	re-entry	into	Libya.	Acquisitions	in	2005	included	cash	payments	of $506	million	for	the	acquisition	of	Ashland's	38	percent	ownership	in	MPC.	For	further	discussion	of	acquisitions,	see	Note	6	to	the	consolidated	financial	statements.

								Disposal	of	assets	and	of	discontinued	operations	totaled	$966	million	in	2006,	compared	with	$131	million	in	2005	and	$76	million	in	2004.	Proceeds	of $832	million	from	the	disposal	of	discontinued	operations	in	2006	related	to	the	sale	of	our	Russian	exploration	and	production	businesses	in	June	2006.	In	2006,	other disposals	of	assets	included	proceeds	from	the	sale	of	90	percent	of	our	interest	in	Syrian	natural	gas	fields,	SSA	stores	and	other	domestic	production	and	transportation assets.	In	2005	and	2004,	proceeds	were	primarily	from	the	sale	of	various	domestic	producing	properties	and	SSA	stores.

								Net	cash	used	in	financing	activities	totaled	$2.581	billion	in	2006,	compared	with	$2.345	billion	in	2005,	and	net	cash	provided	of	$527	million	in	2004. Significant	uses	of	cash	in	financing	activities	during	2006	included	common	stock	repurchases	under	a	previously	announced	plan,	which	is	discussed	under	Liquidity and	Capital	Resources,	dividend	payments,	the	repayment	of	our	6.65%	notes	that	matured	during	2006	and	the	early	extinguishment	of	portions	of	our	outstanding debt.	The	most	significant	use	of	cash	in	2005	was	related	to	the	repayment	of	$1.920	billion	of	debt	assumed	as	a	part	of	the	acquisition	of	Ashland's	38	percent	of MPC.	In	2004,	cash	provided	from	financing	activities	was	primarily	related	to	the	issuance	of	34,500,000	shares	of	common	stock	on	March	31,	2004,	resulting	in	net proceeds	of	$1.004	billion.	The	change	from	2004	to	2005	also	included	an	increase	in	dividends	paid	and	distributions	to	the	minority	shareholder	of	MPC	prior	to	the Acquisition,	net	of	an	increase	in	contributions	from	the	minority	shareholders	of	EGHoldings.

# Derivative	Instruments

								See	"Quantitative	and	Qualitative	Disclosures	about	Market	Risk"	on	page	56,	for	a	discussion	of	derivative	instruments	and	associated	market	risk.

# Dividends	to	Stockholders

								Dividends	of	$1.53	per	common	share	or	$548	million	were	paid	during	2006.	On	January	29,	2007,	our	Board	of	Directors	declared	a	dividend	of	$0.40	cents	per share	on	our	common	stock,	payable	March	12,	2007,	to	stockholders	of	record	at	the	close	of	business	on	February	21,	2007.

# Liquidity	and	Capital	Resources

								Our	main	sources	of	liquidity	and	capital	resources	are	internally	generated	cash	flow	from	operations,	committed	credit	facilities	and	access	to	both	the	debt	and equity	capital	markets.	Our	ability	to	access	the	debt	capital	market	is	supported	by	our	investment	grade	credit	ratings.	Our	senior	unsecured	debt	is	currently	rated investment	grade	by	Standard	and	Poor's	Corporation,	Moody's	Investor	Services,	Inc.	and	Fitch	Ratings	with	ratings	of	BBB+,	Baa1,	and	BBB+.	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	programs,	stock	repurchase	program,	repayment	of	debt	maturities	and	any	amounts	that	may	ultimately	be	paid	in connection	with	contingencies.

								During	2006,	we	entered	into	an	amendment	to	our	$1.5	billion	five-year	revolving	credit	agreement,	expanding	the	size	of	the	facility	to	$2.0	billion	and	extending the	termination	date	from	May	2009	to	May	2011.	Concurrent	with	this	amendment,	the	$500	million	MPC	revolving	credit	facility	was	terminated.	At	December	31, 2006,	there	were	no	borrowings	against	this	facility.	At	December	31,	2006,	we	had	no	commercial	paper	outstanding	under	our	U.S.	commercial	paper	program	that	is backed	by	the	five-year	revolving	credit	facility.

								During	2006	we	entered	into	a	loan	agreement	which	allows	borrowings	of	up	to	$525	million	from	the	Norwegian	export	credit	agency	based	upon	the	amount	of qualifying	purchases	by	Marathon	of	goods	and	services	from	Norwegian	suppliers.	The	loan	agreement	provides	for	either	a	fixed	or	floating	interest	rate	option	at	the time	of	the	initial	drawdown.	Should	we	elect	to	borrow	under	the	agreement,	the	initial	drawdown	can	only	occur	in	June	2007.

								As	a	condition	of	the	closing	agreements	for	the	Acquisition,	we	are	required	to	maintain	MPC	on	a	stand-alone	basis	financially	through	June	30,	2007.	During	this period	of	time,	capital	contributions	into	MPC	are	prohibited	and	MPC	is	prohibited	from	incurring	additional	debt,	except	for	borrowings	under	an	existing intercompany	loan	facility	to	fund	an	expansion	project	at	MPC's	Detroit	refinery	and	in	the	event	of	limited	extraordinary	circumstances.	There	are	no	restrictions against	MPC	making	intercompany	loans	or	declaring	dividends	to	its	parent.	We	believe	that	the

existing	cash	balances	of	MPC	and	cash	provided	from	its	operations	will	be	adequate	to	meet	its	stand-alone	liquidity	requirements	over	the	remainder	of	this	two-year period.

								As	of	December	31,	2006,	there	was	$1.7	billion	aggregate	amount	of	common	stock,	preferred	stock	and	other	equity	securities,	debt	securities,	trust	preferred securities	or	other	securities,	including	securities	convertible	into	or	exchangeable	for	other	equity	or	debt	securities	available	to	be	issued	under	the	$2.7	billion universal	shelf	registration	statement	filed	with	the	Securities	and	Exchange	Commission	in	2002.

								Our	cash-adjusted	debt-to-capital	ratio	(total-debt-minus-cash	to	total-debt-plus-equity-minus-cash)	was	six	percent	at	December	31,	2006,	compared	to	11	percent at	year-end	2005	as	shown	below.	This	includes	$519	million	of	debt	that	is	serviced	by	United	States	Steel.

|  | 2006 | 2005 |
| :--- | :--- | :--- |
| Long-term\tdebt\tdue\twithin\tone\tyear | $471 | $315 |
| Long-term\tdebt | 3,061 | 3,698 |
| Total\tdebt | $3,532 | $4,013 |
| Cash | $2,585 | $2,617 |
| Equity | $14,607 | $11,705 |
| Calculation: |  |  |
| Total\tdebt | $3,532 | $4,013 |
| Minus\tcash | 2,585 | 2,617 |
| Total\tdebt\tminus\tcash | 947 | 1,396 |
| Total\tdebt | 3,532 | 4,013 |
| Plus\tequity | 14,607 | 11,705 |
| Minus\tcash | 2,585 | 2,617 |
| Total\tdebt\tplus\tequity\tminus\tcash | $15,554 | $13,101 |
| Cash-adjusted\tdebt-to-capital\tratio | 6% | 11% |

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

								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.

# Stock	Repurchase	Program

								In	January	2006,	we	announced	a	$2	billion	share	repurchase	program.	In	January	2007,	our	Board	of	Directors	authorized	the	extension	of	this	share	repurchase program	by	an	additional	$500	million.	As	of	February	21,	2007,	we	had	repurchased	24.2	million	common	shares	at	a	cost	of	$2	billion.	We	anticipate	completing	the additional	$500	million	in	share	repurchases	during	the	first	half	of	2007.	Purchases	under	the	program	may	be	in	either	open	market	transactions,	including	block purchases,	or	in	privately	negotiated	transactions.	We	will	use	cash	on	hand,	cash	generated	from	operations	or	cash	from	available	borrowings	to	acquire	shares.	This program	may	be	changed	based	upon	our	financial	condition	or	changes	in	market	conditions	and	is	subject	to	termination	prior	to	completion.

								The	forward-looking	statements	about	our	common	stock	repurchase	program	are	based	on	current	expectations,	estimates	and	projections	and	are	not	guarantees of	future	performance.	Actual	results	may	differ	materially	from	these	expectations,	estimates	and	projections	and	are	subject	to	certain	risks,	uncertainties	and	other factors,	some	of	which	are	beyond	our	control	and	are	difficult	to	predict.	Some	factors	that	could	cause	actual	results	to	differ	materially	are	changes	in	prices	of	and demand	for	crude	oil,	natural	gas	and	refined	products,	actions	of	competitors,	disruptions	or	interruptions	of	our	production	or	refining	operations	due	to	unforeseen hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	the	governmental	or	military	response,	and	other	operating	and	economic	considerations.

# Contractual	Cash	Obligations

								The	table	below	provides	aggregated	information	on	our	obligations	to	make	future	payments	under	existing	contracts	as	of	December	31,	2006.

# Summary	of	Contractual	Cash	Obligations

| (In	millions)<br>(a)(b) | Total | 2007 | 2008-<br>2009 | 2010-<br>2011 | Later<br>Years |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Long-term\tdebt\t(excludes\tinterest) | $3,398 | $450 | $400 | $143 | $2,405 |
| (a) |  |  |  |  |  |
| Sale-leaseback\tfinancing\t(includes\timputed\tinterest) | 75 | 20 | 22 | 22 | 11 |
| (a) |  |  |  |  |  |
| Capital\tlease\tobligations | 141 | 16 | 33 | 33 | 59 |
| (a) |  |  |  |  |  |
| Operating\tlease\tobligations | 851 | 154 | 286 | 158 | 253 |
| (a) |  |  |  |  |  |
| Operating\tlease\tobligations\tunder\tsublease\nPurchase\tobligations: | 32 | 5 | 11 | 11 | 5 |
| (c) |  |  |  |  |  |
| Crude\toil,\trefinery\tfeedstock,\trefined\tproduct\tand\tethanol\tcontracts | 14,419 | 12,588 | 852 | 655 | 324 |
| Transportation\tand\trelated\tcontracts | 1,445 | 515 | 323 | 201 | 406 |
| Contracts\tto\tacquire\tproperty,\tplant\tand\tequipment | 1,703 | 935 | 719 | 37 | 12 |
| (d) |  |  |  |  |  |
| LNG\tterminal\toperating\tcosts | 178 | 13 | 24 | 25 | 116 |
| (e) |  |  |  |  |  |
| Service\tand\tmaterials\tcontracts | 602 | 210 | 231 | 81 | 80 |
| (f) |  |  |  |  |  |
| Unconditional\tpurchase\tobligations | 62 | 7 | 14 | 14 | 27 |
| (g) |  |  |  |  |  |
| Commitments\tfor\toil\tand\tgas\texploration\t(non-capital) | 100 | 57 | 31 | 2 | 10 |
| Total\tpurchase\tobligations | 18,509 | 14,325 | 2,194 | 1,015 | 975 |
| Other\tlong-term\tliabilities\treported\tin\tthe\tconsolidated\tbalance\tsheet: |  |  |  |  |  |
| (h) |  |  |  |  |  |
| Defined\tbenefit\tpostretirement\tplan\tobligations | 1,627 | 97 | 164 | 276 | 1,090 |
| (i) |  |  |  |  |  |
| Total\tcontractual\tcash\tobligations | $24,633 | $15,067 | $3,110 | $1,658 | $4,798 |

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

(c) The	majority	of	these	contractual	obligations	as	of	December	31,	2006	relate	to	contracts	to	be	satisfied	within	the	first	180	days	of	2007.	These	contracts	include	variable	price	arrangements	and	some contracts	are	accounted	for	as	nontraditional	derivatives.

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

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

(f) We	are	a	party	to	a	long-term	transportation	services	agreement	with	Alliance	Pipeline.	This	agreement	is	used	by	Alliance	Pipeline	to	secure	its	financing.	This	arrangement	represents	an	indirect	guarantee	of indebtedness.	Therefore,	this	amount	has	also	been	disclosed	as	a	guarantee.	See	Note	30	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	obligations	consisting	of	pensions	and	other	postretirement	benefits	including	medical	and	life	insurance.	We	have	estimated	projected	funding	requirements	through	2016.

(i) Includes	$581	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	49.

# 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	others.	These	arrangements	are	described	in	Note	30	to	the consolidated	financial	statements.

We	are	a	party	to	an	agreement	that	would	require	us	to	purchase,	under	certain	circumstances,	the	interest	in	Pilot	Travel	Centers	LLC	("PTC")	not	currently	owned. This	put/call	agreement	is	described	in	Note	30	to	the	consolidated	financial	statements.

# Nonrecourse	Indebtedness	of	Investees

								Certain	of	our	investees	have	incurred	indebtedness	that	we	do	not	support	through	guarantees	or	otherwise.	If	we	were	obligated	to	share	in	this	debt	on	a	pro	rata ownership	basis,	our	share	would	have	been	$340	million	as	of	December	31,	2006.	Of	this	amount,	$217	million	relates	to	PTC.	If	any	of	these	investees	default,	we have	no	obligation	to	support	the	debt.	Our	partner	in	PTC	has	guaranteed	$75	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	our	USX	–	U.	S.	Steel	Group	class	of	common	stock	in	exchange	for	all	outstanding	shares	of	Steel	Stock	on	a	one-for-one	basis.

								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,	2006,	we	have	identified	the	following	obligations	totaling	$564	million	that	have	been	assumed	by	United	States	Steel:

•$415	million	of	industrial	revenue	bonds	related	to	environmental	improvement	projects	for	current	and	former	United	States	Steel	facilities,	with maturities	ranging	from	2009	through	2033.	Accrued	interest	payable	on	these	bonds	was	$11	million	at	December	31,	2006.

•$60	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,	2006.

•$44	million	of	obligations	under	a	lease	for	equipment	at	United	States	Steel's	Clairton	coke-making	facility,	with	a	term	extending	to	2012.	There	was no	accrued	interest	payable	on	this	financing	at	December	31,	2006.

•$34	million	of	operating	lease	obligations,	$31	million	of	which	was	in	turn	assumed	by	purchasers	of	major	equipment	used	in	plants	and	operations divested	by	United	States	Steel.

•A	guarantee	of	all	obligations	of	United	States	Steel	as	general	partner	of	Clairton	1314B	Partnership,	L.P.	to	the	limited	partners.	United	States	Steel	has reported	that	it	currently	has	no	unpaid	outstanding	obligations	to	the	limited	partners.	For	further	discussion	of	the	Clairton	1314B	guarantee,	see	Note	3 to	the	consolidated	financial	statements.

								Of	the	total	$564	million,	obligations	of	$530	million	and	corresponding	receivables	from	United	States	Steel	were	recorded	on	our	consolidated	balance	sheet	as	of December	31,	2006	(current	portion	–	$32	million;	long-term	portion	–	$498	million).	The	remaining	$34	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,	2006:

# Summary	of	Contractual	Cash	Obligations	Assumed	by	United	States	Steel

| (In	millions) | Total | 2007 | 2008-<br>2009 | 2010-<br>2011 | Later<br>Years |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Contractual\tobligations\tassumed\tby\tUnited\tStates\tSteel |  |  |  |  |  |
| (a)\nLong-term\tdebt | $415 | $– | $– | $– | $415 |
| Sale-leaseback\tfinancing\t(includes\timputed\tinterest) | 75 | 20 | 22 | 22 | 11 |
| Capital\tlease\tobligations | 58 | 10 | 19 | 19 | 10 |
| Operating\tlease\tobligations | 3 | 3 | – | – | – |
| Operating\tlease\tobligations\tunder\tsublease | 30 | 5 | 10 | 10 | 5 |
| Total\tcontractual\tobligations\tassumed\tby\tUnited\tStates\tSteel | $581 | $38 | $51 | $51 | $441 |

								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.	In	2006	and	2005,	in	accordance	with	the	terms	of	the	tax	sharing	agreement,	we	paid	$35	million	and	$6	million	to	United	States	Steel	in	connection	with	the settlement	with	the	Internal	Revenue	Service	of	the	consolidated	federal	income	tax	returns	of	USX	Corporation	for	the	years	1995	through	2001.	The	final	payment	of $13	million	to	United	States	Steel	related	to	U.S.	federal	income	tax	returns	under	the	tax	sharing	agreement	was	made	in	January	2007.

								United	States	Steel	reported	in	its	Form	10-K	for	the	year	ended	December	31,	2006,	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.

# Transactions	with	Related	Parties

								We	own	a	63	percent	working	interest	in	the	Alba	field	offshore	Equatorial	Guinea.	We	own	a	52	percent	interest	in	an	onshore	LPG	processing	plant	in	EG 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.

								Sales	to	our	50	percent	equity	method	investee,	PTC,	which	consists	primarily	of	refined	petroleum	products,	accounted	for	two	percent	or	less	of	our	total	sales revenue	for	2006,	2005	and	2004.	PTC	is	the	largest	travel	center	network	in	the	United	States	and	operates	269	travel	centers	in	the	United	States	and	Canada.	Prior	to the	Acquisition	on	June	30,	2005,	Ashland	was	a	related	party	as	a	result	of	its	38	percent	minority	interest	in	MPC.	During	that	time,	we	sold	refined	petroleum products	consisting	mainly	of	petrochemicals,	base	lube	oils	and	asphalt	to	Ashland.	Our	sales	to	Ashland	accounted	for	less	than	one	percent	of	our	total	sales	revenue for	2005	and	2004.	We	believe	that	these	transactions	were	conducted	under	terms	comparable	to	those	with	unrelated	parties.

								Marathon	holds	a	60	percent	interest,	SONAGAS	holds	a	25	percent	interest,	Mitsui	holds	an	8.5	percent	interest	and	Marubeni	holds	a	6.5	percent	interest	in EGHoldings.	As	of	December	31,	2006,	total	expenditures	of	$1.363	billion,	including	$1.300	billion	of	capital	expenditures,	related	to	the	Equatorial	Guinea	LNG production	facility	have	been	incurred.	Cash	of	$234	million	held	in	escrow	to	fund	future	contributions	from	SONAGAS	to	EGHoldings	is	classified	as	restricted	cash and	is	included	in	investments	and	long-term	receivables	as	of	December	31,	2006.	Our	current	receivables	from	and	payables	to	the	interest	holders	in	EGHoldings	are $13	million	and	$232	million	as	of	December	31,	2006,	including	a	payable	to	SONAGAS	of	$229	million.

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

								We	have	incurred	and	will	continue	to	incur	substantial	capital,	operating	and	maintenance,	and	remediation	expenditures	as	a	result	of	environmental	laws	and regulations.	If	these	expenditures,	as	with	all	costs,	are	not	ultimately	reflected	in	the	prices	of	our	products	and	services,	our	operating	results	will	be	adversely	affected. We	believe	that	substantially	all	of	our	competitors	must	comply	with	similar	environmental	laws	and	regulations.

However,	the	specific	impact	on	each	competitor	may	vary	depending	on	a	number	of	factors,	including	the	age	and	location	of	its	operating	facilities,	marketing	areas, production	processes	and	whether	it	is	also	engaged	in	the	petrochemical	business	or	the	marine	transportation	of	crude	oil	and	refined	products.

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Capital | $166 | $390 | $433 |
| Compliance |  |  |  |
| Operating\t&amp;\tmaintenance | 319 | 250 | 215 |
| (b)\nRemediation | 20 | 25 | 32 |
| Total | $505 | $665 | $680 |

(a) Amounts	are	determined	based	on	American	Petroleum	Institute	survey	guidelines.

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

								Our	environmental	capital	expenditures	accounted	for	5	percent	of	capital	expenditures	for	continuing	operations	in	2006,	14	percent	in	2005	and	20	percent	in 2004.

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

								New	or	expanded	environmental	requirements,	which	could	increase	our	environmental	costs,	may	arise	in	the	future.	We	comply	with	all	legal	requirements regarding	the	environment,	but	since	not	all	of	them	are	fixed	or	presently	determinable	(even	under	existing	legislation)	and	may	be	affected	by	future	legislation	or regulations,	it	is	not	possible	to	predict	all	of	the	ultimate	costs	of	compliance,	including	remediation	costs	that	may	be	incurred	and	penalties	that	may	be	imposed.

								Our	environmental	capital	expenditures	are	expected	to	be	approximately	$159	million	or	8	percent	of	capital	expenditures	in	2007.	Predictions	beyond	2007	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	$277	million	in	2008;	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.

								Of	particular	significance	to	our	refining	operations	were	U.S.	EPA	regulations	that	required	reduced	sulfur	levels	starting	in	2004	for	gasoline	and	2006	for	diesel fuel.	We	achieved	compliance	with	these	regulations	and	began	production	of	ultra-low	sulfur	diesel	fuel	for	on-road	use	prior	to	the	June	1,	2006	deadline.	The	cost	of achieving	compliance	with	these	regulations	was	approximately	$850	million.	We	will	also	be	spending	approximately	$250	million	from	2006	through	2010	to	produce ultra-low	sulfur	diesel	fuel	for	off-road	use.	Further,	we	estimate	that	we	will	spend	approximately	$400	million	over	a	four-year	period	beginning	in	2008	to	comply with	Mobile	Source	Air	Toxics	II	regulations	relating	to	benzene.	This	is	a	preliminary	estimate	as	the	Mobile	Source	Air	Toxics	II	regulations	should	be	finalized	in	the first	half	of	2007.

								During	2001,	MPC	entered	into	a	New	Source	Review	consent	decree	and	settlement	of	alleged	Clean	Air	Act	and	other	violations	with	the	EPA	covering	all	of	its refineries.	The	settlement	committed	MPC	to	specific	control	technologies	and	implementation	schedules	for	environmental	expenditures	and	improvements	to	its refineries	over	approximately	an	eight-year	period.	In	addition,	MPC	has	been	working	on	certain	agreed	upon	supplemental	environmental	projects	as	part	of	this settlement	of	an	enforcement	action	for	alleged	CAA	violations	and	these	have	been	substantially	completed.

								The	oil	industry	across	the	U.K.	continental	shelf	is	making	reductions	in	the	amount	of	oil	in	its	produced	water	discharges	pursuant	to	the	Department	of	Trade and	Industry	initiative	under	the	Oil	Pollution	Prevention	and	Control	Regulations	("OSPAR")	of	2005.	In	compliance	with	these	regulations,	we	have	almost	completed our	OSPAR	project	for	the	Brae	field	to	make	the	required	reductions	of	oil	in	its	produced	water	discharges.	Our	share	of	capital	costs	for	the	project	is	$7	million.

								For	information	on	legal	proceedings	related	to	environmental	matters,	see	"Item	3.	Legal	Proceedings."

# Outlook

# Capital,	Investment	and	Exploration	Budget

								We	approved	a	capital,	investment	and	exploration	budget	of	$4.242	billion	for	2007,	which	includes	budgeted	capital	expenditures	of	$3.886	billion.	This represents	a	16	percent	increase	over	2006	actual	spending.	The	primary	focus	of	the	2007	budget	is	to	find	additional	oil	and	natural	gas	reserves,	develop	existing fields,	strengthen	RM&T	assets	and	continue	implementation	of	the	integrated	gas	strategy.	The	budget	includes	worldwide	production	spending	of	$1.429	billion primarily	in	the	United	States,	Norway,	Libya	and	Ireland.	The	worldwide	exploration	budget	of	$802	million	includes	plans	to	drill	14	to	17	significant	exploration	or appraisal	wells.	Other	activities	will	focus	primarily	on	areas	within	or	adjacent	to	our	onshore	producing	properties	in	the	United	States.	The	budget	includes $1.464	billion	for	RM&T,	primarily	for	refining	projects	including	the	180	mbpd	Garyville	refinery	expansion	project	and	the	FEED	for	a	potential	Detroit	refinery heavy	oil	upgrading	project	which	would	allow	us	to	process	increased	volumes	of	Canadian	oil	sands	production.	The	RM&T	budget	also	includes	increased investments	in	transportation	and	logistics,	a	strategically	important	area	of	the	business,	including	the	expansion	of	our	ethanol	blending	capabilities	at	terminals	in	the Midwest	and	Southeast.	The	integrated	gas	budget	of	$331	million	is	primarily	for	completion	of	the	LNG	processing	facility	in	Equatorial	Guinea,	as	well	as	FEED expenditures	associated	with	a	potential	expansion	of	that	facility.	The	remaining	$216	million	is	designated	for	capitalized	interest	and	corporate	activities.

								The	seven	announced	discoveries	in	2006	(six	in	deepwater	Angola	and	one	in	Norway)	resulted	from	our	balanced	exploration	strategy	which	places	an	emphasis on	near-term	production	opportunities,	while	retaining	an	appropriate	exposure	to	longer-term	options.	Major	exploration	activities,	which	are	currently	underway	or under	evaluation,	include	those:

•offshore	Angola,	where	we	have	participated	in	13	discoveries	on	Block	31,	in	which	we	hold	a	10	percent	outside-operated	interest.	In	2006,	we announced	the	Urano,	Titania	and	Terra	discoveries,	as	well	as	an	unnamed	discovery.	Current	plans	call	for	a	potential	development	area	in	the northeastern	part	of	Block	31,	which	encompasses	the	Plutao,	Saturno,	Marte,	Venus	and	Terra	discoveries.	The	remaining	discoveries	are	being evaluated	for	potential	development.	We	have	secured	rig	capacity	for	and	plan	to	participate	in	exploration	wells	on	Block	31	during	2007;

•offshore	Angola	on	Block	32	in	which	we	hold	a	30	percent	outside-operated	interest	and	where	we	participated	in	five	discoveries	through	2006, Gindungo,	Canela,	Gengibre,	Mostarda	and	Salsa,	and	announced	two	additional	discoveries	in	2007,	Manjericao	and	Caril.	These	discoveries	move Block	32	closer	toward	establishment	of	a	commercial	development.	We	have	secured	rig	capacity	for	and	plan	to	participate	in	exploration	wells	on Block	32	during	2007;

•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	production	facility	on	Bioko	Island.	We	own	a	63	percent	interest	in	the Alba	Block	and	serve	as	operator;

•in	Norway,	where	we	now	own	interests	in	15	licenses	in	the	Norwegian	sector	of	the	North	Sea	and	plan	to	drill	one	or	two	exploration	wells	during 2007;	and

•in	the	Gulf	of	Mexico,	where	we	plan	to	participate	in	two	to	three	exploration	wells	during	2007.	We	have	secured	rig	capacity	to	drill	two	wells	and	our ability	to	drill	the	third	well	depends	upon	securing	additional	rig	capacity.

								During	2006,	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	Libya,	where	we	re-entered	the	Waha	concessions	at	the	end	of	2005	and	achieved	first	production	in	January	2006.	We	continue	to	work	with	our partners	to	maximize	the	potential	of	this	major	asset.	We	own	a	16.33	percent	outside-operated	interest	in	the	approximately	13	million	acre	Waha concessions;

•in	Norway,	where	our	Alvheim/Vilje	development	will	consist	of	a	floating	production,	storage	and	offloading	vessel	with	subsea	infrastructure	for	five drill	centers	and	associated	flow	lines.	Construction	on	the	project	is	nearly	complete	and	commissioning	has	commenced.	First	production	is	expected during	the	second	quarter	2007,	at	which	time	four	wells	will	be	available,	and	drilling	activities	will	continue	into	2008.	A	peak	net	production	rate	of 75	mboepd	is	expected	in	early	2008.	The	Alvheim	development	includes	the	Kneler,	Boa

and	Kameleon	fields	in	which	we	own	a	65	percent	interest	and	serve	as	operator.	We	own	a	47	percent	outside-operated	interest	in	the	nearby	Vilje discovery.	Also,	plans	for	development	of	the	Volund	discovery	as	a	tie-back	to	the	Alvheim	development	were	approved	by	the	Norwegian	Government in	early	2007.	First	production	is	expected	from	Volund	in	the	second	quarter	of	2009.	We	own	a	65	percent	interest	in	Volund	and	serve	as	operator;

•in	the	Gulf	of	Mexico,	where	the	Neptune	development	is	on	target	for	first	production	by	early	2008.	We	own	a	30	percent	outside-operated	interest	in Neptune;

•in	Ireland,	where	the	Corrib	natural	gas	development	project	has	re-commenced	and	we	expect	first	production	in	2009.	We	own	a	19	percent	outside- operated	interest	in	Corrib;

•in	the	Piceance	Basin	where	we	plan	to	drill	approximately	700	wells	over	the	next	ten	years,	with	first	production	expected	in	late	2007;	and

•in	the	Bakken	Shale	where	we	plan	to	drill	approximately	300	locations	over	the	next	five	years.

								We	estimate	that	our	2007	production	available	for	sale	will	average	approximately	390	to	425	mboepd,	excluding	the	impact	of	acquisitions	and	dispositions.	With the	developments	we	have	under	construction,	we	estimate	our	production	available	for	sale	will	grow	to	465	to	520	mboepd	by	2010,	excluding	acquisitions	and dispositions.	Projected	liquid	hydrocarbon	and	natural	gas	production	available	for	sale	is	based	on	a	number	of	assumptions,	including	(among	others)	pricing,	supply and	demand	for	petroleum	products,	the	amount	of	capital	available	for	exploration	and	development,	regulatory	constraints,	production	decline	rates	of	mature	fields, timing	of	commencing	production	from	new	wells,	drilling	rig	availability,	inability	or	delay	in	obtaining	necessary	government	and	third-party	approvals	and	permits, unforeseen	hazards	such	as	weather	conditions,	acts	of	war	or	terrorist	acts	and	the	government	or	military	response,	and	other	geological,	operating	and	economic considerations.	These	assumptions	may	prove	to	be	inaccurate.

								In	2006,	we	issued	a	request	for	proposals	to	engage	interested	parties	in	a	process	that	could	lead	to	a	Canadian	oil	sands	venture.	This	process	is	intended	to explore	various	commercial	arrangements	under	which	we	would	provide	heavy	Canadian	oil	sands	crude	oil	processing	capacity	in	exchange	for	an	equity	interest	in	a Canadian	oil	sands	project	through	a	joint	venture,	or	other	alternative	business	arrangements	that	potential	partners	may	choose	to	propose.

								The	above	discussion	includes	forward-looking	statements	with	respect	to	anticipated	future	exploratory	and	development	drilling,	the	possibility	of	developing Blocks	31	and	32	offshore	Angola,	the	timing	of	production	from	the	Neptune	development,	the	Piceance	Basin,	the	combined	Alvheim/Vilje	development,	the	Volund field	and	the	Corrib	project.	Some	factors	which	could	potentially	affect	these	forward-looking	statements	include	pricing,	supply	and	demand	for	petroleum	products, the	amount	of	capital	available	for	exploration	and	development,	regulatory	constraints,	drilling	rig	availability,	unforeseen	hazards	such	as	weather	conditions,	acts	of war	or	terrorist	acts	and	the	governmental	or	military	response,	and	other	geological,	operating	and	economic	considerations.	Except	for	the	Alvheim/Vilje	and	Volund developments,	the	foregoing	forward-looking	statements	may	be	further	affected	by	the	inability	to	or	delay	in	obtaining	necessary	government	and	third-party	approvals and	permits.	The	possible	developments	in	Blocks	31	and	32	could	further	be	affected	by	presently	known	data	concerning	size	and	character	of	reservoirs,	economic recoverability,	future	drilling	success	and	production	experience.	The	above	discussion	also	contains	forward-looking	statements	concerning	a	potential	Canadian	oil sands	venture.	Factors	that	could	affect	the	formation	of	a	Canadian	oil	sands	venture	include	unforeseen	difficulty	in	negotiation	of	definitive	agreements,	results	of front-end	engineering	and	design	work,	inability	or	delay	in	obtaining	necessary	government	and	third-party	approvals,	continued	favorable	investment	climate,	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.

								Throughout	2006,	we	remained	focused	on	our	strategy	of	leveraging	refining	and	marketing	investments	in	core	markets,	as	well	as	expanding	and	enhancing	our asset	base	while	controlling	costs.	Our	2006	average	daily	crude	oil	throughput	exceeded	the	record	throughput	achieved	in	2005.

								In	2006,	our	Board	of	Directors	approved	a	projected	$3.2	billion	expansion	of	our	Garyville	refinery	by	180	mbpd	to	425	mbpd,	which	will	increase	our	total refining	capacity	to	1.154	mmbpd.	We	recently	received	air	permit	approval	from	the	Louisiana	Department	of	Environmental	Quality	for	this	project	and	construction	is expected	to	begin	in	mid-2007,	with	startup	planned	for	the	fourth	quarter	of	2009.	When	completed,	this	expansion	will	enable	the	refinery	to	provide	an	additional 7.5	million	gallons	of	clean	transportation	fuels	to	the	market	each	day.

								We	have	also	commenced	front-end	engineering	and	design	for	a	potential	heavy	oil	upgrading	project	at	our	Detroit	refinery	which	would	allow	us	to	process increased	volumes	of	Canadian	oil	sand	production	and	are	undertaking	a	feasibility	study	for	a	similar	upgrading	project	at	our	Catlettsburg	refinery.

								In	2006,	we	signed	a	definitive	agreement	forming	a	joint	venture	that	will	construct	and	operate	one	or	more	ethanol	production	plants.	Our	partner	in	the	joint venture	will	provide	the	day-to-day	management	of	the	plants,	as	well	as	grain	procurement,	and	distillers	dried	grain	marketing	and	ethanol	management	services.	This venture	will	enable	us	to	maintain	the	reliability	of	a	portion	of	our	future	ethanol	supplies.	Together	with	our	partner,	we	selected	the	venture's	initial	plan	site, Greenville,	Ohio,	and	construction	has	commenced	on	a	110	million	gallon	per	year	ethanol	facility.	The	facility	is	expected	to	be	operational	as	soon	as	the	first	quarter of	2008.

								The	above	discussion	includes	forward-looking	statements	concerning	the	planned	expansion	of	the	Garyville	refinery,	potential	heavy	oil	refining	upgrading projects	and	a	joint	venture	that	would	construct	and	operate	ethanol	plants.	Some	factors	that	could	affect	the	Garyville	expansion	project	and	the	ethanol	plant construction,	management	and	development	include	necessary	government	and	third	party	approvals,	transportation	logistics,	availability	of	materials	and	labor, unforeseen	hazards	such	as	weather	conditions	and	other	risks	customarily	associated	with	construction	projects.	The	Garyville	project	may	be	further	affected	by	crude oil	supply.	These	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.	Factors	that	could	affect the	heavy	oil	refining	upgrading	projects	include	unforeseen	difficulty	in	negotiation	of	definitive	agreements,	results	of	front-end	engineering	and	design	work, approval	of	our	Board	of	Directors,	inability	or	delay	in	obtaining	necessary	government	and	third-party	approvals,	continued	favorable	investment	climate,	and	other geological,	operating	and	economic	considerations.

								Construction	of	the	LNG	production	facility	in	Equatorial	Guinea	continues	ahead	of	its	original	schedule	with	the	first	shipments	of	LNG	projected	for	the	second quarter	of	2007.	Construction	is	nearly	complete	and	commissioning	has	commenced.	We	own	a	60	percent	interest	in	Equatorial	Guinea	LNG	Holdings	Limited.	We are	currently	seeking	additional	natural	gas	supplies	to	allow	full	utilization	of	this	LNG	facility,	which	is	designed	to	have	a	higher	capacity	and	a	longer	life	than	the current	contract	to	supply	3.4	million	metric	tons	per	year	for	17	years.

								Once	the	Equatorial	Guinea	LNG	production	facility	commences	its	principal	operations	and	begins	to	generate	revenue,	we	must	assess	whether	or	not EGHoldings	continues	to	be	a	variable	interest	entity	("VIE").	We	consolidate	EGHoldings	because	it	is	a	VIE	and	we	are	its	primary	beneficiary.	Despite	the	fact	that we	hold	majority	ownership,	we	would	not	consolidate	EGHoldings	if	it	ceased	to	be	a	VIE	because	the	minority	shareholders	have	substantive	participating	rights.	If EGHoldings	ceased	to	be	a	VIE,	we	would	account	for	our	interest	using	the	equity	method	of	accounting.

								In	2006,	with	our	project	partners,	we	awarded	a	FEED	contract	for	initial	work	related	to	a	potential	second	LNG	production	facility	on	Bioko	Island,	Equatorial Guinea.	The	FEED	work	is	expected	to	be	completed	during	2007.	The	scope	of	the	FEED	work	for	the	potential	4.4	million	metric	tones	per	annum	LNG	facility includes	feed	gas	metering,	liquefaction,	refrigeration,	ethylene	storage,	boil	off	gas	compression,	product	transfer	to	storage	and	LNG	product	metering.	A	final investment	decision	is	expected	in	early	2008.

								Atlantic	Methanol	Production	Company	LLC	underwent	a	scheduled	maintenance	shutdown	in	2006,	during	which	bottlenecks	in	several	parts	of	the	plant	were also	removed.	Deliveries	resumed	in	October	2006	and	AMPCO	expects	to	reach	its	full	expansion	capacity	during	2007.

								The	above	discussion	contains	forward	looking	statements	with	respect	to	the	timing	and	levels	of	production	associated	with	the	LNG	production	facility	and	the possible	expansion	thereof.	Factors	that	could	affect	the	LNG	production	facility	include	unforeseen	problems	arising	from	commissioning	of	the	facilities,	unforeseen hazards	such	as	weather	conditions	and	other	operating	considerations	such	as	shipping	the	LNG.	In	addition	to	these	factors,	other	factors	that	could	potentially	affect the	possible	expansion	of	the	current	LNG	production	facility	and	the	development	of	additional	LNG	capacity	through	additional	projects	include	partner	approvals, access	to	sufficient	natural	gas	volumes	through	exploration	or	commercial	negotiations	with	other	resource	owners	and	access	to	sufficient	regasification	capacity.	The foregoing	factors	(among	others)	could	cause	actual	results	to	differ	materially	from	those	set	forth	in	the	forward-looking	statements.

# Accounting	Standards	Not	Yet	Adopted

								In	February	2007,	the	FASB	issued	SFAS	No.	159,	"The	Fair	Value	Option	for	Financial	Assets	and	Financial	Liabilities."	This	statement	permits	entities	to	choose to	measure	many	financial	instruments	and	certain	other	items	at	fair	value	that	are	not	currently	required	to	be	measured	at	fair	value.	It	requires	that	unrealized	gains and	losses	on	items	for	which	the	fair	value	option	has	been	elected	be	recorded	in	net	income.	The	statement	also	establishes	presentation	and	disclosure	requirements designed	to	facilitate	comparisons	between	entities	that	choose	different	measurement	attributes	for	similar	types	of	assets	and	liabilities.	For	us,	SFAS	No.	159	will	be effective	January	1,	2008,	and	retrospective	application	is	not	permitted.	Should	we	elect	to	apply	the	fair	value	option	to	any	eligible	items	that	exist	at	January	1,	2008, the	effect	of	the	first	remeasurement	to	fair	value	would	be	reported	as	a	cumulative	effect	adjustment	to	the	opening	balance	of	retained	earnings.	We	are	currently evaluating	the	provisions	of	this	statement.

								In	September	2006,	the	FASB	issued	SFAS	No.	157,	"Fair	Value	Measurements."	This	statement	defines	fair	value,	establishes	a	framework	for	measuring	fair value	in	generally	accepted	accounting	principles	and	expands	disclosures	about	fair	value	measurements.	SFAS	No.	157	does	not	require	any	new	fair	value measurements	but	may	require	some	entities	to	change	their	measurement	practices.	For	us,	SFAS	No.	157	will	be	effective	January	1,	2008,	with	early	application permitted.	We	are	currently	evaluating	the	provisions	of	this	statement.

								In	September	2006,	the	FASB	issued	FASB	Staff	Position	("FSP")	No.	AUG	AIR-1,	"Accounting	for	Planned	Major	Maintenance	Activities."	This	FSP	prohibits the	use	of	the	accrue-in-advance	method	of	accounting	for	planned	major	maintenance	activities	in	annual	and	interim	financial	reporting	periods.	We	expense	such	costs in	the	same	annual	period	as	incurred;	however,	estimated	annual	major	maintenance	costs	are	recognized	as	expense	throughout	the	year	on	a	pro	rata	basis.	As	such, adoption	of	FSP	No.	AUG	AIR-1	will	have	no	impact	on	our	annual	consolidated	financial	statements.	We	are	required	to	adopt	the	FSP	effective	January	1,	2007.	We do	not	believe	the	provisions	of	FSP	No.	AUG	AIR-1	will	have	a	significant	impact	on	our	interim	consolidated	financial	statements.

								In	July	2006,	the	FASB	issued	FASB	Interpretation	No.	48,	"Accounting	for	Uncertainty	in	Income	Taxes	–	An	Interpretation	of	FASB	Statement	No.	109."	FIN No.	48	clarifies	the	accounting	for	uncertainty	in	income	taxes	recognized	in	an	enterprise's	financial	statements	in	accordance	with	SFAS	No.	109,	"Accounting	for Income	Taxes."	FIN	No.	48	prescribes	a	recognition	threshold	and	measurement	attribute	for	the	financial	statement	recognition	and	measurement	of	a	tax	position	taken or	expected	to	be	taken	in	a	tax	return.	The	new	standard	also	provides	guidance	on	derecognition,	classification,	interest	and	penalties,	accounting	in	interim	periods, transition	and	disclosure.	For	us,	the	provisions	of	FIN	No.	48	are	effective	January	1,	2007.	We	do	not	believe	adoption	of	this	statement	will	have	a	significant	effect on	our	consolidated	results	of	operations,	financial	position	or	cash	flows.

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

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

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

# Management	Opinion	Concerning	Derivative	Instruments

								Management	has	authorized	the	use	of	futures,	forwards,	swaps	and	combinations	of	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	petroleum	feedstocks	used	as	raw	materials	and	on	purchases	of	ethanol.

								Our	strategy	generally	has	been	to	obtain	competitive	prices	for	our	products	and	allow	operating	results	to	reflect	market	price	movements	dictated	by	supply	and demand.	We	use	a	variety	of	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	greater	market	risk.

								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	derivatives	to	protect	the	value	of	natural	gas	purchased	and	injected	into	storage	in	support	of	production	operations.	We	use commodity	derivative	instruments	to	mitigate	the	price	risk	associated	with	the	purchase	and	subsequent	resale	of	natural	gas	on	purchased	volumes	and	anticipated	sales volumes.

# 								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,

•on	fixed	price	contracts	for	ethanol	purchases,

•associated	with	anticipated	natural	gas	purchases	for	refinery	use,	and

•associated	with	freight	on	crude	oil,	feedstocks	and	refined	product	deliveries;

•to	protect	the	value	of	excess	refined	product,	crude	oil	and	liquefied	petroleum	gas	inventories;

•to	protect	margins	associated	with	future	fixed	price	sales	of	refined	products	to	non-retail	customers;

•to	protect	against	decreases	in	future	crack	spreads;	and

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

								We	use	financial	derivative	instruments	to	manage	foreign	currency	exchange	rate	exposure	on	certain	foreign	currency	denominated	capital	expenditures, operating	expenses	and	tax	payments.

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

								We	believe	that	our	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	the	use	of	these	instruments	will	not have	a	material	adverse	effect	on	our	consolidated	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,	2006	and	December	31,	2005,	are	provided	in	the	following	table:

# (In	millions)

| (b)(c) |  |  |  |  |
| :--- | :--- | :--- | :--- | :--- |
| Commodity\tDerivative\tInstruments\n: |  |  |  |  |
|  | 10% | 25% | 10% | 25% |
| (d)\nCrude\toil | $\t\t– | $\t\t– | $11(e) | $25(e) |
| (d)\nNatural\tgas | 47(e) | 119(e) | 78(e) | 195(e) |
| (d)\nRefined\tproducts | 11(f) | 28(f) | 6(e) | 15(e) |

(a) We	remain	at	risk	for	possible	changes	in	the	market	value	of	derivative	instruments;	however,	such	risk	should	be	mitigated	by	price	changes	in	the	underlying	physical	commodity.	Effects	of	these	offsets	are not	reflected	in	the	sensitivity	analyses.	Amounts	reflect	hypothetical	10	percent	and	25	percent	changes	in	closing	commodity	prices,	excluding	basis	swaps,	for	each	open	contract	position	at	December	31, 2006	and	2005.	Included	in	the	natural	gas	impacts	shown	above	are	effects	related	to	the	long-term	U.K.	natural	gas	contracts,	which	were	$54	million	in	2006	and	$90	million	in	2005,	for	hypothetical	price changes	of	10	percent	and	were	$138	million	in	2006	and	$225	million	in	2005	for	hypothetical	price	changes	of	25	percent.	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,	2006,	would	cause	future	IFO	effects	to	differ	from	those	presented in	this	table.

(b) The	number	of	net	open	contracts	for	the	E&P	segment	varied	throughout	2006,	from	a	low	of	316	contracts	on	June	27,	2006	to	a	high	of	1,634	contracts	on	January	2,	2006,	and	averaged	1,054	for	the	year. The	number	of	net	open	contracts	for	the	RM&T	segment	varied	throughout	2006,	from	a	low	of	166	contracts	on	December	7,	2006	to	a	high	of	25,123	contracts	on	August	23,	2006,	and	averaged	13,154	for the	year.	The	derivative	commodity	instruments	used	and	positions	taken	will	vary	and,	because	of	these	variations	in	the	composition	of	the	portfolio	over	time,	the	number	of	open	contracts	by	itself	cannot	be used	to	predict	future	income	effects.

(c) 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	reflects	that	which	would	result	in	the	largest	incremental	decrease	in	IFO	when	applied	to	the	commodity derivative	instruments	used	to	hedge	that	commodity.

(e) Price	increase.

(f) Price	decrease.

# E&P	Segment

								Derivative	gains	of	$25	million	in	2006	and	$7	million	in	2005	and	losses	of	$152	million	in	2004	are	included	in	E&P	segment	results.	Additionally,	losses	from discontinued	cash	flow	hedges	of	$3	million	are	included	in	2004	segment	results.	The	discontinued	cash	flow	hedge	amounts	were	reclassified	from	accumulated	other comprehensive	income	as	it	was	no	longer	probable	that	the	original	forecasted	transactions	would	occur.	The	results	of	activities	primarily	associated	with	the marketing	of	our	equity	natural	gas	production,	which	had	been	presented	as	part	of	the	Integrated	Gas	segment	prior	to	2006,	are	included	in	the	E&P	segment	for	all periods	presented.

								Excluded	from	E&P	segment	results	were	gains	of	$454	million	in	2006	and	losses	of	$386	million	in	2005	and	$99	million	in	2004	related	to	long-term	natural	gas contracts	in	the	United	Kingdom	that	are	accounted	for	as	derivative	instruments.	For	additional	information	on	these	U.K.	natural	gas	contracts,	see	"Fair	Value Estimates"	on	page	37.

								At	December	31,	2006	and	2005,	we	had	no	open	derivative	contracts	related	to	our	oil	and	natural	gas	production	and	therefore	remained	substantially	exposed	to market	prices	of	commodities.	In	2004,	we	reduced	our	exposure	to	market	prices	of	commodities	on	26	percent	of	crude	oil	production	and	7	percent	of	natural	gas production.	We	continue	to	evaluate	the	commodity	price	risks	related	to	our	production	and	may	enter	into	commodity	derivative	instruments	when	it	is	deemed advantageous.	As	a	particular	but	not	exclusive	example,	we	may	elect	to	use	commodity	derivative	instruments	to	achieve	minimum	price	levels	on	some	portion	of	our production	to	support	capital	or	acquisition	funding	requirements.

# 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	in	net	income	all changes	in	the	fair	value	of	derivatives	used	in	our	RM&T	operations.	Pretax	derivative	gains	and	losses	included	in	RM&T	segment	income	for	each	of	the	last	three years	are	summarized	in	the	following	table:

| Strategy	(In	millions) | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Mitigate\tprice\trisk | $204 | $(57) | $(106) |
| Protect\tcarrying\tvalues\tof\texcess\tinventories | 200 | (118) | (98) |
| Protect\tmargins\tassociated\twith\tfixed\tprice\tsales | (4) | 18 | 8 |
| Protect\tcrack\tspread\tvalues | – | (81) | (76) |
| Subtotal,\tnon-trading\tactivities | 400 | (238) | (272) |
| Trading\tactivities | 1 | (87) | 8 |
| Total\tnet\tderivative\tgains\t(losses) | $401 | $(325) | $(264) |

								Derivatives	used	in	non-trading	activities	have	an	underlying	physical	commodity	transaction.	Since	the	majority	of	RM&T	segment	derivative	contracts	are	for	the sale	of	commodities,	derivative	losses	generally	occur	when	market	prices	increase	and	typically	are	offset	by	gains	on	the	underlying	physical	commodity	transactions. Conversely,	derivative	gains	generally	occur	when	market	prices	decrease	and	are	typically	offset	by	losses	on	the	underlying	physical	commodity	transactions.	The income	effect	related	to	derivatives	and	the	income	effect	related	to	the	underlying	physical	transactions	may	not	necessarily	be	recognized	in	net	income	in	the	same period	because	we	do	not	attempt	to	qualify	these	commodity	derivative	instruments	for	hedge	accounting.	The	year-to-year	change	in	the	net	impact	of	derivatives primarily	reflects	changes	in	market	conditions.

# Other	Commodity	Related	Risks

								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.	Over-the-counter	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<br>Value^(b) | Incremental<br>Increase	in<br>Fair<br>Value^(c) | Fair<br>Value^(b) | Incremental<br>Increase	in<br>Fair<br>Value^(c) |
| :--- | :--- | :--- | :--- | :--- |
| Financial\tassets\t(liabilities)\n:\nInvestments\tand\tlong-term\treceivables | $461 | $– | $268 | $– |
| (d)\nInterest\trate\tswap\tagreements | $(22) | $9 | $(30) | $14 |
| (d)(e)\nLong-term\tdebt | $(3,729) | $(132) | $(4,354) | $(152) |

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

(b) See	Notes	18	and	19	to	the	consolidated	financial	statements	for	carrying	value	of	these	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,	2006	and	2005.	For	interest	rate	swap	agreements,	this	assumes	a 10	percent	decrease	in	the	effective	swap	rate	at	December	31,	2006	and	2005.

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

(e) Includes	amounts	due	within	one	year.

								At	December	31,	2006	and	2005,	our	portfolio	of	long-term	debt	was	substantially	comprised	of	fixed	rate	instruments.	Therefore,	the	fair	value	of	the	portfolio	is relatively	sensitive	to	the	effects	of	interest	rate	fluctuations.	This	sensitivity	is	illustrated	by	the	$132	million	increase	in	the	fair	value	of	long-term	debt	at December	31,	2006,	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	unfavorably	affect	our	results	of	operations	and	cash	flows	when	we	elect	to	repurchase	or	otherwise	retire	fixed-rate	debt	at	prices	above carrying	value.

								We	manage	our	exposure	to	interest	rate	movements	by	utilizing	financial	derivative	instruments.	The	primary	objective	of	this	program	is	to	reduce	our	overall cost	of	borrowing	by	managing	the	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	our	interest	rate	swaps	as	of	December	31,	2006:

# (Dollars	in	millions)

| Floating	Rate	to	be	Paid | to	be<br>Received | Notional<br>Amount | Swap<br>Maturity | Fair	Value |
| :--- | :--- | :--- | :--- | :--- |
| Six\tMonth\tLIBOR\t+1.935% | 5.375% $ | 450 | 2007 | $(4) |
| Six\tMonth\tLIBOR\t+3.285% | 6.850% $ | 400 | 2008 | $(8) |
| Six\tMonth\tLIBOR\t+2.142% | 6.125% $ | 200 | 2012 | $(10) |

# Foreign	Currency	Exchange	Rate	Risk

								We	manage	our	exposure	to	foreign	currency	exchange	rates	by	utilizing	forward	and	option	contracts.	The	primary	objective	of	this	program	is	to	reduce	our exposure	to	movements	in	the	foreign	currency	markets	by	locking	in	foreign	currency	rates.	At	December	31,	2006,	the	following	currency	derivatives	were outstanding.	All	contracts	currently	qualify	for	hedge	accounting.

|  | Period | Notional<br>Amount | Forward<br>Rate^(a) | Fair	Value^(b) |
| :--- | :--- | :--- | :--- | :--- |
| Foreign\tCurrency\tRate\tForwards: |  |  |  |  |
| Euro | July\t2007\t–\tNovember\t2008 | $51 | 1.255(c) | $3 |
| Kroner\t(Norway) | January\t2007\t–\tOctober\t2009 | $127 | 6.213(d) | $\t\t– |

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

(b) Fair	value	was	based	on	market	rates.

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

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

								The	aggregate	effect	on	foreign	currency	forward	contracts	of	a	hypothetical	10	percent	change	to	exchange	rates	at	December	31,	2006,	would	be	approximately $14	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.

# 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.

# Index	to	2006	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	Statements	of	Income

Consolidated	Balance	Sheets

Consolidated	Statements	of	Cash	Flows

Consolidated	Statements	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)

Supplemental	Statistics	(Unaudited)

# To	the	Stockholders	of	Marathon	Oil	Corporation:

								The	accompanying	consolidated	financial	statements	of	Marathon	Oil	Corporation	and	its	consolidated	subsidiaries	("Marathon")	are	the responsibility	of	management	and	have	been	prepared	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.	They necessarily	include	some	amounts	that	are	based	on	best	judgments	and	estimates.	The	financial	information	displayed	in	other	sections	of	this	Annual Report	on	Form	10-K	is	consistent	with	these	consolidated	financial	statements.

								Marathon	seeks	to	assure	the	objectivity	and	integrity	of	its	financial	records	by	careful	selection	of	its	managers,	by	organizational	arrangements that	provide	an	appropriate	division	of	responsibility	and	by	communications	programs	aimed	at	assuring	that	its	policies	and	methods	are	understood throughout	the	organization.

								The	Board	of	Directors	pursues	its	oversight	role	in	the	area	of	financial	reporting	and	internal	control	over	financial	reporting	through	its	Audit 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	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,	2006.

								Marathon's	management	assessment	of	the	effectiveness	of	Marathon's	internal	control	over	financial	reporting	as	of	December	31,	2006	has	been audited	by	PricewaterhouseCoopers	LLP,	an	independent	registered	public	accounting	firm,	as	stated	in	their	report	which	is	included	herein.

								We	have	completed	integrated	audits	of	Marathon	Oil	Corporation's	consolidated	financial	statements	and	of	its	internal	control	over	financial reporting	as	of	December	31,	2006,	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	consolidated	financial	statements	listed	in	the	accompanying	index	present	fairly,	in	all	material	respects,	the	financial	position	of Marathon	Oil	Corporation	and	its	subsidiaries	at	December	31,	2006	and	2005,	and	the	results	of	their	operations	and	their	cash	flows	for	each	of	the three	years	in	the	period	ended	December	31,	2006	in	conformity	with	accounting	principles	generally	accepted	in	the	United	States	of	America.	These financial	statements	are	the	responsibility	of	the	Company'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	consolidated	financial	statements,	the	Company	changed	its	methods	of	accounting	for	purchases	and	sales	of inventory	with	the	same	counterparty	and	defined	benefit	pension	and	other	postretirement	plans	in	2006	and	its	method	of	accounting	for	conditional asset	retirement	obligations	in	2005.

								Also,	in	our	opinion,	management's	assessment,	included	in	Management's	Report	on	Internal	Control	over	Financial	Reporting,	appearing	herein, that	the	Company	maintained	effective	internal	control	over	financial	reporting	as	of	December	31,	2006	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,	the	Company	maintained,	in	all	material	respects,	effective	internal	control	over financial	reporting	as	of	December	31,	2006,	based	on	criteria	established	in	Internal	Control	–	Integrated	Framework	issued	by	the	COSO.	The Company'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	Company'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 February	28,	2007

# (Dollars	in	millions	except	per	share	data)

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Revenues\tand\tother\tincome: |  |  |  |
| Sales\tand\tother\toperating\trevenues\t(including\tconsumer\texcise\ttaxes) | $57,973 | $48,948 | $39,172 |
| Revenues\tfrom\tmatching\tbuy/sell\ttransactions | 5,457 | 12,636 | 9,242 |
| Sales\tto\trelated\tparties | 1,466 | 1,402 | 1,051 |
| Income\tfrom\tequity\tmethod\tinvestments | 391 | 265 | 167 |
| Net\tgains\ton\tdisposal\tof\tassets | 77 | 57 | 36 |
| Gain\ton\townership\tchange\tin\tMarathon\tPetroleum\tCompany\tLLC | – | – | 2 |
| Other\tincome | 85 | 37 | 100 |
| Total\trevenues\tand\tother\tincome | 65,449 | 63,345 | 49,770 |
| Costs\tand\texpenses: |  |  |  |
| Cost\tof\trevenues\t(excludes\titems\tshown\tbelow) | 42,415 | 37,806 | 30,700 |
| Purchases\trelated\tto\tmatching\tbuy/sell\ttransactions | 5,396 | 12,364 | 9,050 |
| Purchases\tfrom\trelated\tparties | 210 | 225 | 202 |
| Consumer\texcise\ttaxes | 4,979 | 4,715 | 4,463 |
| Depreciation,\tdepletion\tand\tamortization | 1,518 | 1,303 | 1,178 |
| Selling,\tgeneral\tand\tadministrative\texpenses | 1,228 | 1,155 | 1,021 |
| Other\ttaxes | 371 | 318 | 282 |
| Exploration\texpenses | 365 | 217 | 158 |
| Total\tcosts\tand\texpenses | 56,482 | 58,103 | 47,054 |
| Income\tfrom\toperations | 8,967 | 5,242 | 2,716 |
| Net\tinterest\tand\tother\tfinancing\tcosts\t(income) | (37) | 146 | 162 |
| Loss\ton\tearly\textinguishment\tof\tdebt | 35 | – | – |
| Minority\tinterests\tin\tincome\t(loss)\tof: |  |  |  |
| Marathon\tPetroleum\tCompany\tLLC | – | 384 | 532 |
| Equatorial\tGuinea\tLNG\tHoldings\tLimited | (10) | (8) | (7) |
| Income\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | 8,979 | 4,720 | 2,029 |
| Provision\tfor\tincome\ttaxes | 4,022 | 1,714 | 735 |
| Income\tfrom\tcontinuing\toperations | 4,957 | 3,006 | 1,294 |
| Discontinued\toperations | 277 | 45 | (33) |
| Income\tbefore\tcumulative\teffect\tof\tchange\tin\taccounting\tprinciple | 5,234 | 3,051 | 1,261 |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | (19) | – |
| Net\tincome | $5,234 | $3,032 | $1,261 |
| Per\tShare\tData |  |  |  |
| Basic: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $13.85 | $8.44 | $3.85 |
| Net\tincome | $14.62 | $8.52 | $3.75 |
| Diluted: |  |  |  |
| Income\tfrom\tcontinuing\toperations | $13.73 | $8.37 | $3.83 |
| Net\tincome | $14.50 | $8.44 | $3.73 |

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

|  | December	31 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Assets |  |  |  |
| Current\tassets: |  |  |  |
| Cash\tand\tcash\tequivalents |  | $2,585 | $2,617 |
| Receivables,\tless\tallowance\tfor\tdoubtful\taccounts\tof\t$3\tand\t$3 |  | 4,114 | 3,476 |
| Receivables\tfrom\tUnited\tStates\tSteel |  | 32 | 20 |
| Receivables\tfrom\trelated\tparties |  | 63 | 38 |
| Inventories |  | 3,173 | 3,041 |
| Other\tcurrent\tassets |  | 129 | 191 |
| Total\tcurrent\tassets |  | 10,096 | 9,383 |
| Investments\tand\tlong-term\treceivables,\tless\tallowance\tfor\tdoubtful\taccounts\tof\t$9\tand\t$10 |  | 1,887 | 1,864 |
| Receivables\tfrom\tUnited\tStates\tSteel |  | 498 | 532 |
| Property,\tplant\tand\tequipment,\tnet |  | 16,653 | 15,011 |
| Goodwill |  | 1,398 | 1,307 |
| Intangible\tassets,\tnet |  | 180 | 200 |
| Other\tnoncurrent\tassets |  | 119 | 201 |
| Total\tassets |  | $30,831 | $28,498 |
| Liabilities |  |  |  |
| Current\tliabilities: |  |  |  |
| Accounts\tpayable |  | $5,586 | $5,353 |
| Consideration\tpayable\tunder\tLibya\tre-entry\tagreement |  | – | 732 |
| Payable\tto\tUnited\tStates\tSteel |  | 13 | – |
| Payables\tto\trelated\tparties |  | 264 | 82 |
| Payroll\tand\tbenefits\tpayable |  | 409 | 344 |
| Accrued\ttaxes |  | 598 | 782 |
| Deferred\tincome\ttaxes |  | 631 | 450 |
| Accrued\tinterest |  | 89 | 96 |
| Long-term\tdebt\tdue\twithin\tone\tyear |  | 471 | 315 |
| Total\tcurrent\tliabilities |  | 8,061 | 8,154 |
| Long-term\tdebt |  | 3,061 | 3,698 |
| Deferred\tincome\ttaxes |  | 1,897 | 2,030 |
| Defined\tbenefit\tpostretirement\tplan\tobligations |  | 1,245 | 1,251 |
| Asset\tretirement\tobligations |  | 1,044 | 711 |
| Payable\tto\tUnited\tStates\tSteel |  | 7 | 6 |
| Deferred\tcredits\tand\tother\tliabilities |  | 391 | 508 |
| Total\tliabilities |  | 15,706 | 16,358 |
| Minority\tinterests\tin\tEquatorial\tGuinea\tLNG\tHoldings\tLimited |  | 518 | 435 |
| Commitments\tand\tcontingencies |  |  |  |
| Stockholders'\tEquity |  |  |  |
| Common\tstock\tissued\t–\t367,851,558\tand\t366,925,852\tshares\t(par\tvalue\t$1\tper\tshare, |  |  |  |
| 550,000,000\tshares\tauthorized) |  | 368 | 367 |
| Common\tstock\theld\tin\ttreasury,\tat\tcost\t–\t20,080,670\tand\t179,977\tshares |  | (1,638) | (8) |
| Additional\tpaid-in\tcapital |  | 5,152 | 5,111 |
| Retained\tearnings |  | 11,093 | 6,406 |
| Accumulated\tother\tcomprehensive\tloss |  | (368) | (151) |
| Unearned\tcompensation |  | – | (20) |
| Total\tstockholders'\tequity |  | 14,607 | 11,705 |
| Total\tliabilities\tand\tstockholders'\tequity |  | $30,831 | $28,498 |

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Increase\t(decrease)\tin\tcash\tand\tcash\tequivalents |  |  |  |
| Operating\tactivities: |  |  |  |
| Net\tincome | $5,234 | $3,032 | $1,261 |
| Adjustments\tto\treconcile\tnet\tincome\tto\tnet\tcash\tprovided\tfrom\toperating\tactivities: |  |  |  |
| Loss\ton\tearly\textinguishment\tof\tdebt | 35 | – | – |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | 19 | – |
| Income\tfrom\tdiscontinued\toperations | (277) | (45) | 33 |
| Deferred\tincome\ttaxes | 268 | (205) | (62) |
| Minority\tinterests\tin\tincome\t(loss)\tof\tsubsidiaries | (10) | 376 | 525 |
| Depreciation,\tdepletion\tand\tamortization | 1,518 | 1,303 | 1,178 |
| Pension\tand\tother\tpostretirement\tbenefits,\tnet | (404) | 71 | 82 |
| Exploratory\tdry\twell\tcosts\tand\tunproved\tproperty\timpairments | 166 | 111 | 68 |
| Net\tgains\ton\tdisposal\tof\tassets | (77) | (57) | (36) |
| Equity\tmethod\tinvestments,\tnet | (200) | (65) | (15) |
|  | (454) | 386 | 99 |
| Changes\tin: |  |  |  |
| Current\treceivables | (535) | (1,164) | (691) |
| Inventories | (133) | (150) | (40) |
| Current\taccounts\tpayable\tand\taccrued\texpenses | 237 | 1,065 | 1,197 |
| All\tother,\tnet | 50 | (22) | 137 |
| Net\tcash\tprovided\tfrom\tcontinuing\toperations | 5,418 | 4,655 | 3,736 |
| Net\tcash\tprovided\tfrom\tdiscontinued\toperations | 70 | 83 | 30 |
| Net\tcash\tprovided\tfrom\toperating\tactivities | 5,488 | 4,738 | 3,766 |
| Investing\tactivities: |  |  |  |
| Capital\texpenditures | (3,433) | (2,796) | (2,141) |
| Acquisitions | (741) | (506) | – |
| Disposal\tof\tdiscontinued\toperations | 832 | – | – |
| Proceeds\tfrom\tsale\tof\tminority\tinterests\tin\tEquatorial\tGuinea\tLNG\tHoldings\tLimited | – | 163 | – |
| Disposal\tof\tassets | 134 | 131 | 76 |
| Restricted\tcash\t–\tdeposits | (19) | (54) | (42) |
| Restricted\tcash\t–\twithdrawals | 43 | 41 | 34 |
| Investments\t–\tloans\tand\tadvances | (17) | (28) | (160) |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\trepayments\tof\tloans\tand\tadvances | 298 | 15 | 15 |
| Investing\tactivities\tof\tdiscontinued\toperations | (45) | (94) | (106) |
| All\tother,\tnet | (7) | 1 | – |
| Net\tcash\tused\tin\tinvesting\tactivities | (2,955) | (3,127) | (2,324) |
| Financing\tactivities: |  |  |  |
| Payment\tof\tdebt\tassumed\tin\tacquisition | – | (1,920) | – |
| Debt\tissuance\tcosts | – | – | (4) |
| Other\tdebt\trepayments | (501) | (8) | (259) |
| Issuance\tof\tcommon\tstock | 50 | 78 | 1,043 |
| Purchases\tof\tcommon\tstock | (1,698) | – | – |
| Excess\ttax\tbenefits\tfrom\tstock-based\tcompensation\tarrangements | 35 | – | – |
| Dividends\tpaid | (547) | (436) | (348) |
| Contributions\tfrom\tminority\tshareholders\tof\tEquatorial\tGuinea\tLNG\tHoldings\tLimited | 80 | 213 | 95 |
| Distributions\tto\tminority\tshareholder\tof\tMarathon\tPetroleum\tCompany\tLLC | – | (272) | – |
| Net\tcash\tprovided\tfrom\t(used\tin)\tfinancing\tactivities | (2,581) | (2,345) | 527 |
| Effect\tof\texchange\trate\tchanges\ton\tcash | 16 | (18) | 4 |
| Net\tincrease\t(decrease)\tin\tcash\tand\tcash\tequivalents | (32) | (752) | 1,973 |
| Cash\tand\tcash\tequivalents\tat\tbeginning\tof\tyear | 2,617 | 3,369 | 1,396 |
| Cash\tand\tcash\tequivalents\tat\tend\tof\tyear | $2,585 | $2,617 | $3,369 |

|  | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Common\tstock\tissued |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $367 | $347 | $312 | 366,926 | 346,718 | 312,166 |
| (a)\nIssuances | 1 | 20 | 35 | 926 | 20,208 | 34,552 |
| Balance\tat\tend\tof\tyear | $368 | $367 | $347 | 367,852 | 366,926 | 346,718 |
| Common\tstock\theld\tin\ttreasury,\tat\tcost |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $(8) | $(1) | $(46) | (180) | (35) | (1,744) |
| Repurchases | (1,698) | (7) | (4) | (20,745) | (10) | (129) |
| Reissuances\tfor\temployee\tstock\tplans | 68 | – | 49 | 844 | (135) | 1,838 |
| Balance\tat\tend\tof\tyear | $(1,638) | $(8) | $(1) | (20,081) | (180) | (35) |
|  |  |  |  |  | Comprehensive\tIncome |  |
|  |  |  |  | 2006 | 2005 | 2004 |
| Additional\tpaid-in\tcapital |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $5,111 | $4,028 | $3,033 |  |  |  |
| (a) |  |  |  |  |  |  |
| Stock\tissuances | (7) | 1,048 | 983 |  |  |  |
| Stock-based\tcompensation\texpense | 48 | 35 | 12 |  |  |  |
| Balance\tat\tend\tof\tyear | $5,152 | $5,111 | $4,028 |  |  |  |
| Unearned\tcompensation |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $(20) | $(9) | $(9) |  |  |  |
| Change\tin\taccounting\tprinciple | 20 | – | – |  |  |  |
| Changes\tduring\tyear | – | (11) | – |  |  |  |
| Balance\tat\tend\tof\tyear | $– | $(20) | $(9) |  |  |  |
| Retained\tearnings |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $6,406 | $3,810 | $2,897 |  |  |  |
| Net\tincome | 5,234 | 3,032 | 1,261 | $5,234 | $3,032 | $1,261 |
| $1.03\tin\t2004) | (547) | (436) | (348) |  |  |  |
| Balance\tat\tend\tof\tyear | $11,093 | $6,406 | $3,810 |  |  |  |
| Accumulated\tother\tcomprehensive\tloss |  |  |  |  |  |  |
| Minimum\tpension\tliability\tadjustments: |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $(141) | $(71) | $(93) |  |  |  |
| Changes\tduring\tyear,\tnet\tof\ttax\tof\t$74,\t$42\tand\t$3 | 114 | (70) | 22 | 114 | (70) | 22 |
| Reclassification\tto\tdefined\tbenefit\tpostretirement\tplans | 27 | – | – |  |  |  |
| Balance\tat\tend\tof\tyear | $– | $(141) | $(71) |  |  |  |
| Defined\tbenefit\tpostretirement\tplans: |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $– | $– | $– |  |  |  |
| Reclassification\tfrom\tminimum\tpension\tliability |  |  |  |  |  |  |
| adjustments | (27) | – | – |  |  |  |
| Change\tin\taccounting\tprinciple,\tnet\tof\ttax\tof\t$289 | (348) | – | – |  |  |  |
| Balance\tat\tend\tof\tyear | $(375) | $– | $– |  |  |  |
| Deferred\tgains\t(losses)\ton\tderivative\tinstruments: |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $(5) | $12 | $(15) |  |  |  |
| Reclassification\tof\tthe\tcumulative\teffect\tadjustment\tinto |  |  |  |  |  |  |
| net\tincome,\tnet\tof\ttax\tof\t$–,\t$–\tand\t$1 | (2) | (2) | (3) | (2) | (2) | (3) |
| Changes\tin\tfair\tvalue,\tnet\tof\ttax\tof\t$1,\t$3\tand\t$20 | 4 | (15) | (82) | 4 | (15) | (82) |
| Reclassification\tto\tnet\tincome,\tnet\tof\ttax\tof\t$–,\t$–\tand |  |  |  |  |  |  |
| $30 | 1 | – | 112 | 1 | – | 112 |
| Balance\tat\tend\tof\tyear | $(2) | $(5) | $12 |  |  |  |
| Other: |  |  |  |  |  |  |
| Balance\tat\tbeginning\tof\tyear | $(5) | $(5) | $(4) |  |  |  |
| Changes\tduring\tyear,\tnet\tof\ttax\tof\t$8,\t$–\tand\t$– | 14 | – | (1) | 9 | – | (1) |
| Balance\tat\tend\tof\tyear | $9 | $(5) | $(5) |  |  |  |
| Total\tat\tend\tof\tyear | $(368) | $(151) | $(64) |  |  |  |
| Comprehensive\tincome |  |  |  | $5,360 | $2,945 | $1,309 |

(a) 	On	March	31,	2004,	Marathon	issued	34,500,000	shares	of	its	common	stock	at	the	offering	price	of	$30	per	share	and	recorded	net	proceeds	of	$1.004	billion.	On June	30,	2005,	in	connection	with	the	acquisition	of	Ashland	Inc.'s	minority	interest	in	Marathon	Petroleum	Company	LLC,	Marathon	distributed	17,538,815	shares	of its	common	stock	valued	at	$54.45	per	share	to	Ashland's	shareholders.

# 1.	Summary	of	Principal	Accounting	Policies

Marathon	Oil	Corporation	("Marathon"	or	the	"Company")	is	engaged	in	worldwide	exploration,	production	and	marketing	of	crude	oil	and	natural	gas;	domestic refining,	marketing	and	transportation	of	crude	oil	and	petroleum	products;	and	worldwide	marketing	and	transportation	of	products	manufactured	from	natural	gas,	such as	liquefied	natural	gas	("LNG")	and	methanol,	and	development	of	other	projects	to	link	stranded	natural	gas	resources	with	key	demand	areas.

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

								Prior	to	June	30,	2005,	Marathon	owned	a	62	percent	interest	in	Marathon	Petroleum	Company	LLC	("MPC").	After	Marathon	acquired	the	remaining	38	percent interest	as	described	in	Note	6,	MPC	became	a	wholly	owned	subsidiary	of	Marathon.	The	accounts	of	MPC	are	consolidated	in	these	financial	statements	for	all	periods presented	and	the	applicable	minority	interest	has	been	recognized	for	activity	prior	to	the	acquisition	date.

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

								Investments	in	variable	interest	entities	("VIEs")	for	which	Marathon	is	the	primary	beneficiary	are	consolidated.

								Investments	in	entities	over	which	Marathon	has	significant	influence,	but	not	control,	are	accounted	for	using	the	equity	method	of	accounting	and	are	carried	at Marathon's	share	of	net	assets	plus	loans	and	advances.	This	includes	entities	in	which	Marathon	holds	majority	ownership	but	the	minority	shareholders	have substantive	participating	rights	in	the	investee.	Differences	in	the	basis	of	the	investments	and	the	separate	net	asset	values	of	the	investees,	if	any,	are	amortized	into	net income	over	the	remaining	useful	lives	of	the	underlying	assets,	except	for	the	excess	related	to	goodwill.	Income	from	equity	method	investments	represents	Marathon's proportionate	share	of	net	income	generated	by	the	equity	method	investees.

								Gains	or	losses	from	a	change	in	ownership	of	a	consolidated	subsidiary	or	an	unconsolidated	investee	are	recognized	in	net	income	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	and	the	disclosure	of	contingent	assets	and	liabilities	as	of	the	date	of	the	consolidated	financial statements	and	the	reported	amounts	of	revenues	and	expenses	during	the	respective	reporting	periods.

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

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

•Exploration	and	Production	("E&P")	–	explores	for,	produces	and	markets	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;	and

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

								Management	has	determined	that	these	are	its	operating	segments	because	these	are	the	components	of	Marathon	(1)	that	engage	in	business	activities	from	which revenues	are	earned	and	expenses	are	incurred,	(2)	whose	operating	results	are	regularly	reviewed	by	Marathon's	chief	operating	decision	maker	("CODM")	to	make decisions	about	resources	to	be	allocated	and	to	assess	performance	and	(3)	for	which	discrete	financial	information	is	available.	The	CODM	is	responsible	for	allocating resources	to	and	assessing	performance	of	Marathon's	operating	segments.	Information	regarding	assets	by	segment	is	not	presented	because	it	is	not	reviewed	by	the CODM.	The	CODM	is	the	manager	over	the	E&P	and	IG	segments	and	the	manager	of	the	RM&T	segment	reports	to	the	CODM.	The	segment	managers	are responsible	for	allocating	resources	within	the	segments,	reviewing	financial	results	of	components	within	the	segments	and	assessing	the	performance	of	the components.	The	components	within	the	segments	that	are	separately	reviewed	and	assessed	by	the	CODM	in	his	role	as	segment	manager	are	aggregable	because	they have	similar	economic	characteristics.	The	CODM	reviews	the	financial	results	of	the	RM&T	segment	at	the	segment	level.

								Segment	income	represents	income	from	continuing	operations,	net	of	minority	interests	and	income	taxes,	attributable	to	the	operating	segments.	Marathon's corporate	general	and	administrative	costs	are	not	allocated	to	the	operating	segments.	These	costs	primarily	consist	of	employment	costs	(including	pension	effects), professional	services,	facilities	and	other	costs	associated	with	corporate	activities.	Non-cash	gains	and	losses	on	two	long-term	natural	gas	sales	contracts	in	the	United Kingdom	accounted	for	as	derivative	instruments,	gains	and	losses	on	ownership	changes	in	subsidiaries	and	certain	non-operating	or	infrequently	occurring	items	(as determined	by	the	CODM)	also	are	not	allocated	to	operating	segments.	See	the	reconciliation	of	segment	income	to	consolidated	net	income	in	Note	9.

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

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

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

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

Matching	buy/sell	transactions		–		In	a	typical	matching	buy/sell	transaction,	Marathon	enters	into	a	contract	to	sell	a	particular	quantity	and	quality	of	crude	oil	or refined	product	at	a	specified	location	and	date	to	a	particular	counterparty,	and	simultaneously	agrees	to	buy	a	particular	quantity	and	quality	of	the	same	commodity	at a	specified	location	on	the	same	or	another	specified	date	from	the	same	counterparty.	The	value	of	the	purchased	volumes	rarely	equals	the	sales	value	of	the	sold volumes.	The	value	differences	between	purchases	and	sales	are	primarily	due	to	(1)	grade/quality	differentials,	(2)	location	differentials	and/or	(3)	timing	differences	in those	instances	when	the	purchase	and	sale	do	not	occur	in	the	same	month.

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

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

								A	portion	of	Marathon's	matching	buy/sell	transactions	are	"nontraditional	derivative	instruments,"	which	are	described	below.	Effective	for	contracts	entered	into or	modified	on	or	after	April	1,	2006,	the	income	effects	of	matching	buy/sell	arrangements	accounted	for	as	nontraditional	derivative	instruments	are	recognized	on	a net	basis	as	cost	of	revenues.

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

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

Cash	and	cash	equivalents		–		Cash	and	cash	equivalents	include	cash	on	hand	and	on	deposit	and	investments	in	highly	liquid	debt	instruments	with	maturities generally	of	three	months	or	less.

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

Inventories		–		Inventories	are	carried	at	the	lower	of	cost	or	market	value.	Cost	of	inventories	is	determined	primarily	under	the	last-in,	first-out	("LIFO")	method.	An 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	non-cash	charges	or	credits	to	costs	and	expenses.

Traditional	derivative	instruments		–		Marathon	uses	derivatives	to	manage	its	exposure	to	commodity	price	risk,	interest	rate	risk	and	foreign	currency risk.				Management	has	authorized	the	use	of	futures,	forwards,	swaps	and	combinations	of	options,	including	written	or	net	written	options,	related	to	the	purchase, production	or	sale	of	crude	oil,	natural	gas,	refined	products	and	ethanol,	the	fair	value	of	certain	assets	and	liabilities,	future	interest	expense	and	certain	business transactions	denominated	in	foreign	currencies.	Changes	in	the	fair	values	of	all	traditional	derivatives	are	recognized	immediately	in	net	income	unless	the	derivative qualifies	as	a	hedge	of	future	cash	flows	or	certain	foreign	currency	exposures.	Cash	flows	related	to	derivatives	used	to	manage	commodity	price	risk,	interest	rate	risk and	foreign	currency	exchange	rate	risk	related	to	operating	expenditures	are	classified	in	operating	activities	with	the	underlying	hedged	transactions.	Cash	flows related	to	derivatives	used	to	manage	exchange	rate	risk	related	to	capital	expenditures	denominated	in	foreign	currencies	are	classified	in	investing	activities	with	the underlying	hedged	transactions.

								For	derivatives	qualifying	as	hedges	of	future	cash	flows	or	certain	foreign	currency	exposures,	the	effective	portion	of	any	changes	in	fair	value	is	recognized	in other	comprehensive	income	and	is	reclassified	to	net	income	when	the

underlying	forecasted	transaction	is	recognized	in	net	income.	Any	ineffective	portion	of	such	hedges	is	recognized	in	net	income	as	it	occurs.	For	discontinued	cash flow	hedges,	prospective	changes	in	the	fair	value	of	the	derivative	are	recognized	in	net	income.	The	accumulated	gain	or	loss	recognized	in	other	comprehensive income	at	the	time	a	hedge	is	discontinued	continues	to	be	deferred	until	the	original	forecasted	transaction	occurs.	However,	if	it	is	determined	that	the	likelihood	of	the original	forecasted	transaction	occurring	is	no	longer	probable,	the	entire	accumulated	gain	or	loss	recognized	in	other	comprehensive	income	is	immediately	reclassified into	net	income.

								For	derivatives	designated	as	hedges	of	the	fair	value	of	recognized	assets,	liabilities	or	firm	commitments,	changes	in	the	fair	values	of	both	the	hedged	item	and the	related	derivative	are	recognized	immediately	in	net	income	with	an	offsetting	effect	included	in	the	basis	of	the	hedged	item.	The	net	effect	is	to	report	in	net	income the	extent	to	which	the	hedge	is	not	effective	in	achieving	offsetting	changes	in	fair	value.

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

								As	market	conditions	change,	Marathon	may	use	selective	derivative	instruments	that	assume	market	risk.	For	derivative	instruments	that	are	classified	as	trading, changes	in	fair	value	are	recognized	immediately	in	net	income	and	are	classified	as	other	income.	Any	premium	received	is	amortized	into	net	income	based	on	the underlying	settlement	terms	of	the	derivative	position.	All	related	effects	of	a	trading	strategy,	including	physical	settlement	of	the	derivative	position,	are	also recognized	in	net	income	and	classified	as	other	income.

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

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

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

Investment	in	marketable	securities		–		Management	determines	the	appropriate	classification	of	investments	in	marketable	debt	and	equity	securities	at	the	time	of acquisition	and	re-evaluates	such	designation	as	of	each	subsequent	balance	sheet	date.	Securities	classified	as	"available	for	sale"	are	carried	at	estimated	fair	value	with unrealized	gains	and	losses,	net	of	tax,	recorded	as	a	component	of	accumulated	other	comprehensive	loss.	Marathon	holds	no	securities	classified	as	"held	to	maturity securities"	or	"trading	securities."	Realized	and	unrealized	gains	and	losses	are	calculated	using	the	specific	identification	method.

Property,	plant	and	equipment		–		Marathon	uses	the	successful	efforts	method	of	accounting	for	oil	and	gas	producing	activities.	Costs	to	acquire	mineral	interests	in oil	and	natural	gas	properties,	to	drill	and	equip	exploratory	wells	that	find	proved	reserves	and	to	drill	and	equip	development	wells	are	capitalized.	Costs	to	drill exploratory	wells	that	do	not	find	proved	reserves,	geological	and	geophysical	costs	and	costs	of	carrying	and	retaining	unproved	properties	are	expensed.	Costs	incurred for	exploratory	wells	that	find	reserves	that	cannot	yet	be	classified	as	proved	are	capitalized	if	(1)	the	well	has	found	a	sufficient	quantity	of	reserves	to	justify	its completion	as	a	producing	well	and	(2)	Marathon	is	making	sufficient	progress	assessing	the	reserves	and	the	economic	and	operating	viability	of	the	project.	The	status of	suspended	well	costs	is	monitored	continuously	and	reviewed	not	less	than	quarterly.

								Capitalized	costs	of	producing	oil	and	natural	gas	properties	are	depreciated	and	depleted	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	the	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	and	impairs	based	on	time	or	geologic	factors	in	addition	to	the	use	of	an	undiscounted	future	net	cash	flow approach.	Information	such	as	drilling	results,	reservoir	performance,	seismic	interpretation	or	future	plans	to	develop	acreage	are	also	considered.	Unproved	property investments	deemed	to	be	impaired	are	written	down	to	their	fair	value,	as	determined	by	discounted	future	net	cash	flows.	Impairment	expense	for	unproved	oil	and natural	gas	properties	is	reported	in	exploration	expenses.

								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.	Such	assets	are	reviewed	for	impairment	whenever	events	or	changes	in	circumstances	indicate	that	the	carrying amount	of	an	asset	may	not	be	recoverable.	If	the	sum	of	the	expected	future	cash	flows	from	the	use	of	the	asset	and	its	eventual	disposition	is	less	than	the	carrying amount	of	the	asset,	an	impairment	loss	is	recognized	based	on	the	fair	value	of	the	asset.

								When	property,	plant	and	equipment	depreciated	on	an	individual	basis	are	sold	or	otherwise	disposed	of,	any	gains	or	losses	are	reported	in	net	income.	Gains	on disposal	of	property,	plant	and	equipment	are	recognized	when	earned,	which	is	generally	at	the	time	of	closing.	If	a	loss	on	disposal	is	expected,	such	losses	are recognized	when	the	assets	are	classified	as	held	for	sale.	Proceeds	from	disposal	of	property,	plant	and	equipment	depreciated	on	a	group	basis	are	credited	to accumulated	depreciation,	depletion	and	amortization	with	no	immediate	effect	on	net	income.

Goodwill		–		Goodwill	represents	the	excess	of	the	purchase	price	over	the	estimated	fair	value	of	the	net	assets	acquired	in	the	acquisition	of	a	business.	Such	goodwill	is not	amortized,	but	rather	is	tested	for	impairment	annually	and	when	events	or	changes	in	circumstances	indicate	that	the	fair	value	of	a	reporting	unit	with	goodwill	has been	reduced	below	carrying	value.	The	impairment	test	requires	allocating	goodwill	and	other	assets	and	liabilities	to	reporting	units.	Marathon	has	determined	the components	of	the	E&P	segment	have	similar	economic	characteristics	and	therefore	aggregates	the	components	into	a	single	reporting	unit.	The	RM&T	segment	is composed	of	three	reporting	units:	refining	and	marketing,	pipeline	transportation	and	retail	marketing.	The	fair	value	of	each	reporting	unit	is	determined	and	compared to	the	book	value	of	the	reporting	unit.	If	the	fair	value	of	the	reporting	unit	is	less	than	the	book	value,	including	goodwill,	then	the	recorded	goodwill	is	impaired	to	its implied	fair	value	with	a	charge	to	expense.

Intangible	assets		–		Intangible	assets	primarily	include	retail	marketing	tradenames,	intangible	contract	rights	and	marketing	branding	agreements.	Certain	of	the marketing	tradenames	have	indefinite	lives	and	therefore	are	not	amortized,	but	rather	are	tested	for	impairment	annually	and	when	events	or	changes	in	circumstances indicate	that	the	fair	value	of	the	intangible	asset	has	been	reduced	below	carrying	value.	The	other	intangible	assets	are	amortized	over	their	estimated	useful	lives	or	the expected	lives	of	the	related	contracts,	as	applicable,	which	range	from	2	to	22	years.	Such	assets	are	reviewed	for	impairment	whenever	events	or	changes	in circumstances	indicate	that	the	carrying	amount	of	an	asset	may	not	be	recoverable.	If	the	sum	of	the	expected	future	cash	flows	from	the	use	of	the	asset	and	its eventual	disposition	is	less	than	the	carrying	amount	of	the	asset,	an	impairment	loss	is	recognized	based	on	the	fair	value	of	the	asset.

Environmental	costs		–		Environmental	expenditures	are	capitalized	if	the	costs	mitigate	or	prevent	future	contamination	or	if	the	costs	improve	environmental	safety	or efficiency	of	the	existing	assets.	Marathon	provides	for	remediation	costs	and	penalties	when	the	responsibility	to	remediate	is	probable	and	the	amount	of	associated costs	can	be	reasonably	estimated.	The	timing	of	remediation	accruals	coincides	with	completion	of	a	feasibility	study	or	the	commitment	to	a	formal	plan	of	action. Remediation	liabilities	are	accrued	based	on	estimates	of	known	environmental	exposure	and	are	discounted	when	the	estimated	amounts	are	reasonably	fixed	and determinable.	If	recoveries	of	remediation	costs	from	third	parties	are	probable,	a	receivable	is	recorded	and	is	discounted	when	the	estimated	amount	is	reasonably fixed	and	determinable.

Asset	retirement	obligations		–		The	fair	values	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	for such	facilities	include	costs	to	dismantle	and	relocate	or	dispose	of	production	platforms,	gathering	systems,	wells	and	related	structures	and	restoration	costs	of	land	and seabed,	including	those	leased.	Estimates	of	these	costs	are	developed	for	each	property	based	on	the	type	of	production	structure,	depth	of	water,	reservoir characteristics,	depth	of	the	reservoir,	market	demand	for	equipment,	currently	available	procedures	and	consultations	with	construction	and	engineering	professionals. Asset	retirement	obligations	have	not	been	recognized	for	certain	of	Marathon's	international	oil	and	gas	producing	facilities	as	Marathon	currently	does	not	have	a	legal obligation	associated	with	the	retirement	of	those	facilities.

								Effective	December	31,	2005,	conditional	asset	retirement	obligations	for	removal	and	disposal	of	fire-retardant	material	from	certain	refining	facilities	have	been recognized.	The	amounts	recorded	for	such	obligations	are	based	on	the	most	probable	current	cost	projections.	Asset	retirement	obligations	have	not	been	recognized for	the	removal	of	materials	and	equipment	from	or	the	closure	of	certain	refinery,	pipeline	and	marketing	assets	because	the	fair	value	cannot	be	reasonably	estimated due	to	an	indeterminate	settlement	date	of	the	obligation.

								Current	inflation	rates	and	credit-adjusted-risk-free	interest	rates	are	used	to	estimate	the	fair	values	of	asset	retirement	obligations.	Depreciation	of	capitalized	asset retirement	costs	and	accretion	of	asset	retirement	obligations	are	recorded	over	time.	Depreciation	is	generally	determined	on	a	units-of-production	basis	for	oil	and	gas production	facilities	and	on	a	straight-line	basis	for	refining	facilities,	while	accretion	escalates	over	the	lives	of	the	assets.

Deferred	taxes		–		Deferred	tax	assets	and	liabilities	are	recognized	for	the	estimated	future	tax	consequences	attributable	to	differences	between	the	financial	statement carrying	amounts	of	assets	and	liabilities	and	their	tax	bases	as	reported	in	Marathon's	filings	with	the	respective	taxing	authorities.	The	realization	of	deferred	tax	assets is	assessed	periodically	based	on	several	interrelated	factors.	These	factors	include	Marathon's	expectation	to	generate	sufficient	future	taxable	income	including	future foreign	source	income,	tax	credits,	operating	loss	carryforwards	and	management's	intent	regarding	the	permanent	reinvestment	of	the	income	from	certain	foreign subsidiaries.

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

Stock-based	compensation	arrangements		–		Marathon	adopted	Statement	of	Financial	Accounting	Standards	("SFAS")	No.	123(R),	"Share-Based	Payment,"	as	a revision	of	SFAS	No.	123,	"Accounting	for	Stock-Based	Compensation,"	as	of	January	1,	2006.	Marathon	had	previously	adopted	the	fair	value	method	under	SFAS No.	123	for	grants	made,	modified	or	settled	on	or	after	January	1,	2003.

								The	fair	value	of	stock	options,	stock	options	with	tandem	stock	appreciation	rights	("SARs")	and	stock-settled	SARs	("stock	option	awards")	is	estimated	on	the date	of	grant	using	the	Black-Scholes	option	pricing	model.	The	model	employs	various	assumptions,	based	on	management's	best	estimates	at	the	time	of	grant,	which impact	the	fair	value	calculated	and	ultimately,	the	expense	that	is	recognized	over	the	life	of	the	stock	option	award.	Of	the	required	assumptions,	the	expected	life	of the	stock	option	award	and	the	expected	volatility	of	Marathon's	stock	price	have	the	most	significant	impact	on	the	fair	value	calculation.	Marathon	has	utilized historical	data	and	analyzed	current	information	which	reasonably	support	these	assumptions.

								The	fair	value	of	Marathon's	restricted	stock	awards	and	common	stock	units	is	determined	based	on	the	fair	market	value	of	the	Company's	common	stock	on	the date	of	grant.	Prior	to	adoption	of	SFAS	No.	123	(Revised	2004),	"Share-Based	Payment,"	("SFAS	No.	123(R)")	on	January	1,	2006,	the	fair	values	of	Marathon's	stock- based	performance	awards	were	determined	in	the	same	manner	as	restricted	stock	awards.	Under	SFAS	No.	123(R),	on	a	prospective	basis,	these	awards	are	required	to be	valued	utilizing	an	option	pricing	model.	See	Note	2	for	further	information	regarding	Marathon's	adoption	of	SFAS	No.	123(R).	No	stock-based	performance	awards have	been	granted	since	May	2004.

								Effective	January	1,	2006,	Marathon's	stock-based	compensation	expense	is	recognized	based	on	management's	best	estimate	of	the	awards	that	are	expected	to vest,	using	the	straight-line	attribution	method	for	all	service-based	awards	with	a	graded	vesting	feature.	If	actual	forfeiture	results	are	different	than	expected, adjustments	to	recognized	compensation	expense	may	be	required	in	future	periods.	Unearned	stock-based	compensation	is	charged	to	stockholders'	equity	when restricted	stock	awards	and	stock-based	performance	awards	are	granted.	Compensation	expense	is	recognized	over	the	balance	of	the	vesting	period	and	is	adjusted	if conditions	of	the	restricted	stock	award	or	stock-based	performance	award	are	not	met.	Options	with	tandem	SARs	are	classified	as	a	liability	and	are	remeasured	at	fair value	each	reporting	period	until	settlement.

								Prior	to	January	1,	2006,	Marathon	recorded	stock-based	compensation	expense	over	the	stated	vesting	period	for	stock	option	awards	that	are	subject	to	specific vesting	conditions	and	specify	(1)	that	an	employee	vests	in	the	award	upon	becoming	"retirement	eligible"	or	(2)	that	the	employee	will	continue	to	vest	in	the	award after	retirement	without	providing	any	additional	service.	Under	SFAS	No.	123(R),	from	the	January	1,	2006	date	of	adoption,	such	compensation	cost	is	recognized immediately	for	awards	granted	to	retirement-eligible	employees	or	over	the	period	from	the	grant	date	to	the	retirement	eligibility	date	if	retirement	eligibility	will	be reached	during	the	stated	vesting	period.	See	Note	26	for	more	information	on	stock-based	compensation	expense,	stock	option	award,	stock-based	performance	award and	restricted	stock	award	activity,	valuation	assumptions	and	other	information	required	to	be	disclosed	under	SFAS	No.	123(R).

Concentrations	of	credit	risk		–		Marathon	is	exposed	to	credit	risk	in	the	event	of	nonpayment	by	counterparties,	a	significant	portion	of	which	are	concentrated	in energy-related	industries.	The	creditworthiness	of	customers	and	other	counterparties	is	subject	to	continuing	review,	including	the	use	of	master	netting	agreements, where	appropriate.	While	no	single	customer	accounts	for	more	than	10	percent	of	annual	revenues,	Marathon	has	significant	exposures	to	United	States	Steel	arising from	the	transaction	discussed	in	Note	3.

Reclassifications		–		Certain	reclassifications	of	prior	years'	data	have	been	made	to	conform	to	2006	classifications.

# 2.	New	Accounting	Standards

SFAS	No.	158		–		In	September	2006,	the	Financial	Accounting	Standards	Board	("FASB")	issued	SFAS	No.	158,	"Employers'	Accounting	for	Defined	Benefit	Pension and	Other	Postretirement	Plans	–	An	Amendment	of	FASB	Statements	No.	87,	88,	106,	and	132(R)."	This	standard	requires	an	employer	to:	(1)	recognize	in	its statement	of	financial	position	an	asset	for	a	plan's	overfunded	status	or	a	liability	for	a	plan's	underfunded	status;	(2)	measure	a	plan's	assets	and	its	obligations	that determine	its	funded	status	as	of	the	end	of	the	employer's	fiscal	year	(with	limited	exceptions);	and	(3)	recognize	changes	in	the	funded	status	of	a	plan	in	the	year	in which	the	changes	occur	through	comprehensive	income.	The	funded	status	of	a	plan	is	measured	as	the	difference	between	plan	assets	at	fair	value	and	the	benefit obligation.	For	a	pension	plan,	the	benefit	obligation	is	the	projected	benefit	obligation	and	for	any	other	postretirement	plan	it	is	the	accumulated	postretirement	benefit obligation.	Marathon	adopted	SFAS	No.	158	prospectively	as	of	December	31,	2006	and	has	recognized	the	funded	status	of	its	plans	in	the	consolidated	balance	sheet as	of	that	date.	The	adoption	of	SFAS	No.	158	had	no	impact	on	Marathon's	measurement	date	as	the	Company	has	historically	measured	the	plan	assets	and	benefit obligations	of	its	pension	and	other	postretirement	plans	as	of	December	31.	See	Note	24	for	additional	disclosures	regarding	pensions	and	other	postretirement	plans required	by	SFAS	No.	158.

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

| (In	millions) | Before	Application	of<br>SFAS	No.	158 | Adjustments | After	Application	of<br>SFAS	No.	158 |
| :--- | :--- | :--- | :--- |
| Prepaid\tpensions | $229 | $(229) | $– |
| Investments\tand\tlong-term\treceivables | 1,893 | (6) | 1,887 |
| Total\tassets | 31,066 | (235) | 30,831 |
| Payroll\tand\tbenefits\tpayable | 384 | 25 | 409 |
| Defined\tbenefit\tpostretirement\tplan\tobligations | 870 | 375 | 1,245 |
| Long-term\tdeferred\tincome\ttaxes | 2,183 | (286) | 1,897 |
| Deferred\tcredits\tand\tother\tliabilities | 397 | (6) | 391 |
| Total\tliabilities | 15,598 | 108 | 15,706 |
| Accumulated\tother\tcomprehensive\tloss | (25) | (343) | (368) |
| Total\tstockholders'\tequity | $14,950 | $(343) | $14,607 |

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

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

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

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

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

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

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

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

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

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

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

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

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

								The	pro	forma	net	income	and	net	income	per	share	effect	as	if	FIN	No.	47	had	been	applied	during	2005	and	2004	is	not	significantly	different	than	amounts reported.	The	following	summarizes	the	total	amount	of	the	liability	for	asset	retirement	obligations	as	if	FIN	No.	47	had	been	applied	during	all	periods	presented.	The pro	forma	impact	of	the	adoption	of	FIN	No.	47	on	these	unaudited	pro	forma	liability	amounts	has	been	measured	using	the	information,	assumptions	and	interest	rates used	to	measure	the	obligation	recognized	upon	adoption	of	FIN	No.	47.

| December	31,	2003 | $438 |
| :--- | :--- |
| December\t31,\t2004 | 527 |
| December\t31,\t2005 | 711 |

SFAS	No.	153		–		Marathon	adopted	SFAS	No.	153,	"Exchanges	of	Nonmonetary	Assets	–	an	amendment	of	APB	Opinion	No.	29,"	on	a	prospective	basis	as	of	July	1, 2005.	This	amendment	eliminates	the	APB	Opinion	No.	29	exception	for	fair	value	recognition	of	nonmonetary	exchanges	of	similar	productive	assets	and	replaces	it with	an	exception	for	exchanges	of	nonmonetary	assets	that	do	not	have	commercial	substance.

FSP	No.	FAS	19-1		–		Effective	January	1,	2005,	Marathon	adopted	FSP	No.	FAS	19-1,	"Accounting	for	Suspended	Well	Costs,"	which	amended	the	guidance	for suspended	exploratory	well	costs	in	SFAS	No.	19,	"Financial	Accounting	and	Reporting	by	Oil	and	Gas	Producing	Companies."	SFAS	No.	19	requires	costs	of	drilling exploratory	wells	to	be	capitalized	pending	determination	of	whether	the	well	has	found	proved	reserves.	When	a	classification	of	proved

reserves	cannot	yet	be	made,	FSP	No.	FAS	19-1	allows	exploratory	well	costs	to	continue	to	be	capitalized	when	(1)	the	well	has	found	a	sufficient	quantity	of	reserves to	justify	completion	as	a	producing	well	and	(2)	the	enterprise	is	making	sufficient	progress	assessing	the	reserves	and	the	economic	and	operating	viability	of	the project.	Marathon's	accounting	policy	for	suspended	exploratory	well	costs	was	in	accordance	with	FSP	No.	FAS	19-1	prior	to	its	adoption.	FSP	No.	FAS	19-1	also requires	certain	disclosures	to	be	made	regarding	capitalized	exploratory	well	costs	which	are	included	in	Note	15.

FSP	No.	FAS	109-1		–		Effective	December	21,	2004,	Marathon	adopted	FSP	No.	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	No.	FAS	109-1	states	the	deduction,	signed	into	law on	October	22,	2004,	of	up	to	9	percent	(when	fully	phased-in)	of	the	lesser	of	(1)	"qualified	production	activities	income,"	as	defined	in	the	Act,	or	(2)	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	SFAS	No.	109. Accordingly,	Marathon	treats	the	deduction	related	to	production	activities	income	as	a	special	deduction	in	the	years	taken.

FSP	No.	FAS	106-2		–		Effective	July	1,	2004,	Marathon	adopted	FSP	No.	FAS	106-2,	"Accounting	and	Disclosure	Requirements	Related	to	the	Medicare	Prescription Drug,	Improvement	and	Modernization	Act	of	2003."	FSP	No.	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	postretirement	benefit	plans	was	$93	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	was	$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,	which	was	intended	to reflect	the	performance	of	Marathon's	energy	business,	and	USX	–	U.S.	Steel	Group	common	stock	("Steel	Stock"),	which	was	intended	to	reflect	the	performance	of Marathon's	steel	business.	On	December	31,	2001,	in	a	tax-free	distribution	to	holders	of	Steel	Stock,	Marathon	exchanged	the	common	stock	of	United	States	Steel	for all	outstanding	shares	of	Steel	Stock	on	a	one-for-one	basis	(the	"Separation").	In	connection	with	the	Separation,	Marathon	and	United	States	Steel	entered	into	a number	of	agreements,	including:

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

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

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

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

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

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

								In	2006	and	2005,	in	accordance	with	the	terms	of	the	Tax	Sharing	Agreement,	Marathon	paid	$35	million	and	$6	million	to	United	States	Steel	in	connection	with the	settlement	with	the	Internal	Revenue	Service	of	the	consolidated	federal	income	tax	returns	of	USX	Corporation	for	the	years	1995	through	2001.	The	final	payment of	$13	million	to	United	States	Steel	related	to	U.S.	federal	tax	returns	under	the	Tax	Sharing	Agreement	was	made	in	January	2007.

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	from	United	States	Steel	and	the	obligation	are	reduced.

								At	December	31,	2006	and	2005,	amounts	receivable	from	or	payable	to	United	States	Steel	included	in	the	consolidated	balance	sheets	were	as	follows:

| (In	millions)																																																																																																																																	December	31 | 2006 | 2005 |
| :--- | :--- | :--- |
| Receivables\trelated\tto\tdebt\tand\tother\tobligations\tfor\twhich\tUnited\tStates\tSteel |  |  |
| has\tassumed\tresponsibility\tfor\trepayment: |  |  |
| Current | $32 | $20 |
| Noncurrent | 498 | 532 |
| Current\tpayable\tfor\tinterest\trelated\tto\ttax\tsettlements | 13 | – |
| Noncurrent\treimbursements\tpayable\tunder\tnonqualified\tdefined\tbenefit\tpostretirement\tplans | 7 | 6 |

								Marathon	remains	primarily	obligated	for	$34	million	of	operating	lease	obligations	assumed	by	United	States	Steel,	of	which	$31	million	has	been	assumed	by third	parties	that	purchased	plants	and	operations	divested	by	United	States	Steel.

								In	addition,	Marathon	remains	contingently	liable	for	certain	obligations	of	United	States	Steel.	See	Note	30	for	further	information	regarding	these	guarantees.

# 4.	Variable	Interest	Entities

Equatorial	Guinea	LNG	Holdings	Limited	("EGHoldings"),	in	which	Marathon	holds	a	60	percent	interest	and	which	was	formed	for	the	purpose	of	constructing	and operating	an	LNG	production	facility,	is	a	VIE	that	is	consolidated.	As	of	December	31,	2006,	total	expenditures	of	$1.363	billion	related	to	the	LNG	production facility,	including	$1.300	billion	of	capital	expenditures,	have	been	incurred.	The	Andersons	Marathon	Ethanol	LLC,	a	joint	venture	in	which	Marathon	and	its	partner each	hold	a	50	percent	interest	and	which	was	formed	in	2006	for	the	purpose	of	constructing	and	operating	one	or	more	ethanol	production	plants,	is	a	VIE	that	is	not consolidated.	As	of	December	31,	2006,	Marathon	had	contributed	$11	million	to	The	Andersons	Marathon	Ethanol	LLC.

# 5.	Related	Party	Transactions

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

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

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

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

•Equity	method	investees.	See	"Principal	Unconsolidated	Investees"	on	page	F-42	for	major	investees.

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

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Equity\tmethod\tinvestees: |  |  |  |
| PTC | $1,420 | $1,205 | $715 |
| Centennial\tPipeline\tLLC\t("Centennial") | 28 | 47 | 49 |
| Other\tequity\tmethod\tinvestees | 18 | 18 | 13 |
| Ashland | – | 132 | 274 |
| Total | $1,466 | $1,402 | $1,051 |

								Purchases	from	related	parties	were	as	follows:

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Equity\tmethod\tinvestees: |  |  |  |
| LOOP\tLLC | $54 | $49 | $44 |
| Centennial | 53 | 73 | 56 |
| Other\tequity\tmethod\tinvestees | 103 | 91 | 80 |
| Ashland | – | 12 | 22 |
| Total | $210 | $225 | $202 |

# 								Current	receivables	from	related	parties	were	as	follows:

| (In	millions) | December	31 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Equity\tmethod\tinvestees: |  |  |  |
| PTC |  | $41 | $34 |
| Other\tequity\tmethod\tinvestees |  | 9 | 4 |
| Other\trelated\tparties |  | 13 | – |
| Total |  | $63 | $38 |

# 								Payables	to	related	parties	were	as	follows:

|  | December	31 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| SONAGAS |  | $229 | $– |
| GEPetrol |  | – | 57 |
| Equity\tmethod\tinvestees: |  |  |  |
| Alba\tPlant\tLLC |  | 15 | 14 |
| Other\tequity\tmethod\tinvestees |  | 17 | 11 |
| Other\trelated\tparties |  | 3 | – |
| Total |  | $264 | $82 |

								MPC	had	a	$190	million	uncommitted	revolving	credit	agreement	with	Ashland	that	terminated	in	March	2005.	Interest	paid	to	Ashland	for	borrowings	under	this agreement	was	less	than	$1	million	in	each	of	2005	and	2004.

								Cash	of	$234	million	held	in	escrow	for	future	capital	contributions	from	SONAGAS	to	EGHoldings	is	classified	as	restricted	cash	and	is	included	in	investments and	long-term	receivables	as	of	December	31,	2006.

# 6.	Acquisitions

Minority	interest	in	MPC		–		On	June	30,	2005,	Marathon	acquired	the	38	percent	ownership	interest	in	Marathon	Ashland	Petroleum	LLC	("MAP")	previously	held	by Ashland.	In	addition,	Marathon	acquired	a	portion	of	Ashland's	Valvoline	Instant	Oil	Change	business,	its	maleic	anhydride	business,	its	interest	in	LOOP	LLC,	which owns	and	operates	the	only	U.S.	deepwater	oil	port,	and	its	interest	in	LOCAP	LLC,	which	owns	a	crude	oil	pipeline.	As	a	result	of	the	transactions	(the	"Acquisition"), MAP	is	now	wholly	owned	by	Marathon	and	its	name	was	changed	to	Marathon	Petroleum	Company	LLC	("MPC")	effective	September	1,	2005.	The	Acquisition	was accounted	for	under	the	purchase	method	of	accounting	and,	as	such,	Marathon's	results	of	operations	include	the	results	of	the	acquired	businesses	from	June	30,	2005. The	total	consideration,	including	debt	assumed,	is	as	follows:

| (a)<br>Cash | (a)<br>Cash | $487 |
| :--- | :--- | :--- |
| (a)\nMPC\taccounts\treceivable | (a)\nMPC\taccounts\treceivable | 911 |
| (b)\nMarathon\tcommon\tstock | (b)\nMarathon\tcommon\tstock | 955 |
| Estimated\tadditional\tconsideration\trelated\tto\ttax\tmatters | Estimated\tadditional\tconsideration\trelated\tto\ttax\tmatters | 75 |
| Transaction-related\tcosts | Transaction-related\tcosts | 10 |
| Purchase\tprice | Purchase\tprice | 2,438 |
| Assumption\tof\tdebt | (c) | 1,920 |
| (d)\nTotal\tconsideration\tincluding\tdebt\tassumption | (d)\nTotal\tconsideration\tincluding\tdebt\tassumption | $4,358 |

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

(a) Ashland	shareholders	received	17.539	million	shares	valued	at	$54.45	per	share,	which	was	Marathon's	average	common	stock	price	over	the	trading	days	between	June	23	and	June	29,	2005.	The	exchange ratio	was	designed	to	provide	an	aggregate	number	of	Marathon	shares	worth	$915	million	based	on	Marathon's	average	common	stock	price	for	each	of	the	20	consecutive	trading	days	ending	with	the	third complete	trading	day	prior	to	June	30,	2005.

(a) Marathon	is	entitled	to	certain	tax	deductions	related	to	businesses	previously	owned	by	Ashland.	However,	pursuant	to	the	terms	of	the	tax	matters	agreement,	Marathon	has	agreed	to	reimburse	Ashland	for	a portion	of	the	tax	benefits	associated	with	these	deductions.	This	additional	consideration	will	be	included	in	the	purchase	price	as	amounts	owed	to	Ashland	are	identified.	During	2006,	an	additional $17	million	was	included	in	the	purchase	price	for	such	amounts.

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

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

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

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

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

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

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

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

								The	goodwill	arising	from	the	purchase	price	allocation	was	$853	million,	which	was	assigned	to	the	RM&T	segment.	None	of	the	goodwill	is	deductible	for	tax purposes.	Of	the	$112	million	allocated	to	intangible	assets,	$49	million	was	allocated	to	retail	marketing	tradenames	with	indefinite	lives.

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

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

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

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

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

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

								The	following	unaudited	pro	forma	data	is	as	if	the	Acquisition	and	the	re-entry	to	the	Libya	concessions	had	been	consummated	at	the	beginning	of	each	period presented.	The	pro	forma	data	is	based	on	historical	information	and	does	not	reflect	the	actual	results	that	would	have	occurred	nor	is	it	indicative	of	future	results	of operations.

# (In	millions,	except	per	share	amounts)

|  | 2005 | 2004 |
| :--- | :--- | :--- |
| Revenues\tand\tother\tincome | $65,614 | $50,670 |
| Income\tfrom\tcontinuing\toperations | 3,315 | 1,596 |
| Net\tincome | 3,341 | 1,563 |
| Per\tshare\tdata: |  |  |
| Income\tfrom\tcontinuing\toperations\t–\tbasic | $9.09 | $4.51 |
| Income\tfrom\tcontinuing\toperations\t–\tdiluted | $9.01 | $4.49 |
| Net\tincome\t–\tbasic | $9.16 | $4.42 |
| Net\tincome\t–\tdiluted | $9.08 | $4.39 |

# 7.	Discontinued	Operations

								On	June	2,	2006,	Marathon	sold	its	Russian	oil	exploration	and	production	businesses	in	the	Khanty-Mansiysk	region	of	western	Siberia.	Under	the	terms	of	the agreement,	Marathon	received	$787	million	for	these	businesses,	plus	preliminary	working	capital	and	other	closing	adjustments	of	$56	million,	for	a	total	transaction value	of	$843	million.	Proceeds	net	of	transaction	costs	and	cash	held	by	the	Russian	businesses	at	the	transaction	date	totaled	$832	million.	A	gain	on	the	sale	of $243	million	($342	million	before	income	taxes)	was	reported	in	discontinued	operations	for	2006.	Income	taxes	on	this	gain	were	reduced	by	the	utilization	of	a	capital loss	carryforward	as	discussed	in	Note	11.	Exploration	and	Production	segment	goodwill	of	$21	million	was	allocated	to	the	Russian	assets	and	reduced	the	reported gain.	The	final	adjustment	to	the	sales	price	is	expected	to	be	made	in	2007	and	could	affect	the	reported	gain.

								The	activities	of	the	Russian	businesses	have	been	reported	as	discontinued	operations	in	the	consolidated	statements	of	income	and	the	consolidated	statements	of cash	flows	for	all	periods	presented.	Revenues	applicable	to	discontinued	operations	were	$173	million,	$325	million	and	$133	million	for	2006,	2005,	and	2004.	Pretax income	from	discontinued	operations	was	$45	million	and	$61	million	for	2006	and	2005.	There	was	a	pretax	loss	from	discontinued	operations	of	$45	million	in	2004.

# 8.	Income	per	Common	Share

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

|  | Basic | Diluted | Basic | Diluted | Basic | Diluted |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Income\tfrom\tcontinuing\toperations | $4,957 | $4,957 | $3,006 | $3,006 | $1,294 | $1,294 |
| Discontinued\toperations | 277 | 277 | 45 | 45 | (33) | (33) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | – | (19) | (19) | – | – |
| Net\tincome | $5,234 | $5,234 | $3,032 | $3,032 | $1,261 | $1,261 |
| Weighted\taverage\tcommon\tshares\toutstanding | 357,911 | 357,911 | 356,003 | 356,003 | 336,485 | 336,485 |
| Effect\tof\tdilutive\tsecurities | – | 3,116 | – | 3,078 | – | 1,768 |
| Weighted\taverage\tcommon\tshares,\tincluding\tdilutive\teffect | 357,911 | 361,027 | 356,003 | 359,081 | 336,485 | 338,253 |
| Per\tshare: |  |  |  |  |  |  |
| Income\tfrom\tcontinuing\toperations | $13.85 | $13.73 | $8.44 | $8.37 | $3.85 | $3.83 |
| Discontinued\toperations | $0.77 | $0.77 | $0.13 | $0.12 | $(0.10) $ | (0.10) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | $– | $– | $(0.05) $ | (0.05) $ | – | $– |
| Net\tincome | $14.62 | $14.50 | $8.52 | $8.44 | $3.75 | $3.73 |

# 9.	Segment	Information

								Revenues	by	product	line	were:

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Refined\tproducts | $45,511 | $40,040 | $29,780 |
| Merchandise | 2,871 | 2,689 | 2,489 |
| Liquid\thydrocarbons | 12,531 | 16,352 | 13,727 |
| Natural\tgas | 3,742 | 3,675 | 3,266 |
| Transportation\tand\tother | 241 | 230 | 203 |
| Total | $64,896 | $62,986 | $49,465 |

								Matching	buy/sell	transactions	by	product	line	included	above	were:

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Refined\tproducts | $645 | $1,817 | $1,226 |
| Liquid\thydrocarbons | 4,812 | 10,819 | 8,016 |
| Total | $5,457 | $12,636 | $9,242 |

								Effective	January	1,	2006,	Marathon	revised	its	measure	of	segment	income	to	include	the	effects	of	minority	interests	and	income	taxes	related	to	the	segments	to facilitate	comparison	of	segment	results	with	Marathon's	peers.	In	addition,	the	results	of	activities	primarily	associated	with	the	marketing	of	the	Company's	equity natural	gas	production,	which	had	been	presented	as	part	of	the	IG	segment	prior	to	2006,	are	now	included	in	the	E&P	segment	as	those	activities	are	aligned	with	E&P operations.	Segment	information	for	all	periods	presented	reflects	these	changes.

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

| (In	millions) | Exploration<br>and<br>Production | Refining,<br>Marketing	and<br>Transportation | Integrated<br>Gas | Total |
| :--- | :--- | :--- | :--- | :--- |
| 2006 |  |  |  |  |
| Revenues: |  |  |  |  |
| Customer | $8,326 | $54,471 | $179 | $62,976 |
| (a)\nIntersegment | 672 | 16 | – | 688 |
| Related\tparties | 12 | 1,454 | – | 1,466 |
| Segment\trevenues | 9,010 | 55,941 | 179 | 65,130 |
| Elimination\tof\tintersegment\trevenues | (672) | (16) | – | (688) |
| Gain\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts | 454 | – | – | 454 |
| Total\trevenues | $8,792 | $55,925 | $179 | $64,896 |
| Segment\tincome | $2,003 | $2,795 | $16 | $4,814 |
| Income\tfrom\tequity\tmethod\tinvestments | 206 | 145 | 40 | 391 |
| (b)\nDepreciation,\tdepletion\tand\tamortization | 919 | 558 | 9 | 1,486 |
| Minority\tinterests\tin\tloss\tof\tsubsidiaries | – | – | (10) | (10) |
| (b)\nIncome\ttax\tprovision | 2,371 | 1,642 | 8 | 4,021 |
| (c)\nCapital\texpenditures | 2,169 | 916 | 307 | 3,392 |
| 2005 |  |  |  |  |
| Revenues: |  |  |  |  |
| Customer | $7,320 | $54,414 | $236 | $61,970 |
| (a)\nIntersegment | 678 | 198 | – | 876 |
| Related\tparties | 11 | 1,391 | – | 1,402 |
| Segment\trevenues | 8,009 | 56,003 | 236 | 64,248 |
| Elimination\tof\tintersegment\trevenues | (678) | (198) | – | (876) |
| Loss\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts | (386) | – | – | (386) |
| Total\trevenues | $6,945 | $55,805 | $236 | $62,986 |
| Segment\tincome | $1,887 | $1,628 | $55 | $3,570 |
| Income\tfrom\tequity\tmethod\tinvestments | 69 | 137 | 59 | 265 |
| (b)\nDepreciation,\tdepletion\tand\tamortization | 794 | 468 | 8 | 1,270 |
| (b)\nMinority\tinterests\tin\tincome\t(loss)\tof\tsubsidiaries | – | 376 | (8) | 368 |
| (b)\nIncome\ttax\tprovision\t(benefit) | 1,030 | 1,007 | (7) | 2,030 |
| (c)\nCapital\texpenditures | 1,366 | 841 | 571 | 2,778 |
| 2004 |  |  |  |  |
| Revenues: |  |  |  |  |
| Customer | $5,888 | $42,435 | $190 | $48,513 |
| (a)\nIntersegment | 516 | 152 | – | 668 |
| Related\tparties | 8 | 1,043 | – | 1,051 |
| Segment\trevenues | 6,412 | 43,630 | 190 | 50,232 |
| Elimination\tof\tintersegment\trevenues | (516) | (152) | – | (668) |
| Loss\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts | (99) | – | – | (99) |
| Total\trevenues | $5,797 | $43,478 | $190 | $49,465 |
| Segment\tincome | $1,090 | $568 | $37 | $1,695 |
| Income\tfrom\tequity\tmethod\tinvestments | 17 | 81 | 69 | 167 |
| (b)\nDepreciation,\tdepletion\tand\tamortization | 724 | 416 | 7 | 1,147 |
| (b)\nMinority\tinterests\tin\tincome\t(loss)\tof\tsubsidiaries | – | 539 | (7) | 532 |
| (b)\nIncome\ttax\tprovision | 606 | 301 | 19 | 926 |
| (c)\nCapital\texpenditures | 840 | 794 | 488 | 2,122 |

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

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

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

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Segment\tincome | $4,814 | $3,570 | $1,695 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |  |
| Corporate\tand\tother\tunallocated\titems | (212) | (377) | (327) |
| Gain\t(loss)\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts | 232 | (223) | (57) |
| Discontinued\toperations | 277 | 45 | (33) |
| Gain\ton\tdisposition\tof\tSyria\tinterest | 31 | – | – |
| Deferred\tincome\ttaxes\t–\ttax\tlegislation\tchanges | 21 | 15 | – |
| (a) |  |  |  |
| \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​\t0;\tother\tadjustments | 93 | – | – |
| Loss\ton\tearly\textinguishment\tof\tdebt | (22) | – | – |
| Gain\ton\tsale\tof\tminority\tinterests\tin\tEGHoldings | – | 21 | – |
| Corporate\tinsurance\tadjustment | – | – | (17) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | (19) | – |
| Net\tincome | $5,234 | $3,032 | $1,261 |

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

								The	following	summarizes	revenues	from	external	customers	by	geographic	area.

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| United\tStates | $59,723 | $60,242 | $47,354 |
| International | 5,173 | 2,744 | 2,111 |
| Total | $64,896 | $62,986 | $49,465 |

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

|  | 2006 | 2005 |
| :--- | :--- | :--- |
| United\tStates | $11,401 | $10,143 |
| Equatorial\tGuinea | 3,157 | 3,018 |
| Other\tinternational | 3,668 | 3,510 |
| Total | $18,226 | $16,671 |

# 10.	Other	Items

# Net	interest	and	other	financing	costs	(income)

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Interest\tand\tother\tfinancial\tincome: |  |  |  |
| Interest\tincome | $129 | $77 | $44 |
| Foreign\tcurrency\tgains\t(losses) | 16 | (17) | 9 |
| Total | 145 | 60 | 53 |
| Interest\tand\tother\tfinancing\tcosts:\n(a)\nInterest\tincurred | 245 | 257 | 262 |
| (Income)\tloss\tfrom\tinterest\trate\tswaps | 16 | – | (24) |
| Interest\tcapitalized | (152) | (83) | (48) |
| Net\tinterest\texpense | 109 | 174 | 190 |
| Net\tinterest\texpense\t(income)\ton\ttax\tissues | (11) | 22 | 12 |
| Other | 10 | 10 | 13 |
| Total | 108 | 206 | 215 |
| Net\tinterest\tand\tother\tfinancing\tcosts\t(income) | $(37) | $146 | $162 |

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Net\tinterest\tand\tother\tfinancing\tcosts | $16 | $(17) | $9 |
| Provision\tfor\tincome\ttaxes | (22) | 24 | (15) |

# Aggregate	foreign	currency	gains	(losses)

# 11.	Income	Taxes

								Income	tax	provisions	(benefits)	were:

|  | Current | Deferred | Total | Current | Deferred | Total | Current | Deferred | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Federal | $1,579 | $72 | $1,651 | $1,225 | $14 | $1,239 | $476 | $(20) $ | 456 |
| State\tand\tlocal | 230 | 30 | 260 | 171 | 12 | 183 | 47 | 1 | 48 |
| Foreign | 1,945 | 166 | 2,111 | 523 | (231) | 292 | 274 | (43) | 231 |
| Total | $3,754 | $268 | $4,022 | $1,919 | $(205) $ | 1,714 | $797 | $(62) $ | 735 |

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Statutory\trate\tapplied\tto\tincome\tfrom\tcontinuing\toperations\tbefore\tincome\ttaxes | $3,143 | $1,652 | $710 |
| (a) |  |  |  |
| Effects\tof\tforeign\toperations,\tincluding\tforeign\ttax\tcredits | 888 | (39) | 10 |
| State\tand\tlocal\tincome\ttaxes\tnet\tof\tfederal\tincome\ttax\teffects | 170 | 119 | 32 |
| Credits\tother\tthan\tforeign\ttax\tcredits | (2) | (2) | (2) |
| (b) |  |  |  |
| Domestic\tmanufacturing\tdeduction | (47) | (39) | – |
| Excess\tcapital\tlosses\tgenerated\t(utilized) | – | 23 | (4) |
| Effects\tof\tpartially\towned\tcompanies | (6) | (4) | (3) |
| (c) |  |  |  |
| Adjustment\tof\tprior\tyears'\tfederal\tincome\ttaxes | (119) | 10 | (8) |
| Other | (5) | (6) | – |
| Provision\tfor\tincome\ttaxes | $4,022 | $1,714 | $735 |

(a) In	2006,	Marathon	resumed	operations	in	Libya	where	the	statutory	income	tax	rate	is	in	excess	of	90	percent.

(b) See	Note	2	regarding	Marathon's	adoption	of	FSP	No.	FAS	109-1.	Marathon	has	treated	the	deduction,	equal	to	3	percent	of	"qualified	production	activities	income"	under	the	American	Jobs	Creation	Act	of 2004,	as	a	special	deduction	beginning	in	2005.

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

								Deferred	tax	assets	and	liabilities	resulted	from	the	following:

|  |  | December	31 | 2006 | 2005 |
| :--- | :--- | :--- | :--- | :--- |
| Deferred\ttax\tassets:\nEmployee\tbenefits | Deferred\ttax\tassets:\nEmployee\tbenefits |  | $730 | $622 |
| (a)\nCapital\tloss\tcarryforwards | (a)\nCapital\tloss\tcarryforwards |  | – | 79 |
| (b)\nOperating\tloss\tcarryforwards | (b)\nOperating\tloss\tcarryforwards |  | 1,016 | 754 |
| Derivative\tinstruments | Derivative\tinstruments |  | 81 | 181 |
| Foreign\ttax\tcredits | (c) |  | 527 | 123 |
| Other | Other |  | 200 | 380 |
| Valuation\tallowances |  |  |  |  |
| (a)(d)\nFederal | (a)(d)\nFederal |  | (19) | (120) |
| (b)\nState | (b)\nState |  | (59) | (72) |
| (e)\nForeign | (e)\nForeign |  | (611) | (435) |
| Total\tdeferred\ttax\tassets | Total\tdeferred\ttax\tassets |  | 1,865 | 1,512 |
| Deferred\ttax\tliabilities: |  |  |  |  |
| Property,\tplant\tand\tequipment | Property,\tplant\tand\tequipment |  | 2,951 | 2,867 |
| Inventories | Inventories |  | 708 | 762 |
| Investments\tin\tsubsidiaries\tand\taffiliates | Investments\tin\tsubsidiaries\tand\taffiliates |  | 552 | 93 |
| Other | Other |  | 100 | 108 |
| Total\tdeferred\ttax\tliabilities | Total\tdeferred\ttax\tliabilities |  | 4,311 | 3,830 |
| Net\tdeferred\ttax\tliabilities | Net\tdeferred\ttax\tliabilities |  | $2,446 | $2,318 |

(a) Capital	loss	carryforwards	were	utilized	in	conjunction	with	the	sale	of	Marathon's	Russian	oil	exploration	and	production	businesses	in	June	2006	as	discussed	in	Note	7.	The	reversal	of	the	related	valuation allowance	reduced	income	taxes	attributable	to	discontinued	operations	by	$79	million.

(b) For	2006,	foreign	operating	loss	carryforwards	primarily	include	$684	million	for	Norway	regular	income	tax,	$1.006	billion	for	Norway	special	petroleum	tax	and	$250	million	for	Angola	income	tax.	The Norway	and	Angola	operating	loss	carryforwards	have	no	expiration	dates.	The	remainder	of	foreign	carryforwards	are	in	several	other	foreign	jurisdictions	and	expire	in	2007	through	2019.	State	operating loss	carryforwards	of	$1.352	billion	expire	in	2007	through	2021.	The	state	operating	loss	carryforwards	primarily	relate	the	period	prior	to	the	Separation	and	are	offset	by	valuation	allowances.

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

(d) Federal	valuation	allowances	increased	by	$63	million	in	2005	and	decreased	by	$10	million	in	2004.	The	2005	increase	reflected	valuation	allowances	established	for	deferred	tax	assets	generated	in	2005, primarily	related	to	Marathon's	re-entry	into	Libya	of	$38	million	and	excess	capital	losses	related	to	certain	derivative	instruments	and	an	asset	sale	of	$30	million.

(e) Foreign	valuation	allowances	increased	by	$176	million,	$70	million	and	$82	million	in	2006,	2005	and	2004	primarily	as	a	result	of	net	operating	loss	carryforwards	generated	in	those	years	in	Norway, Angola	and	several	other	jurisdictions.

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

|  | December	31 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Assets: |  |  |  |
| Other\tcurrent\tassets |  | $4 | $14 |
| Other\tnoncurrent\tassets |  | 78 | 148 |
| Liabilities: |  |  |  |
| Current\tdeferred\tincome\ttaxes |  | 631 | 450 |
| Noncurrent\tdeferred\tincome\ttaxes |  | 1,897 | 2,030 |
| Net\tdeferred\ttax\tliabilities |  | $2,446 | $2,318 |

								Marathon	is	continuously	undergoing	examination	of	its	federal	income	tax	returns	by	the	Internal	Revenue	Service.	Audits	of	the	Company's	1998	through	2003 income	tax	returns	have	been	completed	and	agreed	upon	by	all	parties.	A	$46	million	refund	was	received	from	the	1998	through	2001	audit,	$35	million	of	which	was paid	to	United	States	Steel	in	accordance	with	the	tax	sharing	agreement	discussed	in	Note	3.	The	audit	for	tax	years	2004	and	2005	commenced	in	May	2006.	Marathon believes	it	has	made	adequate	provision	for	federal	income	taxes	and	interest	which	may	become	payable	for	years	not	yet	settled.	Further,	the	Company	is	routinely involved	in	state	and	local	income	tax	audits	and	foreign	jurisdiction	tax	audits.	Marathon	believes	all	other	audits	will	be	resolved	within	the	amounts	paid	and/or provided	for	these	liabilities.

								Undistributed	income	of	certain	consolidated	foreign	subsidiaries	at	December	31,	2006	amounted	to	$1.581	billion	for	which	no	deferred	U.S.	income	tax provision	has	been	made	because	Marathon	intends	to	permanently	reinvest	such	income	in	those	foreign	operations.	If	such	income	was	not	permanently	reinvested,	a tax	expense	of	$554	million	would	have	been	incurred.

# 12.	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,	Texas	and	reducing	the	workforce.	During	2004,	Marathon entered	into	two	outsourcing	agreements	to	achieve	further	business	process	improvements	and	cost	reductions.

								During	2004,	Marathon	recorded	$43	million	of	costs	as	general	and	administrative	expenses	related	to	these	business	transformation	programs.	These	charges included	employee	severance	and	benefit	costs,	relocation	costs	and	net	benefit	plans	settlement	and	curtailment	losses.

								There	were	minimal	charges	to	expense	during	2005.	As	of	December	31,	2005,	no	accrual	remained	related	to	the	business	transformation	programs.	The following	table	sets	forth	the	significant	components	and	activity	in	the	business	transformation	programs	during	2004.

| (In	millions) | Accrued<br>January	1 | Expense | Noncash<br>Charges | Cash<br>Payments | Accrued<br>December	31 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 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 |

# 13.	Inventories

|  | December	31 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Liquid\thydrocarbons\tand\tnatural\tgas |  | $1,136 | $1,093 |
| Refined\tproducts\tand\tmerchandise |  | 1,812 | 1,763 |
| Supplies\tand\tsundry\titems |  | 225 | 185 |
| Total\t(at\tcost) |  | $3,173 | $3,041 |

								The	LIFO	method	accounted	for	90	percent	and	92	percent	of	total	inventory	value	at	December	31,	2006	and	2005.	Current	acquisition	costs	were	estimated	to exceed	the	LIFO	inventory	values	at	December	31,	2006	and	2005	by	$1.682	billion	and	$1.535	billion.

# 14.	Investments	and	Long-Term	Receivables

|  | December	31 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Equity\tmethod\tinvestments: |  |  |  |
| Alba\tPlant\tLLC |  | $420 | $513 |
| Atlantic\tMethanol\tProduction\tCompany\tLLC |  | 257 | 258 |
| Pilot\tTravel\tCenters\tLLC |  | 510 | 516 |
| LOOP\tLLC |  | 156 | 148 |
| Other |  | 196 | 220 |
| Other\tinvestments |  | 34 | 5 |
| Recoverable\tenvironmental\tcosts\treceivable |  | 54 | 57 |
| Value-added\ttax\trefunds\treceivable |  | – | 29 |
| Fair\tvalue\tof\tderivative\tassets |  | – | 14 |
| Deposits\tof\trestricted\tcash |  | 240 | 87 |
| Other\treceivables |  | 20 | 17 |
| Total |  | $1,887 | $1,864 |

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Income\tdata\t–\tyear: |  |  |  |
| Revenues\tand\tother\tincome | $11,873 | $10,088 | $7,419 |
| Operating\tincome | 746 | 556 | 434 |
| Net\tincome | 710 | 474 | 330 |
| Balance\tsheet\tdata\t–\tDecember\t31: |  |  |  |
| Current\tassets | $817 | $645 |  |
| Noncurrent\tassets | 3,637 | 3,598 |  |
| Current\tliabilities | 755 | 668 |  |
| Noncurrent\tliabilities | 1,119 | 1,477 |  |

								Marathon's	carrying	value	of	its	equity	method	investments	is	$250	million	higher	than	the	underlying	net	assets	of	investees.	This	basis	difference	is	being amortized	into	net	income	over	the	remaining	useful	lives	of	the	underlying	net	assets	except	for	$144	million	of	the	excess	related	to	goodwill.

								Dividends	and	partnership	distributions	received	from	equity	method	investees	(excluding	distributions	that	represented	a	return	of	capital	previously	contributed) were	$191	million	in	2006,	$200	million	in	2005	and	$152	million	in	2004.

# 15.	Property,	Plant	and	Equipment

|  | December	31 | 2006 | 2005 |
| :--- | :--- | :--- | :--- |
| Production |  | $18,894 | $17,262 |
| Refining |  | 5,238 | 4,727 |
| Marketing |  | 2,015 | 1,895 |
| Transportation |  | 2,173 | 1,980 |
| Gas\tliquefaction |  | 1,321 | 1,067 |
| Other |  | 585 | 464 |
| Total |  | 30,226 | 27,395 |
| Less\taccumulated\tdepreciation,\tdepletion\tand\tamortization |  | 13,573 | 12,384 |
| Net\tproperty,\tplant\tand\tequipment |  | $16,653 | $15,011 |

								Property,	plant	and	equipment	includes	gross	assets	acquired	under	capital	leases	of	$79	million	and	$78	million	at	December	31,	2006	and	2005,	with	related amounts	in	accumulated	depreciation,	depletion	and	amortization	of	$10	million	and	$6	million	at	December	31,	2006	and	2005.

# 								Deferred	exploratory	well	costs	were	as	follows:

| (Dollars	in	millions)																																																																																																														December	31 | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Amounts\tcapitalized\tless\tthan\tone\tyear\tafter\tcompletion\tof\tdrilling | $377 | $304 | $284 |
| Amounts\tcapitalized\tgreater\tthan\tone\tyear\tafter\tcompletion\tof\tdrilling | 93 | 59 | 55 |
| Total\tdeferred\texploratory\twell\tcosts | $470 | $363 | $339 |
| Number\tof\tprojects\twith\tcosts\tcapitalized\tgreater\tthan\tone\tyear\tafter\tcompletion\tof\tdrilling | 3 | 2 | 2 |

								Exploratory	well	costs	capitalized	greater	than	one	year	after	completion	of	drilling	as	of	December	31,	2006	included	$46	million	for	the	Ozona	prospect	that	was primarily	incurred	in	2001	and	2002,	$17	million	for	the	Flathead	prospect	that	was	primarily	incurred	in	2001	and	$30	million	related	to	wells	in	Equatorial	Guinea (primarily	Corona	and	Gardenia)	that	was	primarily	incurred	in	2004.	Both	Ozona	and	Flathead	are	located	in	the	Gulf	of	Mexico.

								Marathon	is	continuing	to	evaluate	options	to	develop	the	Ozona	Prospect.	Commercial	terms	were	secured	in	2005	after	protracted	negotiations	with	offset operators	to	allow	this	sub-sea	well	to	be	tied	back	to	existing	oil	and	gas	infrastructure.	A	sidetrack	well	was	planned	for	2006;	however,	a	deepwater	rig	could	not	be obtained	due	to	a	partner	disposition	of	interest	in	the	prospect	and	a	shortage	of	deepwater	rigs	resulting	from	hurricane	damage	in	2005	and	increased	deepwater drilling	activity.	During	2006,	Marathon	continued	its	efforts	to	advance	the	Ozona	Prospect	by	reprocessing	existing	seismic	data	to	optimize	the	next	well	location. Marathon	has	also	continued	to	actively	search	for	rig	availability.

								Technical	evaluations	are	complete	on	the	Flathead	Prospect	and	commercial	evaluations	continued	in	2006.	The	drilling	of	this	prospect	is	delayed	due	to	the shortage	of	available	deepwater	rigs.	Marathon	continues	to	pursue	partnering	opportunities	with	other	oil	and	gas	companies	with	deepwater	rigs	under	contract	that will	ultimately	result	in	a	well	being	drilled	by	2008.

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

								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 | Disposals |  | Balance<br>at	End	of<br>Period |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Year\tended\tDecember\t31,\t2006 | $363 | $174 | $(27) | $(21) $ |  | (19) $ | 470 |
| Year\tended\tDecember\t31,\t2005 | 339 | 135 | (31) | (80) |  | – | 363 |
| Year\tended\tDecember\t31,\t2004 | 243 | 239 | (54) | (89) |  | – | 339 |

# 16.	Goodwill

The	changes	in	the	carrying	amount	of	goodwill	for	the	years	ended	December	31,	2006	and	2005,	were	as	follows:

| (In	millions) | Exploration<br>and<br>Production | Refining,	Marketing<br>and<br>Transportation | Total |
| :--- | :--- | :--- | :--- |
| Balance\tas\tof\tDecember\t31,\t2004 | $231 | $21 | $252 |
| Goodwill\tacquired | 315 | 735 | 1,050 |
| Other | – | 5 | 5 |
| Balance\tas\tof\tDecember\t31,\t2005 | 546 | 761 | 1,307 |
| Adjustments\tto\tpreviously\tacquired\tgoodwill | (6) | 118(a) | 112 |
| (b)\nDisposals | (21) | – | (21) |
| Balance\tas\tof\tDecember\t31,\t2006 | $519 | $879 | $1,398 |

(a) Reflects	adjustments	related	to	additional	consideration	payable	and	prior	period	income	tax	adjustments.

(b) Exploration	and	Production	segment	goodwill	allocated	to	the	Russian	businesses	that	were	sold	in	June	2006	as	discussed	in	Note	7.

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

# 17.	Intangible	Assets

Intangible	assets	were	as	follows:

| (In	millions)																																																	December	31 | Gross	Carrying<br>Amount | Accumulated<br>Amortization | Net	Carrying<br>Amount |
| :--- | :--- | :--- | :--- |
| 2006 |  |  |  |
| Amortized\tintangible\tassets: |  |  |  |
| Branding\tagreements | $54 | $20 | $34 |
| Elba\tIsland\tdelivery\trights | 42 | 8 | 34 |
| Other | 103 | 47 | 56 |
| Total | $199 | $75 | $124 |
| Unamortized\tintangible\tassets: |  |  |  |
| Retail\tmarketing\ttradenames | $49 | $– | $49 |
| Other | 7 | – | 7 |
| Total | $56 | $– | $56 |
| 2005 |  |  |  |
| Amortized\tintangible\tassets: |  |  |  |
| Branding\tagreements | $51 | $16 | $35 |
| Elba\tIsland\tdelivery\trights | 42 | 6 | 36 |
| Other | 96 | 36 | 60 |
| Total | $189 | $58 | $131 |
| Unamortized\tintangible\tassets: |  |  |  |
| Retail\tmarketing\ttradenames | $49 | $– | $49 |
| Unrecognized\tprior\tservice\tcosts\tand\tother | 20 | – | 20 |
| Total | $69 | $– | $69 |

The	following	table	sets	forth	quantitative	information	by	category	of	derivative	instrument	at	December	31,	2006	and	2005.	These	amounts	are	reported	on	a	gross basis	by	individual	derivative	instrument.

|  | December	31 | Assets^(a) | (Liabilities)^(a) | Assets^(a) | (Liabilities)^(a) |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Commodity\tInstruments |  |  |  |  |  |
| (b) |  |  |  |  |  |
| Fair\tvalue\thedges\n: |  |  |  |  |  |
| Exchange\ttraded\tcommodity\tfutures |  | $– | $(4) | $2 | $(2) |
| Over-the-counter\t("OTC")\tcommodity\tswaps |  | 20 | (15) | 66 | (2) |
| Non-hedge\tdesignation: |  |  |  |  |  |
| Exchange-traded\tcommodity\tfutures |  | $301 | $(258) | $281 | $(288) |
| Exchange-traded\tcommodity\toptions |  | 88 | (93) | 70 | (65) |
| OTC\tcommodity\tswaps |  | 44 | (34) | 105 | (99) |
| OTC\tcommodity\toptions |  | 2 | (1) | 3 | (6) |
| Nontraditional\tInstruments |  |  |  |  |  |
| (c) |  |  |  |  |  |
| Long-term\tUnited\tKingdom\tnatural\tgas\tcontracts |  | $– | $(60) | $– | $(513) |
| (d) |  |  |  |  |  |
| Physical\tcommodity\tcontracts |  | 46 | (64) | 71 | (62) |
| Financial\tInstruments |  |  |  |  |  |
| Fair\tvalue\thedges: |  |  |  |  |  |
| (e) |  |  |  |  |  |
| OTC\tinterest\trate\tswaps |  | $– | $(22) | $– | $(30) |
| (f) |  |  |  |  |  |
| Cash\tflow\thedges\n:\nOTC\tforeign\tcurrency\tforwards |  | 3 | – | – | (2) |

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

(b) There	was	no	ineffectiveness	associated	with	fair	value	hedges	for	2006	or	2005	because	the	hedging	instruments	and	the	existing	firm	commitment	contracts	are	priced	on	the	same	underlying	index. Derivative	instruments	used	in	the	fair	value	hedges	mature	between	2007	and	2008.

(c) The	contract	price	under	the	long-term	U.K.	natural	gas	contracts	is	reset	annually	and	is	indexed	to	a	basket	of	costs	of	living	and	energy	commodity	indices	for	the	previous	twelve	months.	The	fair	value	of these	contracts	is	determined	by	applying	the	difference	between	the	contract	price	and	the	U.K.	forward	gas	strip	price	to	the	expected	sales	volumes	under	these	contracts	for	the	next	18	months.	The	18- month	period	represents	approximately	90	percent	of	market	liquidity	in	that	region.

(d) 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	management	has	chosen	not	to	designate	as	normal	purchases	or	normal	sales,	which	can	include	contracts	that	involve	flash	title,	are	accounted	for	as	nontraditional derivative	instruments.

(e) The	fair	value	of	OTC	interest	rate	swaps	excludes	accrued	interest	amounts	not	yet	settled.	As	of	December	31,	2006	and	2005,	accrued	interest	approximated	$4	million	and	$3	million.	The	net	fair	value	of the	OTC	interest	rate	swaps	as	of	December	31,	2006	and	2005	is	included	in	long-term	debt.	See	Note	21.

(f) The	ineffective	portion	of	the	changes	in	fair	value	of	cash	flow	hedges	was	$3	million	during	2006	and	less	than	$1	million	during	2005	on	a	pretax	basis.	Of	the	unrealized	gains	and	losses	recorded	in accumulated	other	comprehensive	loss	as	of	December	31,	2006,	a	net	gain	of	$2	million	is	expected	to	be	reclassified	to	net	income	in	2007.

# 19.	Fair	Value	of	Financial	Instruments

The	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	18,	by	individual	balance	sheet	line	item.	Marathon's	financial	instruments	at	December	31,	2006	and	2005	were:

| (In	millions) | December	31 | Fair<br>Value | Carrying<br>Amount | Fair<br>Value | Carrying<br>Amount |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Financial\tassets: |  |  |  |  |  |
| Cash\tand\tcash\tequivalents |  | $2,585 | $2,585 | $2,617 | $2,617 |
| Receivables |  | 4,177 | 4,177 | 3,514 | 3,514 |
| Receivables\tfrom\tUnited\tStates\tSteel |  | 522 | 530 | 540 | 552 |
| (a) |  |  |  |  |  |
| Investments\tand\tlong-term\treceivables |  | 461 | 348 | 268 | 195 |
| Total\tfinancial\tassets |  | $7,745 | $7,640 | $6,939 | $6,878 |
| Financial\tliabilities: |  |  |  |  |  |
| Accounts\tpayable |  | $5,850 | $5,850 | $5,435 | $5,435 |
| Consideration\tpayable\tunder\tLibya\tre-entry\tagreement |  | – | – | 732 | 732 |
| Payables\tto\tUnited\tStates\tSteel |  | 20 | 20 | 6 | 6 |
| Accrued\tinterest |  | 89 | 89 | 96 | 96 |
| (b) |  |  |  |  |  |
| Long-term\tdebt\tdue\twithin\tone\tyear |  | 450 | 450 | 302 | 302 |
| (b) |  |  |  |  |  |
| Long-term\tdebt |  | 3,279 | 2,947 | 4,052 | 3,573 |
| Total\tfinancial\tliabilities |  | $9,688 | $9,356 | $10,623 | $10,144 |

(a) Excludes	equity	method	investments	and	derivatives.

(b) Excludes	capital	leases.

								The	fair	value	of	financial	instruments	classified	as	current	assets	or	liabilities	approximates	carrying	value	due	to	the	short-term	maturity	of	the	instruments.	The fair	value	of	investments	and	long-term	receivables	was	based	on	discounted	cash	flows	or	other	specific	instrument	analysis.	The	fair	value	of	long-term	debt instruments	was	based	on	market	prices	where	available	or	current	borrowing	rates	available	for	financings	with	similar	terms	and	maturities.	The	fair	value	of	the receivables	from	United	States	Steel	was	estimated	using	market	prices	for	United	States	Steel	debt	assuming	the	industrial	revenue	bonds	are	redeemed	on	or	before	the tenth	anniversary	of	the	Separation	per	the	Financial	Matters	Agreement.

# 20.	Short-Term	Debt

Marathon	has	a	commercial	paper	program	that	is	supported	by	the	unused	and	available	credit	on	the	Marathon	five-year	revolving	credit	facility	discussed	in	Note	21. At	December	31,	2006,	there	were	no	commercial	paper	borrowings	outstanding.

# 21.	Long-Term	Debt

|  |  | December	31 | 2006 | 2005 |
| :--- | :--- | :--- | :--- | :--- |
| Marathon\tOil\tCorporation: |  |  |  |  |
| Revolving\tcredit\tfacility\tdue\t2011 | (a) |  | $– | $– |
| 6.650%\tnotes\tdue\t2006 | 6.650%\tnotes\tdue\t2006 |  | – | 300 |
| 5.375%\tnotes\tdue\t2007 | (b) |  | 450 | 450 |
| 6.850%\tnotes\tdue\t2008 | 6.850%\tnotes\tdue\t2008 |  | 400 | 400 |
| 6.125%\tnotes\tdue\t2012 | (b) |  | 450 | 450 |
| 6.000%\tnotes\tdue\t2012 | (b) |  | 400 | 400 |
| 6.800%\tnotes\tdue\t2032 | (b) |  | 550 | 550 |
| 9.375%\tdebentures\tdue\t2012 | (c) |  | 123 | 163 |
| 9.125%\tdebentures\tdue\t2013 | (c) |  | 212 | 271 |
| 9.375%\tdebentures\tdue\t2022 | (c) |  | 67 | 81 |
| 8.500%\tdebentures\tdue\t2023 | (c) |  | 122 | 123 |
| 8.125%\tdebentures\tdue\t2023 | (c) |  | 181 | 229 |
| 6.570%\tpromissory\tnote\tdue\t2006 | (b) |  | – | 2 |
| Series\tA\tmedium\tterm\tnotes\tdue\t2022 | Series\tA\tmedium\tterm\tnotes\tdue\t2022 |  | 3 | 3 |
| notes\tdue\t2009\t–\t2033 | (d) |  | 439 | 453 |
| Sale-leaseback\tfinancing\tdue\t2007\t–\t2012 | (e) |  | 60 | 66 |
| Capital\tlease\tobligation\tdue\t2007\t–\t2012\nConsolidated\tsubsidiaries: | (f) |  | 44 | 49 |
| Revolving\tcredit\tfacility\tdue\t2009 | (g) |  | – | – |
| Capital\tlease\tobligations\tdue\t2007\t–\t2020 | Capital\tlease\tobligations\tdue\t2007\t–\t2020 |  | 59 | 61 |
| (h)(i) | (h)(i) |  |  |  |
| Total | Total |  | 3,560 | 4,051 |
| Unamortized\tdiscount | Unamortized\tdiscount |  | (6) | (8) |
| Fair\tvalue\tadjustments\ton\tnotes\tsubject\tto\thedging | (j) |  | (22) | (30) |
| Amounts\tdue\twithin\tone\tyear | Amounts\tdue\twithin\tone\tyear |  | (471) | (315) |
| Long-term\tdebt\tdue\tafter\tone\tyear | Long-term\tdebt\tdue\tafter\tone\tyear |  | $3,061 | $3,698 |

(a) In	May	2006,	Marathon	entered	into	an	amendment	of	its	$1.5	billion	five-year	revolving	credit	agreement,	expanding	the	size	of	the	facility	to	$2	billion	and	extending	the	termination	date	from	May	2009	to May	2011.	The	facility	requires	a	representation	at	an	initial	borrowing	that	there	has	been	no	change	in	Marathon's	consolidated	financial	position	or	operations,	considered	as	a	whole,	that	would	materially and	adversely	affect	its	ability	to	perform	its	obligations	under	the	revolving	credit	facility.	Interest	on	the	facility	is	based	on	defined	short-term	market	rates.	During	the	term	of	the	agreement,	Marathon	is obligated	to	pay	a	variable	facility	fee	on	the	total	commitment,	which	at	December	31,	2006	was	0.08	percent.	At	December	31,	2006,	there	were	no	borrowings	outstanding	under	this	facility.

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

(c) During	2006,	Marathon	extinguished	portions	of	this	debt.	Debt	with	a	total	face	value	of	$162	million	was	repurchased	at	a	weighted	average	price	equal	to	122	percent	of	face	value.	The	total	premium	of $35	million	is	reflected	as	loss	on	early	extinguishment	of	debt	in	the	consolidated	statement	of	income	for	2006.

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

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

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

(g) MPC's	$500	million	five-year	revolving	credit	agreement	was	terminated	concurrent	with	the	May	2006	amendment	of	Marathon's	revolving	credit	facility.

(h) Required	payments	of	long-term	debt	for	the	years	2008-2011	are	$417	million,	$19	million,	$21	million	and	$164	million.	Of	these	amounts,	payments	assumed	by	United	States	Steel	are	$14	million, $15	million,	$17	million	and	$161	million.

(i) In	the	event	of	a	change	in	control	of	Marathon,	as	defined	in	the	related	agreements,	debt	obligations	totaling	$1.183	billion	at	December	31,	2006,	may	be	declared	immediately	due	and	payable.

(j) See	Note	18	for	information	on	interest	rate	swaps.

								In	2006,	Marathon	entered	into	a	loan	agreement	which	provides	for	borrowings	of	up	to	$525	million	from	the	Norwegian	export	credit	agency	based	upon	the amount	of	qualifying	purchases	by	Marathon	of	goods	and	services	from	Norwegian	suppliers.	The	loan	agreement	allows	Marathon	to	select	either	a	fixed	or	LIBOR- based	floating	interest	rate	at	the	time	of	the	initial	drawdown	and	a	five-year	or	eight	and	one	half-year	repayment	term.	If	Marathon	elects	to	borrow	under	this agreement,	the	initial	drawdown	must	occur	in	June	2007	with	one	subsequent	drawdown	allowed	in	December	2007.

# 22.	MPC	Receivables	Purchase	and	Sale	Facility

On	July	1,	2005,	MPC	entered	into	a	$200	million,	three-year	Receivables	Purchase	and	Sale	Agreement	with	certain	purchasers.	The	program	was	structured	to	allow MPC	to	periodically	sell	a	participating	interest	in	pools	of	eligible	accounts	receivable.	During	2006,	the	facility	was	terminated.	No	receivables	were	sold	under	the agreement	during	its	term.

# 23.	Supplemental	Cash	Flow	Information

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Net\tcash\tprovided\tfrom\toperating\tactivities\tfrom\tcontinuing\toperations\tincluded: |  |  |  |
| Interest\tpaid\t(net\tof\tamounts\tcapitalized) | $96 | $174 | $206 |
| Income\ttaxes\tpaid\tto\ttaxing\tauthorities | 4,149 | 1,528 | 672 |
| Income\ttax\tsettlements\tpaid\tto\tUnited\tStates\tSteel | 35 | 6 | 3 |
| Commercial\tpaper\tand\trevolving\tcredit\tarrangements,\tnet: |  |  |  |
| Commercial\tpaper\t–\tissuances | $1,321 | $3,896 | $– |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\trepayments | (1,321) | (3,896) | – |
| Credit\tagreements\t–\tborrowings | – | 10 | – |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\trepayments | – | (10) | – |
| Ashland\tcredit\tagreements\t–\tborrowings | – | – | 653 |
| \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–\trepayments | – | – | (653) |
| Total | $– | $– | $– |
| Noncash\tinvesting\tand\tfinancing\tactivities: |  |  |  |
| Asset\tretirement\tcosts\tcapitalized | $286 | $171 | $66 |
| Debt\tpayments\tassumed\tby\tUnited\tStates\tSteel | 24 | 44 | 13 |
| Capital\tlease\tobligations: |  |  |  |
| Assets\tacquired | 1 | 18 | – |
| Net\tassets\tcontributed\tto\tjoint\tventures | – | 7 | 3 |
| Acquisitions: |  |  |  |
| Debt\tand\tother\tliabilities\tassumed | 26 | 4,161 | – |
| Common\tstock\tissued\tto\tseller | – | 955 | – |
| Receivables\ttransferred\tto\tseller | – | 911 | – |
| Disposal\tof\tassets: |  |  |  |
| Asset\tretirement\tobligations\tassumed\tby\tbuyer | 9 | 6 | – |

# 24.	Defined	Benefit	and	Other	Postretirement	Plans

Marathon	has	noncontributory	defined	benefit	pension	plans	covering	substantially	all	domestic	employees	as	well	as	international	employees	located	in	Ireland, Norway	and	the	United	Kingdom.	Benefits	under	these	plans	are	based	primarily	on	years	of	service	and	final	average	pensionable	earnings.	Marathon	adopted	SFAS No.	158,	which	applies	to	such	plans,	prospectively	as	of	December	31,	2006.

								Marathon	also	has	defined	benefit	plans	for	other	postretirement	benefits	covering	most	employees.	Health	care	benefits	are	provided	through	comprehensive hospital,	surgical	and	major	medical	benefit	provisions	subject	to	various	cost	sharing	features.	Life	insurance	benefits	are	provided	to	certain	nonunion	and	union- represented	retiree	beneficiaries.	Other	postretirement	benefits	have	not	been	funded	in	advance.

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

|  | U.S. |  | Int'l | U.S. | Int'l |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Change\tin\tbenefit\tobligations |  |  |  |  |  |  |  |  |
| Benefit\tobligations\tat\tJanuary\t1 | $2,055 |  | $338 | $1,750 | $322 | $776 |  | $697 |
| Service\tcost | 117 |  | 17 | 109 | 11 | 23 |  | 20 |
| Interest\tcost | 113 |  | 17 | 104 | 16 | 42 |  | 38 |
| Actuarial\t(gain)\tloss | (207) | (a) | 15 | 187(b) | (6) | 9 |  | 40(b) |
| Plan\tamendment | 117(c) | 117(c) | – | – | – | – |  | 10 |
| (d) |  |  |  |  |  |  |  |  |
| Mergers\tand\tacquisitions | – |  | – | 2 | – | – |  | 2 |
| Benefits\tpaid | (118) |  | (6) | (97) | (5) | (29) | (e) | (31) |
| Benefit\tobligations\tat\tDecember\t31 | $2,077 |  | $381 | $2,055 | $338 | $821 |  | $776 |
| Change\tin\tplan\tassets |  |  |  |  |  |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tJanuary\t1 | $1,025 |  | $222 | $949 | $185 |  |  |  |
| Actual\treturn\ton\tplan\tassets | 175 |  | 56 | 45 | 16 |  |  |  |
| Employer\tcontributions | 606 |  | 29 | 128 | 26 |  |  |  |
| Benefits\tpaid\tfrom\tplan\tassets | (118) |  | (6) | (97) | (5) |  |  |  |
| Fair\tvalue\tof\tplan\tassets\tat\tDecember\t31 | $1,688 |  | $301 | $1,025 | $222 |  |  |  |
| Funded\tstatus\tof\tplans\tat\tDecember\t31,\t2006 | $(389) |  | $(80) |  |  | $(821) |  |  |
| Amounts\trecognized\tin\tthe\tconsolidated\tbalance\tsheet: |  |  |  |  |  |  |  |  |
| Current\tliabilities | $(8) |  | $(1) |  |  | $(36) |  |  |
| Noncurrent\tliabilities | (381) |  | (79) |  |  | (785) |  |  |
| Accrued\tbenefit\tcost | $(389) |  | $(80) |  |  | $(821) |  |  |
| Pretax\tamounts\trecognized\tin\taccumulated\tother |  |  |  |  |  |  |  |  |
| (f) |  |  |  |  |  |  |  |  |
| comprehensive\tincome\tin\t2006\n: |  |  |  |  |  |  |  |  |
| Net\tloss | $338 |  | $70 |  |  | $184 |  |  |
| Prior\tservice\tcost\t(credit) | 132 |  | – |  |  | (53) |  |  |
| Funded\tstatus\tof\tplans\tat\tDecember\t31,\t2005 |  |  |  | $(1,030) | $(116) |  |  | $(776) |
| Unrecognized\tprior\tservice\tcost\t(credit) |  |  |  | 23 | – |  |  | (64) |
| Unrecognized\tnet\tloss |  |  |  | 651 | 106 |  |  | 184 |
| Accrued\tbenefit\tcost |  |  |  | $(356) | $(10) |  |  | $(656) |
| Amounts\trecognized\tin\tthe\tconsolidated\tbalance\tsheet\tat |  |  |  |  |  |  |  |  |
| December\t31,\t2005: |  |  |  |  |  |  |  |  |
| Accrued\tbenefit\tliability |  |  |  | $(520) | $(91) |  |  | $(656) |
| Intangible\tasset |  |  |  | 16 | – |  |  | – |
| Accumulated\tother\tcomprehensive\tincome,\texcluding\ttax |  |  |  |  |  |  |  |  |
| effects |  |  |  | 148 | 81 |  |  | – |
| Accrued\tbenefit\tcost |  |  |  | $(356) | $(10) |  |  | $(656) |

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

(b) Includes	the	impact	of	decreasing	the	retirement	age	assumption	by	two	years	and	increasing	the	lump	sum	election	rate	assumption	from	90	percent	to	96	percent	based	on	changing	trends	in	Marathon's experience,	which	increased	the	obligation	by	$109	million.

(c) Includes	the	impact	of	plan	design	changes	related	to	the	update	of	the	mortality	table	used	in	the	plans'	definition	of	actuarial	equivalence	and	lump	sum	calculations	and	a	20	percent	retiree	cost	of	living adjustment	for	annuitants.

(d) Includes	the	addition	of	certain	employees	of	the	maleic	anhydride	business	acquired	as	part	of	the	Acquisition.

(e) Benefits	paid	include	the	$3	million	Medicare	Subsidy	received.

(f) Excludes	amounts	related	to	LOOP	LLC,	an	equity	method	investee	with	defined	benefit	pension	and	postretirement	plans	for	which	a	net	loss	of	$6	million	is	reflected	in	accumulated	other	comprehensive income	as	a	result	of	adopting	SFAS	No.	158	as	of	December	31,	2006,	reflecting	Marathon's	51	percent	share.

								The	accumulated	benefit	obligation	for	all	defined	benefit	pension	plans	was	$1.912	billion	and	$1.748	billion	at	December	31,	2006	and	2005.	Marathon's international	subsidiaries	do	not	sponsor	any	defined	benefit	postretirement	plans	other	than	pension	plans.

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

|  | U.S. | Int'l | U.S. | Int'l |
| :--- | :--- | :--- | :--- | :--- |
| Projected\tbenefit\tobligations | $(92) | $(354) | $(2,055) | $(338) |
| Accumulated\tbenefit\tobligations | (62) | (331) | (1,435) | (313) |
| Fair\tvalue\tof\tplan\tassets | – | 278 | 1,025 | 222 |

								On	June	30,	2005,	as	a	result	of	the	Acquisition,	MPC's	defined	benefit	pension	and	other	postretirement	plan	obligations	were	remeasured	using	current	discount rates	and	plan	assumptions.	The	discount	rate	was	decreased	to	5.25	percent	from	5.75	percent.	As	part	of	the	application	of	the	purchase	method	of	accounting,	MPC recognized	38	percent	of	its	unrecognized	net	transition	gain,	prior	service	costs	and	actuarial	losses	related	to	its	defined	benefit	pension	and	other	postretirement	plans. As	a	result,	obligations	related	to	the	defined	benefit	pension	and	other	postretirement	plans	increased	by	$264	million	and	$28	million.

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

|  | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Components\tof\tnet\tperiodic\tbenefit\tcost: |  |  |  |  |  |  |  |  |  |
| Service\tcost | $117 | $17 | $109 | $11 | $94 | $9 | $23 | $20 | $18 |
| Interest\tcost | 113 | 17 | 104 | 16 | 95 | 14 | 42 | 38 | 42 |
| Expected\treturn\ton\tplan\tassets | (103) | (15) | (83) | (12) | (84) | (10) | – | – | – |
| Amortization\t–\tnet\ttransition\tgain | – | – | (3) | – | (4) | – | – | – | – |
| \t\t\t\t–\tprior\tservice\tcost\t(credit) | 8 | – | 4 | – | 4 | – | (11) | (12) | (14) |
| \t\t\t\t–\tactuarial\tloss | 34 | 7 | 47 | 8 | 39 | 7 | 9 | 7 | 11 |
| Multi-employer\tand\tother\tplans | 2 | – | 2 | – | 2 | – | 3 | 3 | 3 |
| Settlement,\tcurtailment\tand\ttermination\tlosses |  |  |  |  |  |  |  |  |  |
| (a) |  |  |  |  |  |  |  |  |  |
| (gains) | – | – | – | – | 37 | – | – | – | (9) |
| Net\tperiodic\tbenefit\tcost | $171 | $26 | $180 | $23 | $183 | $20 | $66 | $56 | $51 |

|  | U.S. | Int'l | U.S. | Int'l |
| :--- | :--- | :--- | :--- | :--- |
| Increase\t(decrease)\tin\tminimum\tliability\tincluded\tin\tother\tcomprehensive\tincome,\texcluding\ttax\teffects\tand\nminority\tinterest | $81 | $10 | $(18) | $(13) |

								The	estimated	net	loss	and	prior	service	cost	for	the	defined	benefit	pension	plans	that	will	be	amortized	from	accumulated	other	comprehensive	income	into	net periodic	benefit	cost	in	2007	are	$21	million	and	$13	million.	The	estimated	net	loss	and	prior	service	credit	for	the	other	defined	benefit	postretirement	plans	that	will be	amortized	from	accumulated	other	comprehensive	income	into	net	periodic	benefit	cost	in	2007	are	$11	million	and	$10	million.

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

|  | U.S. | Int'l | U.S. | Int'l | U.S. | Int'l |  |  |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Weighted-average\tassumptions\tused\tto\tdetermine\tbenefit |  |  |  |  |  |  |  |  |  |
| obligation\tat\tDecember\t31: |  |  |  |  |  |  |  |  |  |
| Discount\trate | 5.80% | 5.20% | 5.50% | 4.70% | 5.75% | 5.30% | 5.90% | 5.75% | 5.75% |
| Rate\tof\tcompensation\tincrease | 4.50% | 4.75% | 4.50% | 4.55% | 4.50% | 4.60% | 4.50% | 4.50% | 4.50% |
| Weighted\taverage\tactuarial\tassumptions\tused\tto\tdetermine\tnet |  |  |  |  |  |  |  |  |  |
| periodic\tbenefit\tcost\tfor\tyears\tended\tDecember\t31: |  |  |  |  |  |  |  |  |  |
| (a) |  |  |  |  |  |  |  |  |  |
| Discount\trate | 5.70% | 4.70% | 5.57% | 5.30% | 6.25% | 5.40% | 5.75% | 5.57% | 6.25% |
| Expected\tlong-term\treturn\ton\tplan\tassets | 8.50% | 6.07% | 8.50% | 6.87% | 9.00% | 6.87% |  |  |  |
| Rate\tof\tcompensation\tincrease |  |  |  |  |  |  |  |  |  |
|  | 4.50% | 4.55% | 4.50% | 4.60% | 4.50% | 4.50% | 4.50% | 4.50% | 4.50% |

(a) On	July	31,	2006,	due	to	an	interim	remeasurement,	the	discount	rate	for	the	U.S.	pension	plans	was	increased	to	6.00	percent	from	5.50	percent.	Also,	on	June	30,	2005	due	to	the	Acquisition,	the	discount	rate for	the	MPC	pension	plan	was	decreased	to	5.25	percent	from	5.75	percent.

# Expected	long-term	return	on	plan	assets

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

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

Assumed	health	care	cost	trend	–	The	following	summarizes	the	assumed	health	care	cost	trend	rates.

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

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

# Plan	investment	policies	and	strategies

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

								International	Plans	–	The	objective	of	the	investment	policy	is	to	achieve	a	long-term	return	which	is	consistent	with	assumptions	made	by	the	actuary	in determining	the	funding	requirements	of	the	plans.	The	target	asset	allocation	is	approximately	75	percent	equity	securities	and	25	percent	debt	securities.	The	day-to- day	management	of

the	plans'	assets	is	delegated	to	several	professional	investment	managers.	The	spread	of	assets	by	type	and	the	investment	managers'	policies	on	investing	in	individual securities	within	each	type	provide	adequate	diversification	of	investments.	The	use	of	derivatives	by	the	investment	managers	is	permitted	and	plan	specific,	subject	to strict	guidelines.	Investment	performance	and	risk	is	measured	and	monitored	on	an	ongoing	basis	through	quarterly	investment	portfolio	reviews	and	periodic	asset	and liability	studies.

								Plan	Contributions	–	Marathon	expects	to	make	contributions	to	the	Company's	funded	pension	plans	of	approximately	$50	million	in	2007.	Cash	contributions	to be	paid	from	the	general	assets	of	the	Company	for	the	unfunded	pension	and	postretirement	benefit	plans	are	expected	to	be	approximately	$8	million	and	$41	million in	2007.

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

|  | U.S. | Int'l |  |
| :--- | :--- | :--- | :--- |
| 2007 | $151 | $6 | $41 |
| 2008 | 166 | 7 | 44 |
| 2009 | 182 | 8 | 48 |
| 2010 | 195 | 9 | 52 |
| 2011 | 208 | 11 | 56 |
| 2012\tthrough\t2016 | 1,235 | 75 | 329 |

(a) Expected	Medicare	reimbursements	for	2007	through	2016	total	$64	million.

								Other	Plan	Contributions	–	Marathon	also	contributes	to	several	defined	contribution	plans	for	eligible	employees.	Contributions	to	these	plans	totaled	$47	million in	2006,	$39	million	in	2005	and	$35	million	in	2004.

# 25.	Asset	Retirement	Obligations

								The	following	summarizes	the	changes	in	asset	retirement	obligations:

|  | 2006 | 2005 |
| :--- | :--- | :--- |
| Asset\tretirement\tobligations\tas\tof\tJanuary\t1 | $711 | $477 |
| Liabilities\tincurred | 29 | 20 |
| Liabilities\tsettled | (16) | (9) |
| Accretion\texpense\t(included\tin\tdepreciation,\tdepletion\tand\tamortization) | 43 | 29 |
| Adoption\tof\tFIN\tNo.\t47 | – | 53 |
| Revisions\tof\tprevious\testimates | 277 | 141 |
| Asset\tretirement\tobligations\tas\tof\tDecember\t31 | $1,044 | $711 |

# 26.	Stock-Based	Compensation	Plans

								Description	of	the	plans	–	The	Marathon	Oil	Corporation	2003	Incentive	Compensation	Plan	(the	"Plan")	authorizes	the	Compensation	Committee	of	the	Board	of Directors	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.	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,	settled	in	cash, exchanged	for	other	awards,	tendered	to	satisfy	the	purchase	price	of	an	award	or	withheld	to	satisfy	tax	obligations	or	that	expire	unexercised	or	otherwise	lapse	become available	for	future	grants.	Shares	issued	as	a	result	of	awards	granted	under	the	Plan	are	generally	funded	out	of	common	stock	held	in	treasury,	except	to	the	extent there	are	insufficient	treasury	shares,	in	which	case	new	common	shares	are	issued.

								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	(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-based	awards	under	the	Plan

								Stock	options	–	Marathon	grants	stock	options	under	the	Plan.	Marathon's	stock	options	represent	the	right	to	purchase	shares	of	common	stock	at	the	fair	market value	of	the	common	stock	on	the	date	of	grant.	Through	2004,	certain	options	were	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	the	shares.	Most	stock	options	granted	under	the	Plan	vest	ratably	over	a	three-year	period	and	have	a	maximum	term	of	ten	years	from	the	date	they	are granted.

								Stock	appreciation	rights	–	Prior	to	2005,	Marathon	granted	SARs	under	the	Plan.	Similar	to	stock	options,	stock	appreciation	rights	represent	the	right	to	receive	a payment	equal	to	the	excess	of	the	fair	market	value	of	shares	of	common	stock	on	the	date	the	right	is	exercised	over	the	grant	price.	Certain	SARs	were	granted	as stock-settled	SARs	and	others	were	granted	in	tandem	with	stock	options.	In	general,	SARs	that	have	been	granted	under	the	Plan	vest	ratably	over	a	three-year	period and	have	a	maximum	term	of	ten	years	from	the	date	they	are	granted.

								Stock-based	performance	awards	–	In	2003	and	2004,	the	Compensation	Committee	granted	stock-based	performance	awards	to	certain	officers	of	Marathon	and its	consolidated	subsidiaries	under	the	Plan.	Beginning	in	2005,	Marathon	discontinued	granting	stock-based	performance	awards	and	instead	grants	cash-settled performance	units	to	officers.	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	will vest	at	the	end	of	a	36-month	performance	period	to	the	extent	that	the	performance	targets	are	achieved	and	the	recipient	is	employed	by	Marathon	on	that	date. Additional	shares	could	be	granted	at	the	end	of	this	performance	period	should	performance	exceed	the	targets.	Prior	to	vesting,	the	recipients	have	the	right	to	vote	and receive	dividends	on	the	target	number	of	shares	awarded.	However,	the	shares	are	not	transferable	until	after	they	vest.

								Restricted	stock	–	Marathon	grants	restricted	stock	and	restricted	stock	units	under	the	Plan.	In	2005,	the	Compensation	Committee	began	granting	time-based restricted	stock	to	officers	as	part	of	their	annual	long-term	incentive	package.	The	restricted	stock	awards	to	officers	vest	three	years	from	the	date	of	grant,	contingent on	the	recipient's	continued	employment.	Marathon	also	grants	restricted	stock	to	certain	non-officer	employees	and	restricted	stock	units	to	certain	international	non- officer	employees	(together	with	the	restricted	stock	granted	to	officers	above,	"restricted	stock	awards")	based	on	their	performance	within	certain	guidelines	and	for retention	purposes.	The	restricted	stock	awards	to	non-officers	generally	vest	in	one-third	increments	over	a	three-year	period,	contingent	on	the	recipient's	continued employment.	Prior	to	vesting,	all	restricted	stock	recipients	have	the	right	to	vote	such	stock	and	receive	dividends	thereon.	The	non-vested	shares	are	not	transferable and	are	held	by	the	Company's	transfer	agent.

								Common	stock	units	–	Marathon	maintains	an	equity	compensation	program	for	its	non-employee	directors	under	the	Plan.	All	non-employee	directors	other	than the	Chairman	receive	annual	grants	of	common	stock	units	under	the	Plan	and	they	are	required	to	hold	those	units	until	they	leave	the	Board	of	Directors.	When dividends	are	paid	on	Marathon	common	stock,	directors	receive	dividend	equivalents	in	the	form	of	additional	common	stock	units.	Prior	to	January	1,	2006,	non- employee	directors	had	the	opportunity	to	receive	a	matching	grant	of	up	to	1,000	shares	of	common	stock	if	they	purchased	an	equivalent	number	of	shares	within 60	days	of	joining	the	Board.

Stock-based	compensation	expense		–		Total	employee	stock-based	compensation	expense	was	$83	million,	$111	million	and	$61	million	in	2006,	2005	and	2004.	The total	related	income	tax	benefits	were	$31	million,	$39	million	and	$22	million.	In	2006,	cash	received	upon	exercise	of	stock	option	awards	was	$50	million.	Tax benefits	realized	for	deductions	during	2006	that	were	in	excess	of	the	stock-based	compensation	expense	recorded	for	options	exercised	and	other	stock-based	awards vested	during	the	period	totaled	$36	million.	Cash	settlements	of	stock	option	awards	totaled	$3	million	in	2006.

Stock	option	awards	granted		–		During	2006,	2005	and	2004,	Marathon	granted	stock	option	awards	to	both	officer	and	non-officer	employees.	The	weighted	average grant	date	fair	values	of	these	awards	were	based	on	the	following	Black-Scholes	assumptions:

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Weighted\taverage\texercise\tprice\tper\tshare | $75.68 | $50.28 | $33.61 |
| Expected\tannual\tdividends\tper\tshare | $1.60 | $1.32 | $1.00 |
| Expected\tlife\tin\tyears | 5.1 | 5.5 | 5.5 |
| Expected\tvolatility | 28% | 28% | 32% |
| Risk-free\tinterest\trate | 5.0% | 3.8% | 3.9% |
| Weighted\taverage\tgrant\tdate\tfair\tvalue\tof\tstock\toption\tawards\tgranted | $20.37 | $12.30 | $8.83 |

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

|  | Number<br>of	Shares | Average<br>Exercise	Price |
| :--- | :--- | :--- |
| Outstanding\tat\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 |
| Outstanding\tat\tDecember\t31,\t2004 | 8,013,248 | 29.84 |
| Granted | 1,894,720 | 50.28 |
| Exercised | (3,786,828) | 29.37 |
| Canceled | (113,186) | 33.96 |
| Outstanding\tat\tDecember\t31,\t2005 | 6,007,954 | 36.51 |
| Granted | 1,601,800 | 75.68 |
| Exercised | (2,018,629) | 23.22 |
| Canceled | (95,630) | 51.42 |
| (a)\nOutstanding\tat\tDecember\t31,\t2006 | 5,495,495 | 49.43 |

(a) Of	the	stock	option	awards	outstanding	as	of	December	31,	2006,	5,076,185	and	419,310	were	outstanding	under	the	2003	Incentive	Compensation	Plan	and	1990	Stock	Plan,	including	489,691	stock	options with	tandem	SARs.

								The	intrinsic	value	of	stock	option	awards	exercised	during	2006,	2005	and	2004	was	$107	million,	$90	million	and	$27	million.	Of	those	amounts,	$32	million, $61	million	and	$19	million	relate	to	stock	options	with	tandem	SARs.

								The	following	table	presents	information	on	stock	option	awards	at	December	31,	2006:

| Range	of<br>Exercise	Prices | Number<br>of	Shares<br>Under<br>Option | Weighted-Average<br>Remaining<br>Contractual	Life |  | Weighted-Average<br>Exercise	Price | Number<br>of	Shares<br>Under<br>Option | Weighted-Average<br>Exercise	Price |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| $25.50\t–\t26.91 | 556,450 |  | 6 | $25.53 | 556,450 | $25.53 |
| $28.12\t–\t30.88 | 189,685 |  | 5 | 28.39 | 189,685 | 28.39 |
| $32.52\t–\t34.00 | 1,596,430 |  | 7 | 33.51 | 949,555 | 33.44 |
| $47.65\t–\t51.67 | 1,568,630 |  | 8 | 50.13 | 379,244 | 49.75 |
| $75.64\t–\t81.02 | 1,584,300 |  | 9 | 75.68 | – | – |
| Total | 5,495,495 |  | 8 | 49.43 | 2,074,934 | 33.84 |

								As	of	December	31,	2006,	the	aggregate	intrinsic	value	of	stock	option	awards	outstanding	was	$237	million.	The	aggregate	intrinsic	value	and	weighted	average remaining	contractual	life	of	stock	option	awards	currently	exercisable	were	$122	million	and	7	years.	As	of	December	31,	2006,	the	number	of	fully-vested	stock option	awards	and	stock	option	awards	expected	to	vest	was	5,061,806.	The	weighted	average	exercise	price	and	weighted	average	remaining	contractual	life	of	these stock	option	awards	were	$48.52	and	8	years	and	the	aggregate	intrinsic	value	was	$223	million.	As	of	December	31,	2006,	unrecognized	compensation	cost	related	to stock	option	awards	was	$32	million,	which	is	expected	to	be	recognized	over	a	weighted	average	period	of	2	years.

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

|  | Stock-Based<br>Performance<br>Awards | Weighted	Average<br>Grant	Date	Fair<br>Value | Restricted<br>Stock	Awards | Weighted	Average<br>Grant	Date	Fair<br>Value |
| :--- | :--- | :--- | :--- | :--- |
| Unvested\tat\tDecember\t31,\t2005 | 448,600 | $29.93 | 985,556 | $47.94 |
| Granted | 67,848(a) | 76.82 | 218,980 | 80.90 |
| Vested | (273,448) | 38.30 | (388,597) | 41.18 |
| Forfeited | (6,000) | 33.61 | (39,790) | 53.10 |
| Unvested\tat\tDecember\t31,\t2006 | 237,000 | 33.61 | 776,149 | 60.42 |

(a) Additional	shares	were	issued	in	2006	because	the	performance	targets	were	exceeded	for	the	36-month	performance	period	related	to	the	2003	grant.

								During	2006,	2005	and	2004	the	weighted	average	grant	date	fair	value	of	restricted	stock	awards	was	$80.90,	$54.41	and	$36.55.	During	2004,	the	weighted average	grant	date	fair	value	of	stock-based	performance	awards	was	$33.61.	The	vesting	date	fair	value	of	stock-based	performance	awards	which	vested	during	2006, 2005	and	2004	was	$21	million,	$5	million	and	$4	million.	The	vesting	date	fair	value	of	restricted	stock	awards	which	vested	during	2006,	2005	and	2004	was $32	million,	$13	million	and	$7	million.

								As	of	December	31,	2006,	there	was	$29	million	of	unrecognized	compensation	cost	related	to	stock-based	performance	awards	and	restricted	stock	awards	which is	expected	to	be	recognized	over	a	weighted	average	period	of	two	years.

On	January	29,	2006,	Marathon's	Board	of	Directors	authorized	the	repurchase	of	up	to	$2	billion	of	common	stock.	As	of	December	31,	2006,	the	Company	had acquired	20.7	million	common	shares	at	a	cost	of	$1.698	billion.	On	January	28,	2007,	Marathon's	Board	of	Directors	authorized	an	extension	of	the	share	repurchase program	by	an	additional	$500	million.	Purchases	under	the	program	may	be	in	either	open	market	transactions,	including	block	purchases,	or	in	privately	negotiated transactions.	The	Company	will	use	cash	on	hand,	cash	generated	from	operations	or	cash	from	available	borrowings	to	acquire	shares.	This	program	may	be	changed based	upon	our	financial	condition	or	changes	in	market	conditions	and	is	subject	to	termination	prior	to	completion.

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 |
| :--- | :--- | :--- |
| 2007 | $36 | $159 |
| 2008 | 27 | 160 |
| 2009 | 27 | 136 |
| 2010 | 28 | 101 |
| 2011 | 27 | 68 |
| Later\tyears | 71 | 259 |
| Sublease\trentals | – | (32) |
| Total\tminimum\tlease\tpayments | 216 | $851 |

								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	$31	million	have	been included	above	and	an	equal	amount	has	been	reported	as	sublease	rentals.

								Of	the	$163	million	present	value	of	net	minimum	capital	lease	payments,	$104	million	was	related	to	obligations	assumed	by	United	States	Steel	under	the Financial	Matters	Agreement.	Of	the	$851	million	total	minimum	operating	lease	payments,	$3	million	was	assumed	by	United	States	Steel	under	the	Financial	Matters Agreement.

								Operating	lease	rental	expense	was:

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Minimum\trental | $197(a) | $165(a) | $168(a) |
| Contingent\trental | 28 | 21 | 15 |
| Sublease\trentals | (7) | (14) | (12) |
| Net\trental\texpense | $218 | $172 | $171 |

# 29.	Sale	of	Minority	Interests	in	EGHoldings

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

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

# 30.	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,	2006	and	2005,	accrued	liabilities	for	remediation	totaled	$101	million	and	$103	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	$66	million	and	$68	million	at	December	31,	2006 and	2005.

								On	May	11,	2001,	MPC	entered	into	a	consent	decree	with	the	U.S.	Environmental	Protection	Agency	which	commits	it	to	complete	certain	agreed	upon environmental	projects	over	an	eight-year	period	primarily	aimed	at	reducing	air	emissions	at	its	seven	refineries.	The	court	approved	this	consent	decree	on	August	28, 2001.	The	total	one-time	expenditures	for	these	environmental	projects	are	estimated	to	be	approximately	$425	million	over	the	eight-year	period,	with	about $365	million	incurred	through	December	31,	2006.	In	addition,	MPC	has	been	working	on	certain	agreed	upon	supplemental	environmental	projects	as	part	of	this settlement	of	an	enforcement	action	for	alleged	CAA	violations	and	these	have	been	substantially	completed.

# Guarantees		–		Marathon	has	issued	the	following	guarantees:

|  |  | Maximum	Potential |
| :--- | :--- | :--- |
| (In\tmillions) | Term | Undiscounted\tPayments\nas\tof\tDecember\t31,\t2006 |
| Indebtedness\tof\tequity\tmethod\tinvestees: |  |  |
| (a) |  |  |
| LOOP | Through\t2024 | $160 |
| (a) |  |  |
| LOCAP | Perpetual-Loan\tBalance\tVaries | 23 |
| (b) |  |  |
| Centennial | Through\t2024 | 75 |
| Guarantees/indemnifications\trelated\tto\tasset\tsales: |  |  |
| (c) |  |  |
| Russia | Indefinite | 843 |
| (d) |  |  |
| Yates | Indefinite | 228 |
| (e) |  |  |
| Canada | Indefinite | 568 |
| (f) |  |  |
| Miscellaneous\tasset\tsales | Indefinite | 68 |
| Other: |  |  |
| (g) |  |  |
| United\tStates\tSteel | Through\t2012 | 680 |
| (h) |  |  |
| Centennial\tPipeline\tcatastrophic\tevent | Indefinite | 50 |
| (i) |  |  |
| Alliance\tPipeline | Through\t2015 | 59 |
| (j) |  |  |
| Kenai\tKachemak\tPipeline\tLLC | Through\t2017 | 15 |
| (k) |  |  |
| Corporate\tassets | (k) | 29 |

(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	agreements.	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.	Included	in	the	underlying	debt	are	a	LOOP	revolving	credit	facility	of	$25	million	and	a	LOCAP revolving	credit	facility	of	$23	million.

(b) Marathon	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,	Marathon	could	be	relinquished from	responsibility	under	the	guarantee	should	Centennial	meet	certain	financial	tests.

(c) In	conjunction	with	the	sale	of	its	Russian	businesses	as	discussed	in	Note	7,	Marathon	guaranteed	the	purchaser	with	regard	to	unknown	obligations	and	inaccuracies	in	representations,	warranties,	covenants and	agreements	by	Marathon.	These	indemnifications	are	part	of	the	normal	course	of	selling	assets.	Under	the	agreement,	the	maximum	potential	amount	of	future	payments	associated	with	these	guarantees	is equivalent	to	the	proceeds	from	the	sale.

(d) In	2003,	Marathon	sold	its	interest	in	the	Yates	field	and	gathering	system.	In	accordance	with	this	transaction,	Marathon	indemnified	the	purchaser	from	inaccuracies	in	Marathon's	representations,	warranties, covenants	and	agreements.

(e) In	conjunction	with	the	sale	of	certain	Canadian	assets	during	2003,	Marathon	guaranteed	the	purchaser	with	regards	to	unknown	environmental	obligations	and	inaccuracies	in	Marathon's	representations, warranties,	covenants	and	agreements.

(f) Marathon	entered	into	certain	performance	and	general	guarantees	and	environmental	and	general	indemnifications	in	connection	with	certain	asset	sales.

(g) 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's	product	sales	fail	to	qualify	for	the	credit	under	Section	29	of	the	Internal	Revenue	Code.	United	States	Steel	has	estimated the	maximum	potential	amount	of	this	indemnity	obligation,	including	interest	and	tax	gross-up,	was	approximately	$680	million.	Furthermore,	United	States	Steel	under	certain	circumstances	has	indemnified the	partnership	for	environmental	obligations.

(h) 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.	Each	member	is	to	contribute	cash	in	proportion	to	its	ownership	interest.

(i) 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	$7	million through	2015.	The	payments	are	required	even	if	the	transportation	facility	is	not	utilized.	This	contract	has	been	used	by	Alliance	to	secure	its	financing.	As	a	result	of	the	Canadian	asset	sale	discussed	above, Husky	has	indemnified	Marathon	for	any	claims	related	to	these	guarantees.

(j) Marathon	is	an	equity	investor	in	Kenai	Kachemak	Pipeline	LLC	("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.

(k) Marathon	has	entered	into	leases	of	corporate	assets	containing	general	lease	indemnities	and	guaranteed	residual	value	clauses.

Contract	commitments		–		At	December	31,	2006	and	2005,	Marathon's	contract	commitments	to	acquire	property,	plant	and	equipment	totaled	$1.703	billion	and $668	million.	The	$1.035	billion	increase	is	primarily	due	to	commitments	related	to	the	Garyville	refinery	expansion.

Agreements	with	joint	owners		–		As	part	of	the	formation	of	PTC,	MPC	and	Pilot	Corporation	("Pilot")	entered	into	a	Put/Call	and	Registration	Rights	Agreement	(the "Agreement").	The	Agreement	provides	that	any	time	after

September	1,	2008,	Pilot	will	have	the	right	to	sell	its	interest	in	PTC	to	MPC	for	an	amount	of	cash	and/or	Marathon,	MPC	or	Ashland	equity	securities	equal	to	the product	of	90	percent	(95	percent	if	paid	in	securities)	of	the	fair	market	value	of	PTC	at	the	time	multiplied	by	Pilot's	percentage	interest	in	PTC.	At	any	time	after September	1,	2011,	under	certain	conditions,	MPC	will	have	the	right	to	purchase	Pilot's	interest	in	PTC	for	an	amount	of	cash	and/or	Marathon,	MPC	or	Ashland	equity securities	equal	to	the	product	of	105	percent	(110	percent	if	paid	in	securities)	of	the	fair	market	value	of	PTC	at	the	time	multiplied	by	Pilot's	percentage	interest	in PTC.	Under	the	Agreement,	MPC	would	determine	the	form	of	consideration	to	be	paid	upon	exercise	of	the	rights.

Other	contingencies		–		In	November	2006,	the	government	of	Equatorial	Guinea	enacted	a	new	hydrocarbon	law	governing	petroleum	operations	in	Equatorial	Guinea. The	transitional	provision	of	the	law	provides	that	all	contractors	and	the	terms	of	any	contract	to	which	they	are	a	party	will	be	subject	to	the	law.	The	governmental agency	responsible	for	the	energy	industry	was	given	the	authority	to	renegotiate	any	contract	for	the	purpose	of	adapting	any	terms	and	conditions	that	are	inconsistent with	the	new	law.	Marathon	is	in	the	process	of	determining	what	impact	this	law	may	have	on	its	existing	operations	in	Equatorial	Guinea.

In	February	2007,	the	FASB	issued	SFAS	No.	159,	"The	Fair	Value	Option	for	Financial	Assets	and	Financial	Liabilities."	This	statement	permits	entities	to	choose	to measure	many	financial	instruments	and	certain	other	items	at	fair	value	that	are	not	currently	required	to	be	measured	at	fair	value.	It	requires	that	unrealized	gains	and losses	on	items	for	which	the	fair	value	option	has	been	elected	be	recorded	in	net	income.	The	statement	also	establishes	presentation	and	disclosure	requirements designed	to	facilitate	comparisons	between	entities	that	choose	different	measurement	attributes	for	similar	types	of	assets	and	liabilities.	For	Marathon,	SFAS	No.	159 will	be	effective	January	1,	2008,	and	retrospective	application	is	not	permitted.	Should	Marathon	elect	to	apply	the	fair	value	option	to	any	eligible	items	that	exist	at January	1,	2008,	the	effect	of	the	first	remeasurement	to	fair	value	would	be	reported	as	a	cumulative	effect	adjustment	to	the	opening	balance	of	retained	earnings. Marathon	is	currently	evaluating	the	provisions	of	this	statement.

								In	September	2006,	the	FASB	issued	SFAS	No.	157,	"Fair	Value	Measurements."	This	statement	defines	fair	value,	establishes	a	framework	for	measuring	fair value	in	generally	accepted	accounting	principles	and	expands	disclosures	about	fair	value	measurements.	SFAS	No.	157	does	not	require	any	new	fair	value measurements	but	may	require	some	entities	to	change	their	measurement	practices.	For	Marathon,	SFAS	No.	157	will	be	effective	January	1,	2008,	with	early application	permitted.	Marathon	is	currently	evaluating	the	provisions	of	this	statement.

								In	September	2006,	the	FASB	issued	FASB	Staff	Position	("FSP")	No.	AUG	AIR-1,	"Accounting	for	Planned	Major	Maintenance	Activities."	This	FSP	prohibits the	use	of	the	accrue-in-advance	method	of	accounting	for	planned	major	maintenance	activities	in	annual	and	interim	financial	reporting	periods.	Marathon	expenses such	costs	in	the	same	annual	period	as	incurred;	however,	estimated	annual	major	maintenance	costs	are	recognized	as	expense	throughout	the	year	on	a	pro	rata	basis. As	such,	adoption	of	FSP	No.	AUG	AIR-1	will	have	no	impact	on	Marathon's	annual	consolidated	financial	statements.	Marathon	is	required	to	adopt	the	FSP	effective January	1,	2007.	Marathon	does	not	believe	the	provisions	of	FSP	No.	AUG	AIR-1	will	have	a	significant	impact	on	its	interim	consolidated	financial	statements.

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

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

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

|  | 4th	Qtr. | 3rd	Qtr. | 2nd	Qtr. | 1st	Qtr. | 4th	Qtr. | 3rd	Qtr. | 2nd	Qtr. | 1st	Qtr. |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Revenues | $13,807 | $16,492 | $18,179 | $16,418 | $17,088 | $17,077 | $15,942 | $12,879 |
| Income\tfrom\toperations | 1,793 | 2,944 | 2,754 | 1,476 | 2,031 | 1,236 | 1,351 | 624 |
| Income\tfrom\tcontinuing\toperations | 1,079 | 1,623 | 1,484 | 771 | 1,265 | 750 | 668 | 323 |
| Discontinued\toperations | – | – | 264 | 13 | 19 | 20 | 5 | 1 |
| Income\tbefore\tcumulative\teffect\tof\tchange\tin |  |  |  |  |  |  |  |  |
| accounting\tprinciple | 1,079 | 1,623 | 1,748 | 784 | 1,284 | 770 | 673 | 324 |
| Net\tincome | 1,079 | 1,623 | 1,748 | 784 | 1,265 | 770 | 673 | 324 |
| Common\tstock\tdata |  |  |  |  |  |  |  |  |
| Net\tincome\tper\tshare: |  |  |  |  |  |  |  |  |
| –\tBasic | $3.09 | $4.55 | $4.84 | $2.15 | $3.46 | $2.11 | $1.94 | $0.94 |
| –\tDiluted | $3.06 | $4.52 | $4.80 | $2.13 | $3.43 | $2.09 | $1.92 | $0.93 |
| Dividends\tpaid\tper\tshare | $0.40 | $0.40 | $0.40 | $0.33 | $0.33 | $0.33 | $0.28 | $0.28 |
| (a) |  |  |  |  |  |  |  |  |
| Price\trange\tof\tcommon\tstock\n: |  |  |  |  |  |  |  |  |
| –\tLow | $71.94 | $70.73 | $69.83 | $65.24 | $56.28 | $54.69 | $44.00 | $35.73 |
| –\tHigh | $97.57 | $92.19 | $86.04 | $78.15 | $69.21 | $70.83 | $55.58 | $48.76 |

(a) Composite	tape

| Alba	Plant	LLC | Cayman	Islands | 52% | (a) | Liquefied	Petroleum	Gas |
| :--- | :--- | :--- | :--- | :--- |
| Atlantic\tMethanol\tProduction\tCompany\tLLC | Cayman\tIslands | 45% | 45% | Methanol\tProduction |
| Centennial\tPipeline\tLLC | United\tStates | 50% | 50% | 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\tLiquefaction |
| LOCAP\tLLC | United\tStates | 59% | (a) | Pipeline\t&amp;\tStorage\tFacilities |
| LOOP\tLLC | United\tStates | 51% | (a) | Offshore\tOil\tPort |
| Minnesota\tPipe\tLine\tCompany,\tLLC | United\tStates | 17% | 17% | Pipeline\tFacility |
| Muskegon\tPipeline\tLLC | United\tStates | 60% | (a) | Pipeline\tFacility |
| Odyssey\tPipeline\tL.L.C. | United\tStates | 29% | 29% | Pipeline\tFacility |
| Pilot\tTravel\tCenters\tLLC | United\tStates | 50% | 50% | Travel\tCenters |
| Poseidon\tOil\tPipeline\tCompany,\tL.L.C. | United\tStates | 28% | 28% | Crude\tOil\tTransportation |
| Southcap\tPipe\tLine\tCompany | United\tStates | 22% | 22% | Crude\tOil\tTransportation |

(a) Represents	a	noncontrolling	interest.

								The	supplementary	information	is	disclosed	by	the	following	geographic	areas:	the	United	States;	Europe,	which	primarily	includes	activities	in	the	United Kingdom,	Ireland	and	Norway;	Africa,	which	primarily	includes	activities	in	Angola,	Equatorial	Guinea,	Gabon	and	Libya;	and	Other	International,	which	includes activities	in	Canada,	the	Russian	Federation	and	other	international	locations	outside	of	Europe	and	Africa.	Discontinued	operations	represent	Marathon's	Russian	oil exploration	and	production	businesses	that	were	sold	in	2006.

| (In	millions)																																																														 December	31 | United<br>States | Europe | Africa | Other<br>Int'l | Total |
| :--- | :--- | :--- | :--- | :--- | :--- |
| 2006\tCapitalized\tcosts: |  |  |  |  |  |
| Proved\tproperties | $7,682 | $7,216 | $2,319 | $1 | $17,218 |
| Unproved\tproperties | 938 | 77 | 206 | 4 | 1,225 |
| Suspended\texploratory\twells | 156 | 25 | 289 | – | 470 |
| Total | 8,776 | 7,318 | 2,814 | 5 | 18,913 |
| Accumulated\tdepreciation,\tdepletion\tand\tamortization: |  |  |  |  |  |
| Proved\tproperties | 5,141 | 4,771 | 412 | 1 | 10,325 |
| Unproved\tproperties | 42 | 1 | 9 | – | 52 |
| Total | 5,183 | 4,772 | 421 | 1 | 10,377 |
| Net\tcapitalized\tcosts | $3,593 | $2,546 | $2,393 | $4 | $8,536 |
| Share\tof\tequity\tmethod\tinvestees'\tcapitalized\tcosts | $15 | $– | $361 | $– | $376 |
| 2005\tCapitalized\tcosts: |  |  |  |  |  |
| Proved\tproperties | $7,015 | $6,349 | $1,857 | $342 | $15,563 |
| Unproved\tproperties | 428 | 107 | 573 | 193 | 1,301 |
| Suspended\texploratory\twells | 111 | 31 | 204 | 17 | 363 |
| Total | 7,554 | 6,487 | 2,634 | 552 | 17,227 |
| Accumulated\tdepreciation,\tdepletion\tand\tamortization: |  |  |  |  |  |
| Proved\tproperties | 4,752 | 4,476 | 288 | 111 | 9,627 |
| Unproved\tproperties | 27 | – | 9 | 32 | 68 |
| Total | 4,779 | 4,476 | 297 | 143 | 9,695 |
| Net\tcapitalized\tcosts | $2,775 | $2,011 | $2,337 | $409 | $7,532 |
| Share\tof\tequity\tmethod\tinvestees'\tcapitalized\tcosts | $13 | $– | $395 | $– | $408 |

(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 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2006\tProperty\tacquisition: |  |  |  |  |  |  |  |
| Proved | $4 | $– | $19 | $– | $23 | $– | $23 |
| Unproved | 526 | 3 | 3 | 4 | 536 | – | 536 |
| Exploration | 224 | 36 | 169 | 70 | 499 | 2 | 501 |
| (b)\nDevelopment | 603 | 607 | 40 | – | 1,250 | 43 | 1,293 |
| (c)\nCapitalized\tasset\tretirement\tcosts | 78 | 201 | 13 | 2 | 294 | 1 | 295 |
| Total | $1,435 | $847 | $244 | $76 | $2,602 | $46 | $2,648 |
| Share\tof\tinvestees'\tcosts\tincurred | $3 | $– | $1 | $– | $4 | $– | $4 |
| 2005\tProperty\tacquisition: |  |  |  |  |  |  |  |
| Proved | $3 | $– | $390 | $– | $393 | $– | $393 |
| Unproved | 31 | – | 381 | – | 412 | – | 412 |
| Exploration | 186 | 48 | 95 | 14 | 343 | 10 | 353 |
| (b)\nDevelopment | 465 | 531 | 32 | – | 1,028 | 85 | 1,113 |
| (c)\nCapitalized\tasset\tretirement\tcosts | 35 | 108 | 12 | 1 | 156 | 2 | 158 |
| Total | $720 | $687 | $910 | $15 | $2,332 | $97 | $2,429 |
| Share\tof\tinvestees'\tcosts\tincurred | – | – | 31 | – | 31 | – | 31 |
| 2004\tProperty\tacquisition: |  |  |  |  |  |  |  |
| Proved | $9 | $– | $3 | $– | $12 | $– | $12 |
| Unproved | 10 | – | 1 | – | 11 | – | 11 |
| Exploration | 96 | 27 | 127 | 31 | 281 | 10 | 291 |
| (b)\nDevelopment | 316 | 151 | 140 | – | 607 | 102 | 709 |
| (c)\nCapitalized\tasset\tretirement\tcosts | 14 | 49 | 5 | – | 68 | (5) | 63 |

| Total | $445 | $227 | $276 | $31 | $979 | $107 | $1,086 |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Share\tof\tinvestees'\tcosts\tincurred | $1 | $– | $128 | $– | $129 | $1 | $130 |

(a) Includes	costs	incurred	whether	capitalized	or	expensed.

(b) Includes	$12	million,	$12	million	and	$8	million	of	costs	incurred	prior	to	assignment	of	proved	reserves	in	2006,	2005	and	2004.	The	associated	reserves	were	awaiting	full	project	sanction	at	the	end	of	the applicable	year.

(c) Includes	the	effect	of	foreign	currency	fluctuations.

# Results	of	Operations	for	Oil	and	Gas	Producing	Activities

| (In	millions) | (In	millions) | United<br>States | Europe | Africa | Other<br>Int'l | Total |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| 2006\tRevenues\tand\tother\tincome: |  |  |  |  |  |  |
| Sales^(a) | Sales^(a) | $2,329 | $1,240 | $1,300 | $– | $4,869 |
| Transfers | Transfers | 307 | 58 | 1,168 | – | 1,533 |
| Other\tincome^(b) | Other\tincome^(b) | 3 | – | – | 46 | 49 |
| Total\trevenues | Total\trevenues | 2,639 | 1,298 | 2,468 | 46 | 6,451 |
| Expenses: |  |  |  |  |  |  |
| Production\tcosts | Production\tcosts | (512) | (207) | (126) | – | (845) |
| Transportation\tcosts^(c) | Transportation\tcosts^(c) | (124) | (44) | (33) | – | (202) |
| Exploration\texpenses | Exploration\texpenses | (169) | (29) | (91) | (73) | (362) |
| Depreciation,\tdepletion\tand\tamortization | Depreciation,\tdepletion\tand\tamortization | (458) | (281) | (127) | – | (866) |
| Administrative\texpenses | Administrative\texpenses | (41) | (10) | (6) | (36) | (92) |
| Total\texpenses | Total\texpenses | (1,304) | (571) | (383) | (109) | (2,367) |
| Other\tproduction-related\tincome^(d) | Other\tproduction-related\tincome^(d) | – | 73 | 1 | – | 74 |
| Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes | 1,335 | 800 | 2,086 | (63) | 4,158 |
| Income\ttax\tprovision\t(benefit) | Income\ttax\tprovision\t(benefit) | 489 | 358 | 1,457 | (4) | 2,300 |
| Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations | $846 | $442 | $629 | $(59) | $1,858 |
| Results\tof\tdiscontinued\toperations | Results\tof\tdiscontinued\toperations | $– | $– | $– | $273 | $273 |
| Share\tof\tequity\tmethod\tinvestees'\tresults\tof\toperations | Share\tof\tequity\tmethod\tinvestees'\tresults\tof\toperations | $– | $– | $118 | $– | $118 |
| 2005\tRevenues\tand\tother\tincome: |  |  |  |  |  |  |
| Sales^(a) | Sales^(a) | $2,227 | $1,136 | $71 | $– | $3,434 |
| Transfers | Transfers | 422 | 38 | 810 | – | 1,270 |
| Other\tincome^(b) | Other\tincome^(b) | 22 | – | – | – | 22 |
| Total\trevenues | Total\trevenues | 2,671 | 1,174 | 881 | – | 4,726 |
| Expenses: |  |  |  |  |  |  |
| Production\tcosts | Production\tcosts | (448) | (170) | (82) | (3) | (703) |
| Transportation\tcosts^(c) | Transportation\tcosts^(c) | (114) | (40) | (27) | – | (181) |
| Exploration\texpenses | Exploration\texpenses | (118) | (31) | (27) | (38) | (214) |
| Depreciation,\tdepletion\tand\tamortization | Depreciation,\tdepletion\tand\tamortization | (411) | (255) | (87) | – | (753) |
| Administrative\texpenses | Administrative\texpenses | (34) | (8) | (5) | (25) | (72) |
| Total\texpenses | Total\texpenses | (1,125) | (504) | (228) | (66) | (1,923) |
| Other\tproduction-related\tincome | (d) | 2 | 44 | – | – | 46 |
| Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes | 1,548 | 714 | 653 | (66) | 2,849 |
| Income\ttax\tprovision\t(benefit) | Income\ttax\tprovision\t(benefit) | 572 | 256 | 199 | (13) | 1,014 |
| Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations | $976 | $458 | $454 | $(53) | $1,835 |
| Results\tof\tdiscontinued\toperations | Results\tof\tdiscontinued\toperations | $– | $– | $– | $42 | $42 |
| Share\tof\tequity\tmethod\tinvestees'\tresults\tof\toperations | Share\tof\tequity\tmethod\tinvestees'\tresults\tof\toperations | $– | $– | $50 | $– | $50 |
| 2004\tRevenues\tand\tother\tincome: |  |  |  |  |  |  |
| (a) |  |  |  |  |  |  |
| Sales | Sales | $1,631 | $876 | $260 | $– | $2,767 |
| Transfers | Transfers | 392 | 28 | 159 | – | 579 |
| Total\trevenues | Total\trevenues | 2,023 | 904 | 419 | – | 3,346 |
| Expenses: |  |  |  |  |  |  |
| Production\tcosts | Production\tcosts | (381) | (166) | (55) | (5) | (607) |
| Transportation\tcosts | (c) | (112) | (35) | (6) | – | (153) |
| Exploration\texpenses | Exploration\texpenses | (79) | (19) | (28) | (32) | (158) |
| Depreciation,\tdepletion\tand\tamortization | Depreciation,\tdepletion\tand\tamortization | (356) | (275) | (56) | – | (687) |
| Administrative\texpenses | Administrative\texpenses | (39) | (4) | (15) | (24) | (82) |
| Total\texpenses | Total\texpenses | (967) | (499) | (160) | (61) | (1,687) |
| Other\tproduction-related\tincome | (d) | – | 15 | – | – | 15 |
| Results\tbefore\tincome\ttaxes | Results\tbefore\tincome\ttaxes | 1,056 | 420 | 259 | (61) | 1,674 |
| Income\ttax\tprovision\t(benefit) | Income\ttax\tprovision\t(benefit) | 374 | 154 | 96 | (26) | 598 |
| Results\tof\tcontinuing\toperations | Results\tof\tcontinuing\toperations | $682 | $266 | $163 | $(35) | $1,076 |
| Results\tof\tdiscontinued\toperations | Results\tof\tdiscontinued\toperations | $– | $– | $– | $(47) | $(47) |
| Share\tof\tequity\tmethod\tinvestees'\tresults\tof\toperations\tincluded\tin\tcontinuing\toperations | Share\tof\tequity\tmethod\tinvestees'\tresults\tof\toperations\tincluded\tin\tcontinuing\toperations | $1 | $– | $9 | $– | $10 |
| Share\tof\tequity\tmethod\tinvestees'\tresults\tof\toperations\tincluded\tin\tdiscontinued\toperations | Share\tof\tequity\tmethod\tinvestees'\tresults\tof\toperations\tincluded\tin\tdiscontinued\toperations | $– | $– | $– | $1 | $1 |

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

(b) Includes	net	gains	on	asset	dispositions.

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

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

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Results\tof\tcontinuing\toperations | $1,858 | $1,835 | $1,076 |
| Items\tnot\tincluded\tin\tresults\tof\tcontinuing\toil\tand\tgas\toperations,\tnet\tof\ttax: |  |  |  |
| Marketing\tincome\tand\ttechnology\tcosts | 40 | 4 | 4 |
| Income\tfrom\tequity\tmethod\tinvestments | 135 | 52 | 11 |
| Other | 1 | (4) | (1) |
| Items\tnot\tallocated\tto\tE&amp;P\tsegment\tincome: |  |  |  |
| Gain\ton\tasset\tdisposition | (31) | – | – |
| E&amp;P\tsegment\tincome | $2,003 | $1,887 | $1,090 |

# Average	Production	Costs

| (per	boe) | United<br>States | Europe | Africa | Continuing<br>Operations |
| :--- | :--- | :--- | :--- | :--- |
| 2006 | $8.51 | $8.36 | $2.78 | $6.48 |
| 2005 | 7.11 | 6.45 | 3.33 | 6.18 |
| 2004 | 5.58 | 5.39 | 3.35 | 5.25 |

(a) Computed	using	production	costs,	excluding	transportation	costs,	as	disclosed	in	the	Results	of	Operations	for	Oil	and	Gas	Producing	Activities	and	as	defined	by	the	Securities	and	Exchange	Commission. Natural	gas	volumes	were	converted	to	barrels	of	oil	equivalent	using	a	conversion	factor	of	six	mcf	of	natural	gas	to	one	barrel	of	oil.

# Average	Realizations

|  | United<br>States | Europe | Africa | Continuing<br>Operations | Discontinued<br>Operations |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (excluding\tderivative\tgains\tand\tlosses) |  |  |  |  |  |
| 2006\tLiquid\thydrocarbons\t(per\tbbl) | $54.41 | $64.02 | $59.83 | $58.63 | $38.38 |
| (a)\nNatural\tgas\t(per\tmcf) | 5.76 | 6.78 | 0.27 | 5.52 | – |
| 2005\tLiquid\thydrocarbons\t(per\tbbl) | $45.41 | $52.99 | $46.27 | $47.35 | $33.47 |
| (a)\nNatural\tgas\t(per\tmcf) | 6.42 | 5.72 | 0.25 | 5.61 | – |
| 2004:\tLiquid\thydrocarbons\t(per\tbbl) | $32.76 | $37.16 | $35.11 | $34.40 | $22.65 |
| (a)\nNatural\tgas\t(per\tmcf) | 4.89 | 4.11 | 0.25 | 4.31 | – |
| (including\tderivative\tgains\tand\tlosses) |  |  |  |  |  |
| 2006\tLiquid\thydrocarbons\t(per\tbbl) | $54.41 | $64.02 | $59.83 | $58.63 | $38.38 |
| (a)\nNatural\tgas\t(per\tmcf) | 5.77 | 6.78 | 0.27 | 5.53 | – |
| 2005\tLiquid\thydrocarbons\t(per\tbbl) | $45.41 | $52.99 | $46.27 | $47.35 | $33.47 |
| (a)\nNatural\tgas\t(per\tmcf) | 6.40 | 5.72 | 0.25 | 5.59 | – |
| 2004\tLiquid\thydrocarbons\t(per\tbbl) | $29.11 | $33.65 | $35.11 | $31.56 | $22.62 |
| (a)\nNatural\tgas\t(per\tmcf) | 4.85 | 4.11 | 0.25 | 4.28 | – |

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

# Estimated	Quantities	of	Proved	Oil	and	Gas	Reserves

								Estimates	of	the	proved	reserves	have	been	prepared	in-house	teams	of	reservoir	engineers	and	geoscience	professionals.	Reserve	estimates	are	periodically reviewed	by	Marathon's	Corporate	Reserves	Group	to	assure	that	rigorous	professional	standards	and	the	reserves	definitions	prescribed	by	the	U.S.	Securities	and Exchange	Commission	("SEC")	are	consistently	applied	throughout	the	Company.

								Proved	reserves	are	the	estimated	quantities	of	oil	and	natural	gas	that	geologic	and	engineering	data	demonstrate	with	reasonable	certainty	to	be	recoverable	in future	years	from	known	reservoirs	under	existing	economic	and	operating	conditions.	Estimates	of	proved	reserves	may	change,	either	positively	or	negatively,	as additional	information	becomes	available	and	as	contractual,	economic	and	political	conditions	change.

								Marathon's	net	proved	reserve	estimates	have	been	adjusted	as	necessary	to	reflect	all	contractual	agreements,	royalty	obligations	and	interests	owned	by	others	at the	time	of	the	estimate.	Only	reserves	that	are	estimated	to	be	recovered	during	the	term	of	the	current	contract	have	been	included	in	the	proved	reserve	estimate	unless there	is	a	clear	and	consistent	history	of	contract	extension.	Reserves	from	properties	governed	by	production	sharing	contracts	have	been	calculated	using	the "economic	interest"	method	prescribed	by	the	SEC.	Reserves	that	are	not	currently	considered	proved,	such	as	those	that	may	result	from	extensions	of	currently	proved areas	or	that	may	result	from	applying	secondary	or	tertiary	recovery	processes	not	yet	tested	and	determined	to	be	economic	are	excluded.	Purchased	natural	gas utilized	in	reservoir	management	and	subsequently	resold	is	also	excluded.	Marathon	does	not	have	any	quantities	of	oil	and	gas	reserves	subject	to	long-term	supply agreements	with	foreign	governments	or	authorities	in	which	Marathon	acts	as	producer.

								Proved	developed	reserves	are	the	quantities	of	oil	and	gas	expected	to	be	recovered	through	existing	wells	with	existing	equipment	and	operating	methods.	In some	cases,	proved	undeveloped	reserves	may	require	substantial	new	investments	in	additional	wells	and	related	facilities.	Production	volumes	shown	are	sales volumes,	net	of	any	products	consumed	during	production	activities.

| Beginning	of	year	–	2004 | 210 | 59 | 218 | 487 | 89 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| (b)\nPurchase\tof\treserves\tin\tplace | 1 | – | 2 | 3 | – |
| Revisions\tof\tprevious\testimates | (1) | 3 | 14 | 16 | (51) |
| Improved\trecovery | 1 | – | – | 1 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 9 | 60 | 1 | 70 | 7 |
| Production | (29) | (15) | (12) | (56) | (6) |
| End\tof\tyear\t–\t2004 | 191 | 107 | 223 | 521 | 39 |
| (b)\nPurchase\tof\treserves\tin\tplace | – | – | 3 | 3 | – |
| Re-entry\tto\tLibya\tconcessions | – | – | 165 | 165 | – |
| Revisions\tof\tprevious\testimates | 10 | 4 | 1 | 15 | 3 |
| Improved\trecovery | 2 | – | – | 2 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 15 | – | – | 15 | 12 |
| Production | (28) | (13) | (19) | (60) | (10) |
| (b)\nSales\tof\treserves\tin\tplace | (1) | – | – | (1) | – |
| End\tof\tyear\t–\t2005 | 189 | 98 | 373 | 660 | 44 |
| (b)\nPurchase\tof\treserves\tin\tplace | – | – | 1 | 1 | – |
| Revisions\tof\tprevious\testimates | 2 | 8 | 49 | 59 | 1 |
| Improved\trecovery | 3 | – | – | 3 | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 6 | 15 | 15 | 36 | 4 |
| Production | (28) | (13) | (41) | (82) | (4) |
| (b)\nSales\tof\treserves\tin\tplace | – | – | – | – | (45) |
| End\tof\tyear\t–\t2006 | 172 | 108 | 397 | 677 | – |
| Proved\tdeveloped\treserves: |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2004 | 193 | 47 | 120 | 360 | 31 |
| End\tof\tyear\t–\t2004 | 171 | 41 | 147 | 359 | 27 |
| End\tof\tyear\t–\t2005 | 165 | 39 | 368 | 572 | 31 |
| End\tof\tyear\t–\t2006 | 150 | 35 | 381 | 566 | – |

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

| (Billions	of	cubic	feet) | United<br>States | Europe | Africa^(a) | Continuing<br>Operations | Discontinued<br>Operations |  |
| :--- | :--- | :--- | :--- | :--- | :--- | :--- |
| Natural\tGas |  |  |  |  |  |  |
| Proved\tdeveloped\tand\tundeveloped\treserves: |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2004 | 1,635 | 484 | 665 | 2,784 |  | – |
| (b)\nPurchase\tof\treserves\tin\tplace | 1 | – | – | 1 |  | – |
| Revisions\tof\tprevious\testimates | (230) | 7 | 916 | 693 |  | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 189 | 150 | 11 | 350 |  | – |
| (c)\nProduction | (231) | (97) | (28) | (356) |  | – |
| End\tof\tyear\t–\t2004 | 1,364 | 544 | 1,564 | 3,472 |  | – |
| (b)\nPurchase\tof\treserves\tin\tplace | – | – | 24 | 24 |  | – |
| Revisions\tof\tprevious\testimates | (78) | 18 | 298 | 238 |  | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 135 | 3 | – | 138 |  | – |
| (c)\nProduction | (211) | (79) | (34) | (324) |  | – |
| (b)\nSales\tof\treserves\tin\tplace | (1) | – | – | (1) |  | – |
| End\tof\tyear\t–\t2005 | 1,209 | 486 | 1,852 | 3,547 |  | – |
| (b)\nPurchase\tof\treserves\tin\tplace | – | 4 | 8 | 12 |  | – |
| Revisions\tof\tprevious\testimates | (5) | 4 | 139 | 138 |  | – |
| Extensions,\tdiscoveries\tand\tother\tadditions | 59 | 20 | 24 | 103 |  | – |
| (c)\nProduction | (194) | (70) | (26) | (290) |  | – |
| End\tof\tyear\t–\t2006 | 1,069 | 444 | 1,997 | 3,510 |  | – |
| Proved\tdeveloped\treserves: |  |  |  |  |  |  |
| Beginning\tof\tyear\t–\t2004 | 1,067 | 421 | 528 | 2,016 |  | – |
| End\tof\tyear\t–\t2004 | 992 | 376 | 570 | 1,938 |  | – |
| End\tof\tyear\t–\t2005 | 943 | 326 | 638 | 1,907 |  | – |
| End\tof\tyear\t–\t2006 | 857 | 238 | 648 | 1,743 |  | – |

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

(b) The	net	positive	or	negative	balance	of	proved	reserves	acquired	or	relinquished	in	property	trades	within	the	same	geographic	area	is	reported	as	purchases	of	reserves	in	place	or	sales	of	reserves	in	place, respectively.

(c) Excludes	the	resale	of	purchased	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	natural	gas	relating	to	Marathon's	proved	reserves	to	the	year-end	quantities	of	those reserves.	Future	price	changes	are	considered	only	to	the	extent	provided	by	contractual	arrangements	in	existence	at	year-end.

								The	assumptions	used	to	compute	the	proved	reserve	valuation	do	not	necessarily	reflect	Marathon's	expectations	of	actual	revenues	to	be	derived	from	those reserves	or	their	present	worth.	Assigning	monetary	values	to	the	estimated	quantities	of	reserves,	described	on	the	preceding	page,	does	not	reduce	the	subjective	and ever-changing	nature	of	such	reserve	estimates.

								Additional	subjectivity	occurs	when	determining	present	values	because	the	rate	of	producing	the	reserves	must	be	estimated.	In	addition	to	uncertainties	inherent in	predicting	the	future,	variations	from	the	expected	production	rate	also	could	result	directly	or	indirectly	from	factors	outside	of	Marathon's	control,	such	as unintentional	delays	in	development,	environmental	concerns,	changes	in	prices	or	regulatory	controls.

								The	reserve	valuation	assumes	that	all	reserves	will	be	disposed	of	by	production.	However,	if	reserves	are	sold	in	place	or	subjected	to	participation	by	foreign governments,	additional	economic	considerations	could	also	affect	the	amount	of	cash	eventually	realized.

								Future	production,	transportation	and	administrative	costs	and	development	costs	are	computed	by	estimating	the	expenditures	to	be	incurred	in	developing	and producing	the	proved	oil	and	gas	reserves	at	the	end	of	the	year,	based	on	year-end	costs	and	assuming	continuation	of	existing	economic	conditions.

								Future	income	tax	expenses	are	computed	by	applying	the	appropriate	year-end	statutory	tax	rates,	with	consideration	of	future	tax	rates	already	legislated,	to	the future	pretax	net	cash	flows	relating	to	Marathon's	proved	oil	and	gas	reserves.	Oil	and	gas	related	tax	credits	and	allowances	are	recognized.

								Discount	was	derived	by	using	a	discount	rate	of	10	percent	annually.

| (In	millions)																																																														 December	31 | States | Europe | Africa | Total |
| :--- | :--- | :--- | :--- | :--- |
| 2006 |  |  |  |  |
| Future\tcash\tinflows | $13,435 | $8,713 | $22,799 | $44,947 |
| Future\tproduction,\ttransportation\tand\tadministrative\tcosts | (5,512) | (2,564) | (1,877) | (9,953) |
| Future\tdevelopment\tcosts | (762) | (1,781) | (495) | (3,038) |
| Future\tincome\ttax\texpenses | (2,217) | (1,709) | (14,847) | (18,773) |
| Future\tnet\tcash\tflows | $4,944 | $2,659 | $5,580 | $13,183 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (1,818) | (408) | (2,439) | (4,665) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil\tand\tgas\nreserves | $3,126 | $2,251 | $3,141 | $8,518 |
| 2005 |  |  |  |  |
| Future\tcash\tinflows | $17,346 | $10,007 | $18,088 | $45,441 |
| Future\tproduction,\ttransportation\tand\tadministrative\tcosts | (5,046) | (2,007) | (1,910) | (8,963) |
| Future\tdevelopment\tcosts | (853) | (1,531) | (751) | (3,135) |
| Future\tincome\ttax\texpenses | (3,738) | (3,199) | (9,687) | (16,624) |
| Future\tnet\tcash\tflows | $7,709 | $3,270 | $5,740 | $16,719 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (2,862) | (829) | (2,427) | (6,118) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil\tand\tgas |  |  |  |  |
| reserves | $4,847 | $2,441 | $3,313 | $10,601 |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tdiscontinued |  |  |  |  |
| operations |  |  |  | $216 |
| 2004 |  |  |  |  |
| Future\tcash\tinflows | $12,377 | $7,742 | $5,709 | $25,828 |
| Future\tproduction,\ttransportation\tand\tadministrative\tcosts | (4,337) | (1,950) | (951) | (7,238) |
| Future\tdevelopment\tcosts | (585) | (1,801) | (294) | (2,680) |
| Future\tincome\ttax\texpenses | (2,581) | (1,753) | (1,265) | (5,599) |
| Future\tnet\tcash\tflows | $4,874 | $2,238 | $3,199 | $10,311 |
| 10\tpercent\tannual\tdiscount\tfor\testimated\ttiming\tof\tcash\tflows | (1,740) | (737) | (1,419) | (3,896) |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tproved\toil\tand\tgas |  |  |  |  |
| (a) |  |  |  |  |
| reserves | $3,134 | $1,501 | $1,780 | $6,415 |
| Standardized\tmeasure\tof\tdiscounted\tfuture\tnet\tcash\tflows\trelating\tto\tdiscontinued |  |  |  |  |
| operations |  |  |  | $54 |

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

|  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- |
| Sales\tand\ttransfers\tof\toil\tand\tgas\tproduced,\tnet\tof\tproduction,\ttransportation\tand\tadministrative\tcosts | $(5,312) | $(3,754) | $(2,689) |
| Net\tchanges\tin\tprices\tand\tproduction,\ttransportation\tand\tadministrative\tcosts\trelated\tto\tfuture\tproduction | (1,342) | 6,648 | 771 |
| Extensions,\tdiscoveries\tand\timproved\trecovery,\tless\trelated\tcosts | 1,290 | 700 | 1,349 |
| Development\tcosts\tincurred\tduring\tthe\tperiod | 1,251 | 1,030 | 609 |
| Changes\tin\testimated\tfuture\tdevelopment\tcosts | (527) | (552) | (628) |
| Revisions\tof\tprevious\tquantity\testimates | 1,319 | 820 | 948 |
| Net\tchanges\tin\tpurchases\tand\tsales\tof\tminerals\tin\tplace | 30 | 4,557 | 33 |
| Accretion\tof\tdiscount | 1,882 | 1,124 | 757 |
| Net\tchange\tin\tincome\ttaxes | (660) | (6,694) | (627) |
| Timing\tand\tother | (14) | 307 | 97 |
| Net\tchange\tfor\tthe\tyear | (2,083) | 4,186 | 620 |
| Beginning\tof\tyear | 10,601 | 6,415 | 5,795 |
| End\tof\tyear | $8,518 | $10,601 | $6,415 |
| Net\tchange\tfor\tthe\tyear\tfrom\tdiscontinued\toperations | $(216) | $162 | $(152) |

| (thousands	of	barrels	per	day)^(a)<br>Net	Liquid	Hydrocarbon	Sales<br>United	States | 76 | 76 | 81 |
| :--- | :--- | :--- | :--- |
| Europe | 35 | 36 | 40 |
| Africa | 112 | 52 | 32 |
| Total\tInternational | 147 | 88 | 72 |
| Worldwide\tContinuing\tOperations | 223 | 164 | 153 |
| Discontinued\tOperations | 12 | 27 | 17 |
| Worldwide | 235 | 191 | 170 |
| Natural\tgas\tliquids\tincluded\tin\tabove | 23 | 18 | 15 |
| (millions\tof\tcubic\tfeet\tper\tday)^(a)(b)\nNet\tNatural\tGas\tSales\nUnited\tStates | 532 | 578 | 631 |
| Europe | 243 | 262 | 292 |
| Africa | 72 | 92 | 76 |
| Total\tInternational | 315 | 354 | 368 |
| Worldwide | 847 | 932 | 999 |
| Total\tWorldwide\tSales\n(thousands\tof\tbarrels\tof\toil\tequivalent\tper\tday) |  |  |  |
| Continuing\tOperations | 365 | 319 | 320 |
| Discontinued\tOperations | 12 | 27 | 17 |
| Worldwide | 377 | 346 | 337 |
| (c) |  |  |  |
| Average\tRealizations |  |  |  |
| Liquid\tHydrocarbons\t(dollars\tper\tbarrel) |  |  |  |
| United\tStates | $54.41 | $45.41 | $32.76 |
| Europe | 64.02 | 52.99 | 37.16 |
| Africa | 59.83 | 46.27 | 35.11 |
| Total\tInternational | 60.81 | 49.04 | 36.24 |
| Worldwide\tContinuing\tOperations | 58.63 | 47.35 | 34.40 |
| Discontinued\tOperations | 38.38 | 33.47 | 22.65 |
| Worldwide | $57.58 | $45.42 | $33.31 |
| Natural\tGas\t(dollars\tper\tthousand\tcubic\tfeet) |  |  |  |
| United\tStates | $5.76 | $6.42 | $4.89 |
| Europe | 6.74 | 5.70 | 4.13 |
| Africa | 0.27 | 0.25 | 0.25 |
| Total\tInternational | 5.27 | 4.28 | 3.33 |
| Worldwide | $5.58 | $5.61 | $4.31 |
| Net\tProved\tReserves\tat\tyear-end\n(developed\tand\tundeveloped) |  |  |  |
| Liquid\tHydrocarbons\t(millions\tof\tbarrels) |  |  |  |
| United\tStates | 172 | 189 | 191 |
| International | 505 | 515 | 369 |
| Total | 677 | 704 | 560 |
| Developed\treserves\tas\ta\tpercentage\tof\ttotal\tnet\treserves | 84% | 86% | 69% |
| Natural\tGas\t(billions\tof\tcubic\tfeet) |  |  |  |
| United\tStates | 1,069 | 1,209 | 1,364 |
| International | 2,441 | 2,338 | 2,108 |
| Total | 3,510 | 3,547 | 3,472 |
| Developed\treserves\tas\ta\tpercentage\tof\ttotal\tnet\treserves | 50% | 54% | 56% |

(a) Amounts	represent	net	sales	after	royalties,	except	for	Ireland	where	amounts	are	before	royalties.

(b) Includes	natural	gas	acquired	for	injection	and	subsequent	resale	of	46	mmcfd,	38	mmcfd	and	19	mmcfd	in	2006,	2005	and	2004.	Effective	July	1,	2005,	the	methodology	for	allocating	sales	volumes	between natural	gas	produced	from	the	Brae	complex	and	third-party	natural	gas	production	was	modified,	resulting	in	an	increase	in	volumes	representing	natural	gas	acquired	for	injection	and	subsequent	resale. (c) Excludes	gains	and	losses	on	traditional	derivative	instruments	and	the	unrealized	effects	of	long-term	U.K.	natural	gas	contracts	that	are	accounted	for	as	derivatives.

# (Dollars	in	millions,	except	as	noted)

|  |  |  | 2006 | 2005 | 2004 |
| :--- | :--- | :--- | :--- | :--- | :--- |
| Segment\tIncome\t(Loss) |  |  |  |  |  |
| Exploration\tand\tProduction |  |  |  |  |  |
| United\tStates | United\tStates | United\tStates | $873 | $983 | $674 |
| International | International | International | 1,130 | 904 | 416 |
| E&amp;P\tsegment | E&amp;P\tsegment | E&amp;P\tsegment | 2,003 | 1,887 | 1,090 |
| Refining,\tMarketing\tand\tTransportation^(a) |  |  | 2,795 | 1,628 | 568 |
| Integrated\tGas | Integrated\tGas | Integrated\tGas | 16 | 55 | 37 |
| Segment\tincome | Segment\tincome | Segment\tincome | 4,814 | 3,570 | 1,695 |
| Items\tnot\tallocated\tto\tsegments,\tnet\tof\tincome\ttaxes: |  |  |  |  |  |
| Corporate\tand\tother\tunallocated\titems | Corporate\tand\tother\tunallocated\titems | Corporate\tand\tother\tunallocated\titems | (212) | (377) | (327) |
| Gain\t(loss)\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts | Gain\t(loss)\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts | Gain\t(loss)\ton\tlong-term\tU.K.\tnatural\tgas\tcontracts | 232 | (223) | (57) |
| Discontinued\toperations | Discontinued\toperations | Discontinued\toperations | 277 | 45 | (33) |
| Gain\ton\tdisposition\tof\tSyria\tinterest | Gain\ton\tdisposition\tof\tSyria\tinterest | Gain\ton\tdisposition\tof\tSyria\tinterest | 31 | – | – |
| Deferred\tincome\ttaxes\t–\ttax\tlegislation\tchanges | Deferred\tincome\ttaxes\t–\ttax\tlegislation\tchanges | Deferred\tincome\ttaxes\t–\ttax\tlegislation\tchanges | 21 | 15 | – |
| \t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t\t–\tother\tadjustments^(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\t\t\t\t\t\t\t\t\t\t\t\t\t–\tother\tadjustments^(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\t\t\t\t\t\t\t\t\t\t\t\t\t–\tother\tadjustments^(b) | 93 | – | – |
| Loss\ton\tearly\textinguishment\tof\tdebt | Loss\ton\tearly\textinguishment\tof\tdebt | Loss\ton\tearly\textinguishment\tof\tdebt | (22) | – | – |
| Gain\ton\tsale\tof\tminority\tinterests\tin\tEG\tHoldings | Gain\ton\tsale\tof\tminority\tinterests\tin\tEG\tHoldings | Gain\ton\tsale\tof\tminority\tinterests\tin\tEG\tHoldings | – | 21 | – |
| Corporate\tinsurance\tadjustment | Corporate\tinsurance\tadjustment | Corporate\tinsurance\tadjustment | – | – | (17) |
| Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | Cumulative\teffect\tof\tchange\tin\taccounting\tprinciple | – | (19) | – |
| Net\tincome | Net\tincome | Net\tincome | $5,234 | $3,032 | $1,261 |
| Net\tincome\tper\tcommon\tshare\t–\tbasic\t(in\tdollars) | Net\tincome\tper\tcommon\tshare\t–\tbasic\t(in\tdollars) | Net\tincome\tper\tcommon\tshare\t–\tbasic\t(in\tdollars) | $14.62 | $8.52 | $3.75 |
| \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\t\t\t\t\t\t\t\t–\tdiluted\t(in\tdollars) | \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\t\t\t\t\t\t\t\t–\tdiluted\t(in\tdollars) | \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\t\t\t\t\t\t\t\t–\tdiluted\t(in\tdollars) | $14.50 | $8.44 | $3.73 |
| Capital\texpenditures |  |  |  |  |  |
| Exploration\tand\tProduction | Exploration\tand\tProduction | Exploration\tand\tProduction | $2,169 | $1,366 | $840 |
| Refining,\tMarketing\tand\tTransportation^(a) | Refining,\tMarketing\tand\tTransportation^(a) | Refining,\tMarketing\tand\tTransportation^(a) | 916 | 841 | 794 |
| Integrated\tGas^(c) | Integrated\tGas^(c) | Integrated\tGas^(c) | 307 | 571 | 488 |
| Discontinued\tOperations | Discontinued\tOperations | Discontinued\tOperations | 45 | 94 | 106 |
| Corporate | Corporate | Corporate | 41 | 18 | 19 |
| Total | Total | Total | $3,478 | $2,890 | $2,247 |
| Exploration\tExpense |  |  |  |  |  |
| United\tStates | United\tStates | United\tStates | $169 | $118 | $78 |
| International |  |  | 196 | 99 | 80 |
| Total | Total | Total | $365 | $217 | $158 |
| Refinery\tRuns\t(thousands\tof\tbarrels\tper\tday) |  |  |  |  |  |
| Crude\toil\trefined | Crude\toil\trefined | Crude\toil\trefined | 980 | 973 | 939 |
| Other\tcharge\tand\tblend\tstocks | Other\tcharge\tand\tblend\tstocks | Other\tcharge\tand\tblend\tstocks | 234 | 205 | 171 |
| Total | Total | Total | 1,214 | 1,178 | 1,110 |
| Refined\tProduct\tYields\t(thousands\tof\tbarrels\tper\tday) |  |  |  |  |  |
| Gasoline | Gasoline | Gasoline | 661 | 644 | 608 |
| Distillates | Distillates | Distillates | 323 | 318 | 299 |
| Propane | Propane | Propane | 23 | 21 | 22 |
| Feedstocks\tand\tspecial\tproducts | Feedstocks\tand\tspecial\tproducts | Feedstocks\tand\tspecial\tproducts | 107 | 96 | 94 |
| Heavy\tfuel\toil | Heavy\tfuel\toil | Heavy\tfuel\toil | 26 | 28 | 25 |
| Asphalt | Asphalt | Asphalt | 89 | 85 | 77 |
| Total | Total | Total | 1,229 | 1,192 | 1,125 |
| Refined\tProduct\tSales\tVolumes\t(thousands\tof\tbarrels\tper\tday) | (d)(e) | (d)(e) | 1,425 | 1,455 | 1,400 |
| Matching\tbuy/sell\tvolumes\tincluded\tin\tabove(e) | Matching\tbuy/sell\tvolumes\tincluded\tin\tabove(e) | Matching\tbuy/sell\tvolumes\tincluded\tin\tabove(e) | 24 | 77 | 71 |
| Refining\tand\tWholesale\tMarketing\tGross\tMargin | ($\tper\tgallon) | (f) | $0.2288 | $0.1582 | $0.0877 |
| Speedway\tSuperAmerica |  |  |  |  |  |
| Retail\toutlets\tat\tyear-end | Retail\toutlets\tat\tyear-end | Retail\toutlets\tat\tyear-end | 1,636 | 1,638 | 1,669 |
| 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) | 3,301 | 3,226 | 3,152 |
| 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) | $0.1156 | $0.1230 | $0.1186 |
| Merchandise\tsales | Merchandise\tsales | Merchandise\tsales | $2,706 | $2,531 | $2,335 |
| Merchandise\tgross\tmargin |  |  | $667 | $626 | $571 |

(a) RM&T	segment	income	for	2005	and	2004	is	net	of	$376	million	and	$539	million	pretax	minority	interest	in	MPC.	RM&T	capital	expenditures	include	MPC	at	100	percent	for	all	periods.

(c) Includes	Equatorial	Guinea	LNG	Holdings	at	100	percent.

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

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

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

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

# Item	9A.	Controls	and	Procedures

# Disclosure	Controls	and	Procedures

								An	evaluation	of	the	effectiveness	of	the	design	and	operation	of	our	disclosure	controls	and	procedures	(as	defined	in	Rules	13(a)-15(e)	and	15(d)-15(e)	under	the Securities	Exchange	Act	of	1934)	was	carried	out	under	the	supervision	and	with	the	participation	of	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.	During	the	period	covered	by	this	report,	there	were	no	changes	in	our	internal controls	over	financial	reporting	that	have	materially	affected,	or	were	reasonably	likely	to	materially	affect,	our	internal	controls	over	financial	reporting.

# Internal	Controls

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

# Item	9B.	Other	Information

# PART	III

# Item	10.	Directors,	Executive	Officers	and	Corporate	Governance

								Information	concerning	the	directors	of	Marathon	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Election	of Directors"	in	Marathon's	Proxy	Statement	for	the	2007	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	for	the	2007	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,	2007,	are	as	follows:

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

								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.

								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.

								Mr.	Roberts	joined	Marathon	in	June	2006	as	senior	vice	president,	business	development.	Prior	to	joining	Marathon,	he	was	employed	by	BG	Group	from	2003	as executive	vice	president/managing	director	responsible	for	Asia	and	the	Middle	East.	He	served	as	advisor	to	the	vice	chairman	of	ChevronTexaco	Corporation	from 2001	to	2003.

# Section	16(a)	Beneficial	Ownership	Reporting	Compliance

								Section	16(a)	of	the	Securities	Exchange	Act	of	1934,	as	amended,	requires	that	the	Company's	directors	and	executive	officers,	and	persons	who	own	more	than ten	percent	of	a	registered	class	of	the	Company'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	the	Company's	review	of	the	reporting	forms	and	written	representations	provided	to	the Company	from	the	individuals	required	to	file	reports,	the	Company	believes	that	each	of	its	executive	officers	and	directors	has	complied	with	the	applicable	reporting requirements	for	transactions	in	the	Company's	securities	during	the	fiscal	year	ended	December	31,	2006,	except	for	Michael	K.	Stewart	who	filed	one	Form	4	report two	days	late	relating	to	shares-for-tax	withholding	for	a	vesting	of	restricted	stock	granted	to	Mr.	Stewart	prior	to	his	election	as	an	executive	officer	of	the	Company.

# Item	11.	Executive	Compensation

								Information	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Executive	Compensation	Tables	and	Other Information;"	under	the	sub-headings	"Compensation	Committee"	and	"Compensation	Committee	Interlocks	and	Insider	Participation"	under	the	heading	"The	Board	of Directors	and	Governance	Matters;"	and	under	the	heading	"Compensation	Committee	Report"	in	Marathon's	Proxy	Statement	for	the	2007	Annual	Meeting	of stockholders.

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

								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	for	the	2007	Annual	Meeting	of	stockholders.

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

								Information	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Certain	Relationships	and	Related	Person	Transactions," and	under	the	sub-heading	"Board	and	Committee	Independence"	under	the	heading	"The	Board	of	Directors	and	Governance	Matters"	in	Marathon's	Proxy	Statement for	the	2007	Annual	Meeting	of	stockholders.

# Item	14.	Principal	Accounting	Fees	and	Services

								Information	required	by	this	item	is	incorporated	by	reference	to	the	material	appearing	under	the	heading	"Information	Regarding	the	Independent	Registered Public	Accounting	Firm's	Fees,	Services	and	Independence"	in	Marathon's	Proxy	Statement	for	the	2007	Annual	Meeting	of	stockholders.

# Item	15.	Exhibits,	Financial	Statement	Schedules

# A.	Documents	Filed	as	Part	of	the	Report

1. Financial	Statements	(see	Part	II,	Item	8.	of	this	report	regarding	financial	statements)

# 2. Financial	Statement	Schedules

Financial	Statement	Schedules	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.

# 3. Exhibits:

Any	reference	made	to	USX	Corporation	in	the	exhibit	listing	that	follows	is	a	reference	to	the	former	name	of	Marathon	Oil	Corporation,	a	Delaware	corporation	and the	registrant,	and	is	made	because	the	exhibit	being	listed	and	incorporated	by	reference	was	originally	filed	before	July,	2001,	the	date	of	the	change	in	the	registrant's name.	References	to	Marathon	Ashland	Petroleum	LLC	or	MAP	are	references	to	the	entity	now	known	as	Marathon	Petroleum	Company	LLC.

# Exhibit	No. Description

# 2. Plan	of	Acquisition,	Reorganization,	Arrangement,	Liquidation	or	Succession

2.1* Holding	Company	Reorganization	Agreement,	dated	as	of	July	1,	2001,	by	and	among	USX	Corporation,	USX Holdco,	Inc.	and	United	States	Steel	LLC.

2.2* Agreement	and	Plan	of	Reorganization,	dated	as	of	July	31,	2001,	by	and	between	USX	Corporation	and	United	States Steel	LLC.

2.3++ Master	Agreement,	among	Ashland	Inc.,	ATB	Holdings	Inc.,	EXM	LLC,	New	EXM	Inc.,	Marathon	Oil	Corporation, Marathon	Oil	Company,	Marathon	Domestic	LLC	and	Marathon	Ashland	Petroleum	LLC,	dated	as	of	March	18,	2004 and	Amendment	No.	1	dated	as	of	April	27,	2005	(incorporated	by	reference	to	Exhibit	2.1	on	Amendment	No.	3	to	the Registration	Statement	on	Form	S-4/A	(File	No.	333-119694)	of	Marathon	Oil	Corporation	filed	on	May	19,	2005).

2.4++ Amended	and	Restated	Tax	Matters	Agreement	among	Ashland	Inc.,	ATB	Holdings	Inc.,	EXM	LLC,	New	EXM	Inc., Marathon	Oil	Corporation,	Marathon	Oil	Company,	Marathon	Domestic	LLC	and	Marathon	Ashland	Petroleum	LLC, dated	as	of	April	27,	2005	(incorporated	by	reference	to	Exhibit	2.2	on	Amendment	No.	3	to	the	Registration	Statement on	Form	S-4/A	(File	No.	333-119694)	of	Marathon	Oil	Corporation	filed	on	May	19,	2005).

2.5++ Assignment	and	Assumption	Agreement	(VIOC	Centers)	between	Ashland	Inc.	and	ATB	Holdings	Inc.,	dated	as	of March	18,	2004	(incorporated	by	reference	to	Exhibit	2.3	to	Marathon	Oil	Corporation's	Amendment	No.	1	to	Form	8- K/A,	filed	on	November	29,	2004).

2.6++ Assignment	and	Assumption	Agreement	(Maleic	Business)	between	Ashland	Inc.	and	ATB	Holdings	Inc.,	dated	as	of March	18,	2004	(incorporated	by	reference	to	Exhibit	2.4	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.

3.2 By-laws	of	Marathon	Oil	Corporation	(incorporated	by	reference	to	Exhibit	3.1	to	Marathon	Oil	Corporation's	Form	8- K	filed	on	October	27,	2006).

# 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 Amendment	No.	1	dated	as	of	May	4,	2006	to	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, 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 March	31,	2006).

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

10.3 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).

10.4 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	on	March	10,	2003).

10.5* Marathon	Oil	Corporation	1990	Stock	Plan,	as	Amended	and	Restated	Effective	January	1,	2002.

10.6 Second	Amended	and	Restated	Marathon	Oil	Corporation	Non-Officer	Restricted	Stock	Plan,	As	Amended	and Restated	Effective	January	2,	2002	(incorporated	by	reference	to	Exhibit	10.2	to	Marathon	Oil	Corporation's Amendment	No.	1	to	Form	10-Q/A	for	the	quarter	ended	September	30,	2002).

10.7 Marathon	Oil	Corporation	Deferred	Compensation	Plan	for	Non-Employee	Directors	(Amended	and	Restated	as	of January	1,	2002)	(incorporated	by	reference	to	Exhibit	10.12	to	Marathon	Oil	Corporation's	Amendment	No.	1	to Form	10-Q	for	the	quarter	ended	September	30,	2002).

10.8 First	Amendment	to	the	Marathon	Oil	Corporation	Deferred	Compensation	Plan	for	Non-Employee	Directors (Amended	and	Restated	as	of	January	1,	2002)	(incorporated	by	reference	to	Exhibit	10.1	to	Marathon	Oil Corporation's	Form	8-K,	filed	on	December	8,	2005).

10.13 Form	of	Non-Qualified	Stock	Option	with	Tandem	Stock	Appreciation	Right	Award	Agreement	for	Executive Committee	members	granted	under	Marathon	Oil	Corporation's	2003	Incentive	Compensation	Plan,	effective January	1,	2003	(incorporated	by	reference	to	Exhibit	10.5	to	Marathon	Oil	Corporation's	Form	10-Q	for	the	quarter ended	September	30,	2004).

10.14 Form	of	Non-Qualified	Stock	Option	with	Tandem	Stock	Appreciation	Right	Award	Agreement	for	Officers	granted under	Marathon	Oil	Corporation's	2003	Incentive	Compensation	Plan,	effective	January	1,	2003	(incorporated	by reference	to	Exhibit	10.6	to	Marathon	Oil	Corporation's	Form	10-Q	for	the	quarter	ended	September	30,	2004).

10.15 Form	of	Non-Qualified	Stock	Option	Award	Agreement	for	MAP	officers	granted	under	Marathon	Oil	Corporation's 2003	Incentive	Compensation	Plan,	effective	January	1,	2003	(incorporated	by	reference	to	Exhibit	10.18	to	Marathon Oil	Corporation's	Annual	Report	on	Form	10-K	for	the	year	ended	December	31,	2005).

10.16 Form	of	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	10.7 to	Marathon	Oil	Corporation's	Form	10-Q	for	the	quarter	ended	September	30,	2004).

10.17 Form	of	Stock	Appreciation	Right	Award	Agreement	for	Executive	Committee	members	granted	under	Marathon	Oil Corporation's	2003	Incentive	Compensation	Plan,	effective	January	1,	2003	(incorporated	by	reference	to	Exhibit	10.8 to	Marathon	Oil	Corporation's	Form	10-Q	for	the	quarter	ended	September	30,	2004).

10.31 First	Amendment	to	Marathon	Petroleum	Company	LLC	Deferred	Compensation	Plan	(incorporated	by	reference	to Exhibit	10.2	to	Marathon	Oil	Corporation's	form	8-K	filed	on	October	10,	2006).

10.32 Speedway	SuperAmerica	LLC	Excess	Benefit	Plan	(incorporated	by	reference	to	Exhibit	10.31	to	Marathon	Oil Corporation's	Annual	Report	on	Form	10-K	for	the	year	ended	December	31,	2005).

10.33 Speedway	SuperAmerica	LLC	Excess	Benefit	Plan	Amendment	(incorporated	by	reference	to	Exhibit	10.32	to Marathon	Oil	Corporation's	Annual	Report	on	Form	10-K	for	the	year	ended	December	31,	2005).

10.34 Pilot	JV	Amendment	to	Deferred	Compensation	Plans	and	Excess	Benefits	Plans	(incorporated	by	reference	to	Exhibit 10.33	to	Marathon	Oil	Corporation's	Annual	Report	on	Form	10-K	for	the	year	ended	December	31,	2005).

10.35 EMRO	Marketing	Company	Deferred	Compensation	Plan	(incorporated	by	reference	to	Exhibit	10.34	to	Marathon	Oil Corporation's	Annual	Report	on	Form	10-K	for	the	year	ended	December	31,	2005).

10.36* Form	of	Change	of	Control	Agreement	between	Marathon	Oil	Corporation	and	Various	Officers.

10.37 Letter	Agreement	between	Marathon	Oil	Company	and	Janet	F.	Clark,	executed	December	9,	2003	(incorporated	by reference	to	Exhibit	10(i)	to	Marathon	Oil	Corporation's	Annual	Report	on	Form	10-K	for	the	year	ended	December 31,	2003).

12.1* Computation	of	Ratio	of	Earnings	to	Combined	Fixed	Charges.

14.1 Code	of	Ethics	for	Senior	Financial	Officers	(incorporated	by	reference	to	Exhibit	14.	to	Marathon	Oil	Corporation's Form	10-K	for	the	year	ended	December	31,	2004).

21.1* List	of	Significant	Subsidiaries.

23.1* 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	Executive	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	Executive	Vice	President	and	Chief	Financial	Officer	pursuant	to	18	U.S.C.	Section	1350.

# Filed	herewith

++ Marathon	agrees	to	furnish	supplementally	a	copy	of	any	omitted	schedule	to	the	United	States	Securities	and	Exchange	Commission	upon	request.

								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	1,	2007 MARATHON	OIL	CORPORATION

By: /s/		MICHAEL	K.	STEWART

Michael	K.	Stewart

Vice	President,	Accounting	and	Controller

								Pursuant	to	the	requirements	of	the	Securities	Exchange	Act	of	1934,	this	report	has	been	signed	below	by	the	following	persons	on	March	1,	2007	on	behalf	of	the registrant	and	in	the	capacities	indicated.

Douglas	C.	Yearley



Question: as of december 31 , 2005 , what was the before tax charge related to adopting fin no . 47 in millions?
Calculation:   cost = 19 + 12
 answer = cost
Answer: 31