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Delaware				25-0996816
(State of Incorporation)				(I.R.S. Employer Identification No.)

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

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PART I
	Item 1.		Business		2
	Item 1A.		Risk Factors		22
	Item 1B.		Unresolved Staff Comments		27
	Item 2.		Properties		27
	Item 3.		Legal Proceedings		27
	Item 4.		Submission of Matters to a Vote of Security Holders		30
PART II
	Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		30
	Item 6.		Selected Financial Data		31
	Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
	Item 7A.		Quantitative and Qualitative Disclosures about Market Risk		53
	Item 8.		Financial Statements and Supplementary Data		F-1
	Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		58
	Item 9A.		Controls and Procedures		58
	Item 9B.		Other Information		58
PART III
	Item 10.		Directors and Executive Officers of the Registrant		58
	Item 11.		Executive Compensation		59
	Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		59
	Item 13.		Certain Relationships and Related Transactions		60
	Item 14.		Principal Accounting Fees and Services		60
PART IV
	Item 15.		Exhibits and Financial Statement Schedules		61
			Schedule II – Valuation and Qualifying Accounts		66
SIGNATURES					67
GLOSSARY OF CERTAIN DEFINED TERMS					68
Form of Non-Qualified Stock Option Grant for MAP officers
Form of Non-Qualified Stock Option Award Agreement
Form of Performance Share Award Agreement
Form of Cash Retention Award Agreement
Marathon Oil Company Excess Benefit Plan
Marathon Oil Company Deferred Compensation Plan
Marathon Petroleum Company LLC Excess Benefit Plan
Marathon Petroleum Company LLC Deferred Compensation Plan
Speedway SuperAmerica LLC Excess Benefit Plan
Speedway SuperAmerica LLC Excess Benefit Plan Amendment
Pilot JV Amendment to Deferred Compensation Plans and Excess Benefits Plans
EMRO Marketing Company Deferred Compensation Plan
Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
Computation of Ratio of Earnings to Fixed Charges
List of Significant Subsidiaries
Consent of Independent Registered Public Accounting Firm
Certification of President and CEO pursuant to Rule 13a-14a/15d-14a
Certification of SVP and CFO pursuant to Rule 13a-14a/15d-14a
Certification of President and CEO pursuant to Section 1350
Certification of SVP and CFO pursuant to Section 1350

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	Reserves

																Developed and
				Developed												Undeveloped
				2005				2004				2003				2005				2004				2003
Liquid Hydrocarbons (Millions of Barrels)
	United States				165				171				193				189				191				210
	Europe				39				41				47				98				107				59
	Africa				368				147				120				373				223				218
	Other International				31				27				31				44				39				89
		Total Consolidated			603				386				391				704				560				576
	Equity Method Investees				–				–				2				–				–				2
WORLDWIDE					603				386				393				704				560				578
Developed reserves as a percent of total net proved reserves					86	%			69	%			68	%
Natural Gas (Billions of Cubic Feet)
	United States				943				992				1,067				1,209				1,364				1,635
	Europe				326				376				421				486				544				484
	Africa				638				570				528				1,852				1,564				665
WORLDWIDE					1,907				1,938				2,016				3,547				3,472				2,784
Developed reserves as a percent of total net proved reserves					54	%			56	%			72	%
Total BOE (Millions of Barrels)
	United States				322				336				371				390				418				483
	Europe				93				104				117				179				198				139
	Africa				475				242				208				682				484				329
	Other International				31				27				31				44				39				89
		Total Consolidated			921				709				727				1,295				1,139				1,040
	Equity Method Investees				–				–				2				–				–				2
WORLDWIDE					921				709				729				1,295				1,139				1,042
Developed reserves as a percent of total net proved reserves					71	%			62	%			70	%

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	Delivery Commitments

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	Oil and Natural Gas Net Sales

(Thousands of Barrels per Day)			2005				2004				2003
United States(c)				76				81				107
Europe(d)				36				40				41
Africa(d)				52				32				27
Other International(d)				27				16				10
	Total Consolidated Continuing Operations			191				169				185
Equity Method Investees				–				1				6
Worldwide Continuing Operations				191				170				191
Discontinued Operations(e)				–				–				3
WORLDWIDE				191				170				194

(Millions of Cubic Feet per Day)			2005				2004				2003
United States(c)				578				631				732
Europe				224				273				262
Africa				92				76				66
	Total Consolidated Continuing Operations			894				980				1,060
Equity Method Investees				–				–				13
Worldwide Continuing Operations				894				980				1,073
Discontinued Operations(e)				–				–				74
WORLDWIDE				894				980				1,147

(a)		Includes crude oil, condensate and natural gas liquids.
(b)		Amounts represent net sales after royalties, except for the U.K., Ireland and the Netherlands where amounts are before royalties for the applicable periods.
(c)		Amounts represent net sales from leasehold ownership, after royalties and interests of others.
(d)		Amounts represent equity tanker liftings and direct deliveries of liquid hydrocarbons. The amounts correspond with the basis for fiscal settlements with governments. Crude oil purchases, if any, from host governments are excluded.
(e)		Amounts represent Marathon’s western Canadian operations.
(f)		Amounts exclude volumes purchased from third parties for injection and subsequent resale of 38 mmcfd in 2005, 19 mmcfd in 2004 and 23 mmcfd in 2003.

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	Productive and Drilling Wells

2005		Productive Wells(a)
																		Service								Drilling
		Oil								Natural Gas								Wells(b)								Wells(c)
		Gross				Net				Gross				Net				Gross				Net				Gross				Net
United States			5,724				2,029				5,254				3,696				2,723				827				55				31
Europe			51				19				68				37				29				10				3				1
Africa			926				155				13				8				97				18				7				1
Other International			156				156				–				–				50				50				26				26
WORLDWIDE			6,857				2,359				5,335				3,741				2,899				905				91				59

2004		Productive Wells(a)
																		Service
		Oil								Natural Gas								Wells(b)
		Gross				Net				Gross				Net				Gross				Net
United States			5,604				2,022				4,860				3,702				2,749				845
Europe			54				20				66				35				28				10
Africa			9				5				13				9				3				1
Other International			116				116				–				–				23				23
WORLDWIDE			5,783				2,163				4,939				3,746				2,803				879

2003			Productive Wells(a)
																			Service
			Oil								Natural Gas								Wells(b)
			Gross				Net				Gross				Net				Gross				Net
United States				5,580				2,040				4,649				3,555				2,726				834
Europe				52				14				65				35				27				9
Africa				7				4				10				7				1				1
Other International				109				109				–				–				21				21
	Total Consolidated			5,748				2,167				4,724				3,597				2,775				865
Equity Method Investees				96				21				–				–				15				3
WORLDWIDE				5,844				2,188				4,724				3,597				2,790				868

(a)		Includes active wells and wells temporarily shut-in. Of the gross productive wells, gross wells with multiple completions operated by Marathon totaled 278 in 2005, 273 in 2004 and 273 in 2003. Information on wells with multiple completions operated by other companies is unavailable to Marathon.
(b)		Consists of injection, water supply and disposal wells.
(c)		Consists of exploratory and development wells.

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	Drilling Activity

					2005				2004				2003
United States
	Development (b)		– Oil			46				13				4
			– Natural Gas			288				167				231
			– Dry			4				–				–
			Total			338				180				235
	Exploratory		– Oil			2				1				1
			– Natural Gas			17				8				7
			– Dry			2				6				2
			Total			21				15				10
			Total United States			359				195				245
International
	Development (b)		– Oil			68				27				31
			– Natural Gas			2				3				14
			– Dry			1				1				1
			Total			71				31				46
	Exploratory		– Oil			2				2				2
			– Natural Gas			–				–				21
			– Dry			4				7				5
			Total			6				9				28
			Total International			77				40				74
WORLDWIDE						436				235				319

(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

																		Developed and
		Developed								Undeveloped								Undeveloped
(Thousands of Acres)		Gross				Net				Gross				Net				Gross				Net
United States			1,459				910				2,894				1,415				4,353				2,325
Europe			395				305				968				393				1,363				698
Africa			12,971				2,149				2,951				769				15,922				2,918
Other International			599				599				2,541				1,997				3,140				2,596
WORLDWIDE			15,424				3,963				9,354				4,574				24,778				8,537

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Crude Oil Refining Capacity
(Barrels per Day)
Garyville, Louisiana			245,000
Catlettsburg, Kentucky			222,000
Robinson, Illinois			192,000
Detroit, Michigan			100,000
Canton, Ohio			73,000
Texas City, Texas			72,000
St. Paul Park, Minnesota			70,000
TOTAL			974,000

(Thousands of Barrels per Day)		2005				2004				2003
Gasoline			644				608				567
Distillates			318				299				284
Propane			21				22				21
Feedstocks and Special Products			96				94				93
Heavy Fuel Oil			28				25				24
Asphalt			85				77				72
TOTAL			1,192				1,125				1,061

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(Thousands of Barrels per Day)		2005				2004				2003
Gasoline			836				807				776
Distillates			385				373				365
Propane			22				22				21
Feedstocks and Special Products			96				92				97
Heavy Fuel Oil			29				27				24
Asphalt			87				79				74
TOTAL			1,455				1,400				1,357
Matching Buy/ Sell Volumes included in above			77				71				64

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	•	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;
	•	50 percent interest in Centennial Pipeline LLC, which owns a refined products system connecting Gulf Coast refineries with the Midwest market;
	•	51 percent interest in LOOP LLC (“LOOP”), which is the owner and operator of the only U.S. deepwater oil port, located 18 miles off the coast of Louisiana;
	•	59 percent interest in LOCAP LLC, which owns a crude oil pipeline connecting LOOP and the Capline system;
	•	37 percent interest in the Capline system, a large diameter crude oil pipeline extending from St. James, Louisiana to Patoka, Illinois;
	•	17 percent interest in Explorer Pipeline Company, which is a refined products pipeline system extending from the Gulf of Mexico to the Midwest;
	•	33 percent interest in Minnesota Pipe Line Company, which owns a crude oil pipeline extending from Clearbrook, Minnesota to Cottage Grove, Minnesota, which is in the vicinity of MPC’s St. Paul Park, Minnesota refinery;
	•	60 percent interest in Muskegon Pipeline LLC, which owns a refined products pipeline extending from Griffith, Indiana to North Muskegon, Michigan; and
	•	6 percent interest in Wolverine Pipe Line Company, a refined products pipeline system extending from Chicago, Illinois to Toledo, Ohio.

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	•	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.

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	•	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.

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	•	for any taxable period, or any portion of any taxable period, ended on or before December 31, 2001, unpaid tax sharing payments will be made between Marathon and United States Steel generally in accordance with the general tax sharing principles in effect before the Separation;
	•	no tax sharing payments will be made with respect to taxable periods, or portions thereof, beginning after December 31, 2001; and
	•	provisions relating to the tax and related liabilities, if any, that result from the Separation ceasing to qualify as a tax-free transaction and limitations on post-Separation activities that might jeopardize the tax-free status of the Separation.

	•	the taxes payable by each of the Marathon Group and the U.S. Steel Group were determined as if each of them had filed its own consolidated, combined or unitary tax return; and
	•	the U.S. Steel Group would receive the benefit, in the form of tax sharing payments by the parent corporation, of the tax attributes, consisting principally of net operating losses and various credits, that its business generated and the parent used on a consolidated basis to reduce its taxes otherwise payable.

	•	would not, before January 1, 2004, take various actions or enter into various transactions that might, under section 355 of the Internal Revenue Code of 1986, jeopardize the tax-free status of the Separation; and
	•	would be responsible for, and indemnify and hold the other party harmless from and against, any tax and related liability, such as interest and penalties, that results from the Separation ceasing to qualify as tax-free because of its taking of any such action or entering into any such transaction.

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

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	•	worldwide and domestic supplies of and demand for oil and natural gas;
	•	the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
	•	political instability or armed conflict in oil-producing regions; and
	•	domestic and foreign governmental regulations and taxes.

	•	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.

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	•	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 or may attempt to renegotiate or revoke existing contractual arrangements; and
	•	fluctuating currency values, hard currency shortages and currency controls.

	•	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.

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

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	•	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.

	•	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,

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	•	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,

Item 2.	Properties

Item 3.	Legal Proceedings

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

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

(a)

(b)

(c)

(d)

Total Number

Maximum Number

of Shares Purchased as

of Shares that May

Total Number of

Average

Part of Publicly

Yet Be Purchased

Shares

Price Paid per

Announced Plans or

Under the Plans or

Period

Purchased(a)(b)

Share

Programs

Programs

10/01/05 – 10/31/05

13,159

$

59.00

N/A

N/A

11/01/05 – 11/30/05

2,219

$

60.86

N/A

N/A

12/01/05 – 12/31/05

21,196

(c)

$

61.78

N/A

N/A

Total

36,574

$

60.73

N/A

N/A

(a)	15,566 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 6 shares due to Acquisition exchanges and Ashland share transfers pending at the time of closing of the Acquisition.
(c)	21,002 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.

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Item 6.	Selected Financial Data

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

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	•	We achieved exploration success with eight discoveries from 11 significant wells. We strengthened core E&P areas by:

	•	re-entering our operations in Libya;
	•	completing the Equatorial Guinea liquefied petroleum gas plant expansion project;
	•	progressing the Alvheim development offshore Norway to 43 percent completion; and
	•	obtaining approval for the Neptune development in the deepwater Gulf of Mexico.

	•	We added net proved oil and natural gas reserves of 282 million boe, excluding 2 million boe of dispositions, while producing 124 million boe during 2005. Over the past three years, we have added net proved reserves of 675 million boe, excluding dispositions of approximately 277 million boe, while producing approximately 385 million boe.
	•	We strengthened our RM&T business by:

	•	acquiring full ownership of our RM&T operations, with our acquisition of the 38 percent interest previously held by Ashland;
	•	completing the 26,000 bpd expansion of our Detroit refinery; and
	•	initiating FEED work for a potential 180,000 bpd expansion of our Garyville, Louisiana refinery.

	•	We achieved same store merchandise sales growth of 11.7 percent at Speedway SuperAmerica in 2005, which is the third consecutive year of double digit merchandise sales growth, and same store gasoline sales volume growth of 4.0 percent, which is the fourth consecutive year of better than one percent volume growth.
	•	We advanced our integrated gas strategy by:

	•	accelerating the EG LNG plant construction, such that the project is 66 percent complete at the end of 2005 with the first LNG shipments projected for the third quarter of 2007; and
	•	initiating an LNG supply contract to utilize our Elba Island, Georgia re-gasification terminal access rights.

	•	We increased the quarterly dividend 18 percent to 33 cents per share.

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	•	discount rate for measuring the present value of future plan obligations;
	•	expected long-term rates of return on plan assets;
	•	rate of future increases in compensation levels; and
	•	health care cost projections.

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(In millions)					2005				2004				2003
E&P					$	6,486			$	4,996			$	4,877
RM&T						56,003				43,630				34,514
IG						2,084				1,739				2,248
			Segment revenues			64,573				50,365				41,639
Elimination of intersegment revenues						(876	)			(668	)			(610	)
Loss on long-term U.K. gas contracts						(386	)			(99	)			(66	)
			Total revenues		$	63,311			$	49,598			$	40,963
Items included in both revenues and costs and expenses:
	Consumer excise taxes on petroleum products and merchandise				$	4,715			$	4,463			$	4,285
	Matching crude oil and refined product buy/sell transactions settled in cash:
		E&P			$	123			$	167			$	222
		RM&T				12,513				9,075				6,961
			Total buy/sell transactions included in revenues		$	12,636			$	9,242			$	7,183

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			2005				2004				2003
Statutory tax rate				35.0	%			35.0	%			35.0	%
Effects of foreign operations				(0.9	)			1.3				(0.4	)
State and local income taxes after federal income tax effects				2.5				1.6				2.2
Other federal tax effects				(0.4	)			(1.3	)			(0.2	)
	Effective tax rate			36.2	%			36.6	%			36.6	%

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(In millions)				2005				2004				2003
E&P
	Domestic			$	1,564			$	1,073			$	1,155
	International				1,424				623				425
		E&P segment income			2,988				1,696				1,580
RM&T					3,013				1,406				819
IG					31				48				(3	)
		Segment income			6,032				3,150				2,396
Items not allocated to segments:
	Administrative expenses				(367	)			(307	)			(227	)
	Loss on long-term U.K. gas contracts(a)				(386	)			(99	)			(66	)
	Gain on sale of minority interests in EGHoldings				23				–				–
	Impairment of certain oil and gas properties(b)				–				(44	)			–
	Corporate insurance adjustment(c)				–				(32	)			–
	Gain (loss) on ownership change in MPC				–				2				(1	)
	Gain on asset dispositions(d)				–				–				106
	Loss on dissolution of MKM Partners L.P.(e)				–				–				(124	)
		Income from operations		$	5,302			$	2,670			$	2,084

(a)		Amounts relate to long-term gas contracts in the U.K. that are accounted for as derivative instruments and recorded at fair value. See “Critical Accounting Estimates – Fair Value Estimates” on page 34 for further discussion.
(b)		Amount includes $32 million related to unproved properties and $12 million related to producing properties primarily due to unsuccessful developmental drilling activity in Russia.
(c)		Insurance expense related to estimated future obligations to make certain insurance premium payments related to past loss experience.
(d)		Amount represents a gain on the disposition of our interest in CLAM Petroleum B.V. and certain fields in the Big Horn Basin of Wyoming and SSA stores in Florida, North Carolina, South Carolina and Georgia.
(e)		See Note 13 to the consolidated financial statements for a discussion of the dissolution of MKM Partners L.P.

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					2005				2004				2003
Net liquid hydrocarbon sales (mbpd)(a)(b)
	United States					76.4				81.2				106.5
	Equity method investee					–				–				4.4
		Total United States				76.4				81.2				110.9
	Europe					36.3				39.8				41.5
	Africa					51.7				32.5				27.1
	Other International					26.6				15.6				10.0
	Equity method investee					–				1.0				1.2
		Total International(c)				114.6				88.9				79.8
		Worldwide continuing operations				191.0				170.1				190.7
	Discontinued operations					–				–				3.1
WORLDWIDE						191.0				170.1				193.8
Net natural gas sales (mmcfd)(b)(d)
	United States					577.6				631.2				731.6
	Europe					262.0				291.8				285.9
	Africa					92.4				76.4				65.9
	Equity method investee					–				–				12.4
		Total International				354.4				368.2				364.2
		Worldwide continuing operations				932.0				999.4				1,095.8
	Discontinued operations					–				–				74.1
WORLDWIDE						932.0				999.4				1,169.9
Total sales (mboepd)						346.3				336.7				388.8
Average sales prices (excluding derivative gains and losses)
	Liquid hydrocarbons ($ per bbl)(a)
		United States			$	45.41			$	32.76			$	26.92
		Equity method investee				–				–				29.45
			Total United States			45.41				32.76				27.02
		Europe				52.99				37.16				28.50
		Africa				46.27				35.11				26.29
		Other International				33.47				22.65				18.33
		Equity method investee				–				21.10				13.72
			Total International			45.43				33.68				26.24
			Worldwide continuing operations			45.42				33.24				26.70
		Discontinued operations				–				–				28.96
WORLDWIDE					$	45.42			$	33.24			$	26.73
	Natural gas ($ per mcf)
		United States			$	6.42			$	4.89			$	4.53
		Europe				5.70				4.13				3.35
		Africa				0.25				0.25				0.25
		Equity method investee				–				–				3.69
			Total International			4.28				3.33				2.80
			Worldwide continuing operations			5.61				4.31				3.95
		Discontinued operations				–				–				5.43
WORLDWIDE					$	5.61			$	4.31			$	4.05
Refined products sales volumes (mbpd)(e)						1,455				1,400				1,357
Matching buy/sell volumes included in refined products volumes (mbpd)						77				71				64
Refining and wholesale marketing margin (per gallon)(f)					$	0.1582			$	0.0877			$	0.0603

(a)		Includes crude oil, condensate and natural gas liquids.
(b)		Amounts represent net sales after royalties, except for the U.K., Ireland and the Netherlands where amounts are before royalties for the applicable periods.
(c)		Amounts represent equity tanker liftings and direct deliveries of liquid hydrocarbons. The amounts correspond with the basis for fiscal settlements with governments. Crude oil purchases, if any, from host governments are excluded.
(d)		Includes natural gas acquired for injection and subsequent resale of 38.1, 19.3 and 23.4 mmcfd in 2005, 2004 and 2003, 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.
(e)		Total average daily volumes of refined product sales to wholesale, branded and retail (SSA) customers.
(f)		Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation.

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(In millions)					2005				2004
E&P
	Domestic				$	2,799			$	2,644
	International					4,737				3,530
		Total E&P				7,536				6,174
RM&T						6,113				4,842
IG						1,157				621
Corporate						205				173
			Total		$	15,011			$	11,810

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(In millions)					2005				2004				2003
E&P
	Domestic				$	637			$	402			$	344
	International					823				542				629
		Total E&P				1,460				944				973
RM&T						841				794				789
IG						572				490				131
Corporate						17				19				16
			Total		$	2,890			$	2,247			$	1,909

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			December 31				December 31
(Dollars in millions)			2005				2004
Long-term debt due within one year			$	315			$	16
Long-term debt				3,698				4,057
	Total debt		$	4,013			$	4,073
Cash			$	2,617			$	3,369
Equity			$	11,705			$	8,111
Calculation:
Total debt			$	4,013			$	4,073
Minus cash				2,617				3,369
	Total debt minus cash			1,396				704
Total debt				4,013				4,073
Plus equity				11,705				8,111
Minus cash				2,617				3,369
	Total debt plus equity minus cash		$	13,101			$	8,815
Cash-adjusted debt-to-capital ratio				11	%			8	%

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												2007-				2009-				Later
(In millions)				Total				2006				2008				2010				Years
Long-term debt (excludes interest)(a)(b)				$	3,874			$	302			$	850			$	–			$	2,722
Sale-leaseback financing (includes imputed interest)(a)					85				11				30				22				22
Capital lease obligations(a)					156				16				33				33				74
Operating lease obligations(a)					517				100				102				68				247
Operating lease obligations under sublease(a)					43				12				11				10				10
Purchase obligations:
	Crude oil, refinery feedstock and refined products contracts(c)				10,771				10,660				111				–				–
	Transportation and related contracts				1,027				209				271				150				397
	Contracts to acquire property, plant and equipment				668				543				123				1				1
	LNG facility operating costs(d)				192				13				25				25				129
	Service and materials contracts(e)				185				71				45				38				31
	Unconditional purchase obligations(f)				69				7				14				14				34
	Commitments for oil and gas exploration (non-capital) (g)				20				20				–				–				–
Total purchase obligations					12,932				11,523				589				228				592
Other long-term liabilities reported in the consolidated balance sheet:
	Employee benefit obligations(h)				2,321				201				385				396				1,339
Total contractual cash obligations(i)				$	19,928			$	12,165			$	2,000			$	757			$	5,006

(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.

(b)		We anticipate cash payments for interest of $255 million for 2006, $432 million for 2007-2008, $385 million for 2009-2010 and $1.658 billion for the remaining years for a total of $2.730 billion.

(c)		The majority of contractual obligations to purchase crude oil, refinery feedstock and refined products as of December 31, 2005 relate to contracts to be satisfied within the first 180 days of 2006.
(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 LNG re-gasification 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 28 to the consolidated financial statements for a complete discussion of our guarantee.
(g)		Commitments for oil and gas exploration (non-capital) include estimated costs related to contractually obligated exploratory work programs that are expensed immediately, such as geological and geophysical costs.
(h)		We have employee benefit obligations consisting of pensions and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2014.
(i)		Includes $625 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 47.

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	Off-Balance Sheet Arrangements

	Nonrecourse Indebtedness of Investees

	Obligations Associated with the Separation of United States Steel

	•	$428 million of industrial revenue bonds related to environmental improvement projects for current and former United States Steel facilities, with maturities ranging from 2009 through 2033. Accrued interest payable on these bonds was $9 million at December 31, 2005.
	•	$66 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, 2005.

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	•	$49 million of obligations under a lease for equipment at United States Steel’s Clairton cokemaking facility, with a term extending to 2012. There was no accrued interest payable on this financing at December 31, 2005.
	•	$45 million of operating lease obligations, of which $37 million 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.

											2007-				2009-				Later
(In millions)			Total				2006				2008				2010				Years
	Long-term debt(a)		$	428			$	–			$	–			$	–			$	428
	Sale-leaseback financing (includes imputed interest)			85				11				30				22				22
	Capital lease obligations			67				10				19				19				19
	Operating lease obligations			8				5				3				–				–
	Operating lease obligations under sublease			37				5				11				10				11
Total contractual obligations assumed by United States Steel			$	625			$	31			$	63			$	51			$	480

(a)		We anticipate cash payments for interest of $24 million for 2006, $47 million for 2007-2008, $47 million for 2009-2010 and $272 million for the later years to be assumed by United States Steel.

	Transactions with Related Parties

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(In millions)				2005				2004				2003
Capital				$	390			$	433			$	331
Compliance
	Operating & maintenance				250				215				243
	Remediation(b)				25				32				44
		Total		$	665			$	680			$	618

(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.

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	•	Offshore Angola, where development options for the northeast area of Block 31, which includes the Plutao, Saturno, Marte and Venus discoveries, are currently being evaluated. Also on Block 31 during 2005, the announcement of five discoveries, Ceres, Palas, Juno, Astraea and Hebe, in the southeastern part of the block reinforce the likelihood of a second development area. The Urano well was started in December 2005 and drilling is in progress. We own a 10 percent interest in Block 31. We have secured rig capacity for and plan to participate in five exploration wells during 2006.
	•	On Angola Block 32, in which we own a 30 percent interest, three discoveries were announced, Gindungo, Canela and Gengibre. We also participated in a well on the Cola prospect that encountered hydrocarbons, but additional drilling will be required to determine commerciality. Finally, we announced a successful appraisal of the Gengibre discovery and the Mostarda well has reached total depth. These results will be announced following government approval. We have secured rig capacity for and plan to participate in six exploration wells during 2006.
	•	Equatorial Guinea, where we are evaluating development scenarios for the Deep Luba and Gardenia discoveries on the Alba Block, one of which includes production through the Alba field infrastructure and the future LNG facility under construction on Bioko Island. We own a 63 percent interest in the Alba Block and serve as operator.
	•	Norway, where we acquired four new Norwegian exploration licenses (three operated) in the December 2004 APA License Round. We now own interests in 16 licenses in the Norwegian sector of the North Sea and plan to drill one to two exploration wells during 2006.
	•	Gulf of Mexico, where we plan to participate in one to four wells during 2006.

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	•	Libya, where we re-entered the Waha concessions at the end of 2005 and have extended the licenses for an additional 25 years. In 2006 we will do more detailed analysis of work to be completed to maximize the potential of this major asset which currently produces 350,000 bpd gross and we expect to contribute 40,000 to 45,000 bpd net to Marathon during 2006. We own a 16.33 percent interest in the approximately 13 million acre Waha concessions.
	•	Norway, where our Alvheim development will consist of a floating production, storage and offloading (“FPSO”) vessel with subsea infrastructure for five drill centers and associated flow lines. At year-end 2005 the project was 43 percent complete with production expected to start during the first quarter 2007. The Alvheim development includes the Kneler, Boa and Kameleon fields in which we own a 65 percent interest and serve as operator. A development plan for the nearby Vilje discovery, in which we own a 47 percent interest, was approved by the Norwegian Government in 2005. The combined Alvheim/ Vilje developments are expected to ramp up production in the first quarter of 2007 to more than 50,000 net boepd. Also, results for the Volund well (formerly Hamsun) are being analyzed and development scenarios are being examined, including a possible tie-back to the Alvheim development. We own a 65 percent interest in Volund and serve as operator.
	•	Gulf of Mexico, where the Neptune development was sanctioned during 2005 and which is on track for first production in late 2007 or early 2008.
	•	Equatorial Guinea, where we completed our LPG expansion project and ramped up liquids production to approximately 86,000 gross bpd (49,000 bpd net to Marathon) by the end of 2005. We continue to exceed our initial liquids production projection, as gross production available for sale in January 2006 was approximately 90,000 bpd (51,000 bpd net to Marathon).
	•	Russia, where our successful drilling program in East Kamennoye took our production to greater than 30,000 net bpd at year end, more than double the production level when we acquired the assets in 2003.

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	•	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,
	•	associated with anticipated natural gas purchases for refinery use,
	•	associated with freight on crude oil, feedstocks and refined product deliveries, and
	•	on fixed price contracts for ethanol purchases;

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

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	Commodity Price Risk

(In millions)
		Incremental Decrease in IFO
		Assuming a Hypothetical Price
		Change of (a)
		2005								2004
Derivative Commodity Instruments(b)(c)		10%				25%				10%				25%
Crude oil(d)		$	11	(e)		$	25	(e)		$	1	(e)		$	–
Natural gas(d)			78	(e)			195	(e)			36	(e)			91	(e)
Refined products(d)			6	(e)			15	(e)			3	(f)			7	(f)

(a)		We remain at risk for future changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying hedged item. Effects of these offsets are not reported in the sensitivity analyses. Amounts assume hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at December 31, 2005 and 2004. The hypothetical price changes of 10 percent and 25 percent would result in incremental decreases in income from operations of $90 million and $225 million for 2005 and $48 million and $119 million for 2004 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments and these amounts are included above in the impact for natural gas. 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, 2005, would cause future IFO effects to differ from those presented in the table.
(b)		Net open contracts for the combined E&P and IG segments varied throughout 2005, from a low of 1,243 contracts at March 10 to a high of 2,192 contracts at January 20, and averaged 1,654 for the year. The number of net open contracts for the RM&T segment varied throughout 2005, from a low of 3,621 contracts at December 19 to a high of 28,079 contracts at March 21, and averaged 18,401 for the year. The derivative commodity instruments used and hedging positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.
(c)		The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated. Gains and losses on options are based on changes in intrinsic value only.
(d)		The direction of the price change used in calculating the sensitivity amount for each commodity is based on the largest incremental decrease in IFO when applied to the derivative commodity instruments used to hedge that commodity.
(e)		Price increase.
(f)		Price decrease.

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Strategy (In millions)			2005				2004				2003
Mitigate price risk			$	(57	)		$	(106	)		$	(112	)
Protect carrying values of excess inventories				(118	)			(98	)			(57	)
Protect margin on fixed price sales				18				8				5
Protect crack spread values				(81	)			(76	)			6
	Subtotal – non-trading activities			(238	)			(272	)			(158	)
Trading activities				(87	)			8				(4	)
	Total net derivative losses		$	(325	)		$	(264	)		$	(162	)

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(In millions)
			December 31, 2005								December 31, 2004
							Incremental								Incremental
			Fair				Increase in				Fair				Increase in
			Value(b)				Fair Value(c)				Value(b)				Fair Value(c)
Financial assets (liabilities)(a):
	Investments and long-term receivables		$	268			$	–			$	266			$	–
	Interest rate swap agreements(e)		$	(30	)		$	14			$	(10	)		$	14
	Long-term debt(d)(e)		$	(4,354	)		$	(152	)		$	(4,480	)		$	(164	)

(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 Note 17 and 18 to the consolidated financial statements for carrying value of instruments.
(c)		For long-term debt, this assumes a 10 percent decrease in the weighted average yield to maturity of our long-term debt at December 31, 2005 and 2004. For interest rate swap agreements, this assumes a 10 percent decrease in the effective swap rate at December 31, 2005 and 2004.
(d)		Includes amounts due within one year and the effects of interest rate swaps.
(e)		Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.

		Fixed Rate to be				Notional				Swap
Floating Rate to be Paid		Received				Amount				Maturity				Fair Value
Six Month LIBOR +4.226%			6.650	%		$	300  million				2006			$	(1) million
Six Month LIBOR +1.935%			5.375	%		$	450  million				2007			$	(8) million
Six Month LIBOR +3.285%			6.850	%		$	400  million				2008			$	(11) million
Six Month LIBOR +2.142%			6.125	%		$	200  million				2012			$	(10) million

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Notional

Collar Strike

Fair

Financial Instruments

Period

Amount

Range(a)

Value(b)

Foreign Currency Rate Option

Collars

Euro

January 2006 – June 2006

$

81 million

1.17 – 1.22

(c)

$

–

Norwegian kroner

January 2006 – June 2006

$

154  million

6.42 – 6.95

(d)

$

–

(a)		Rates shown are weighted average floor and ceiling prices for the period. If exchange rates are within the specified collar range at expiration, the collar expires worthless. If exchange rates are outside of the various collar ranges at expiration, we will settle the difference with the counterparty.
(b)		Fair value was based on market prices.
(c)		U.S. dollar to foreign currency.
(d)		Foreign currency to U.S. dollar.

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	Index to 2005 Consolidated Financial Statements and Supplementary Data

			Page
Management’s Responsibilities for Financial Statements				F-2
Management’s Report on Internal Control over Financial Reporting				F-2
Report of Independent Registered Public Accounting Firm				F-3
Audited Consolidated Financial Statements:
	Consolidated Statements of Income			F-4
	Consolidated Balance Sheets			F-5
	Consolidated Statements of Cash Flows			F-6
	Consolidated Statements of Stockholders’ Equity			F-7
	Notes to Consolidated Financial Statements			F-8
Selected Quarterly Financial Data (Unaudited)				F-42
Principal Unconsolidated Investees (Unaudited)				F-42
Supplementary Information on Oil and Gas Producing Activities (Unaudited)				F-43
Five-Year Operating Summary				F-50
Five-Year Selected Financial Data				F-52

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	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.

Clarence P. Cazalot, Jr.		Janet F. Clark		Albert G. Adkins
President and		Senior Vice President		Vice President,
Chief Executive Officer		and Chief Financial Officer		Accounting

	To the Stockholders of Marathon Oil Corporation:

	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, 2005. This evaluation did not include the internal control over financial reporting related to Marathon’s Libya operations acquired in a purchase business combination on December 29, 2005. Under the terms of the agreement, the operational re-entry date is January 1, 2006; therefore, Marathon’s consolidated results of operations for 2005 do not include any results from the Libya operations. Total assets recorded for the Libya operations as of December 31, 2005 represent approximately 4 percent of total assets as of that date.
	Marathon’s management assessment of the effectiveness of Marathon’s internal control over financial reporting as of December 31, 2005 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

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

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	To the Stockholders of Marathon Oil Corporation:

We have completed integrated audits of Marathon Oil Corporation and its subsidiaries’ (Marathon) 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

	Consolidated financial statements

	In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of Marathon at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of Marathon’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
	As discussed in Note 2 to the financial statements, Marathon changed its method of accounting for conditional asset retirement obligations in 2005 and its method of accounting for asset retirement obligations in 2003.

	Internal control over financial reporting

	Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Marathon maintained effective internal control over financial reporting as of December 31, 2005 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, 2005, based on criteria established in Internal Control – Integrated Framework issued by the COSO. Marathon’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of Marathon’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
	A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
	Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
	As described in the accompanying Management’s Report on Internal Control over Financial Reporting, management has excluded Marathon’s Libya operations from its assessment of internal control over financial reporting as of December 31, 2005 because it was acquired by Marathon in a purchase business combination in December 2005. We have also excluded the Libya operations from our audit of internal control over financial reporting. The Libya operations’ total assets and total revenues represent 4% and 0%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2005.

	PricewaterhouseCoopers LLP
	Houston, Texas
	March 3, 2006

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	Consolidated Statements of Income

(Dollars in millions, except per share data)				2005				2004				2003
Revenues and other income:
	Sales and other operating revenues (including consumer excise taxes)			$	49,273			$	39,305			$	32,859
	Revenues from matching buy/sell transactions				12,636				9,242				7,183
	Sales to related parties				1,402				1,051				921
	Income from equity method investments				266				170				29
	Net gains on disposal of assets				57				36				166
	Gain (loss) on ownership change in Marathon Petroleum Company LLC				–				2				(1	)
	Other income – net				39				101				77
		Total revenues and other income			63,673				49,907				41,234
Costs and expenses:
	Cost of revenues (excluding items shown below)				37,847				30,740				24,900
	Purchases related to matching buy/sell transactions				12,364				9,050				7,213
	Purchases from related parties				225				202				209
	Consumer excise taxes				4,715				4,463				4,285
	Depreciation, depletion and amortization				1,358				1,217				1,144
	Selling, general and administrative expenses				1,158				1,025				920
	Other taxes				482				338				299
	Exploration expenses				222				202				180
		Total costs and expenses			58,371				47,237				39,150
Income from operations					5,302				2,670				2,084
Net interest and other financing costs					145				161				186
Minority interests in income (loss) of:
	Marathon Petroleum Company LLC				384				532				302
	Equatorial Guinea LNG Holdings Limited				(8	)			(7	)			–
Income from continuing operations before income taxes					4,781				1,984				1,596
Provision for income taxes					1,730				727				584
Income from continuing operations					3,051				1,257				1,012
Discontinued operations					–				4				305
Income before cumulative effect of changes in accounting principles					3,051				1,261				1,317
Cumulative effect of changes in accounting principles					(19	)			–				4
Net income				$	3,032			$	1,261			$	1,321
Per Share Data
	Basic:
		Income from continuing operations		$	8.57			$	3.74			$	3.26
		Net income		$	8.52			$	3.75			$	4.26
	Diluted:
		Income from continuing operations		$	8.49			$	3.72			$	3.26
		Net income		$	8.44			$	3.73			$	4.26

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Consolidated Balance Sheets

(Dollars in millions, except per share data)			December 31	2005				2004
Assets
Current assets:
	Cash and cash equivalents			$	2,617			$	3,369
	Receivables, less allowance for doubtful accounts of $3 and $6				3,476				3,146
	Receivables from United States Steel				20				15
	Receivables from related parties				38				74
	Inventories				3,041				1,995
	Other current assets				191				267
		Total current assets			9,383				8,866
Investments and long-term receivables, less allowance for doubtful accounts of $10 and $10					1,864				1,546
Receivables from United States Steel					532				587
Property, plant and equipment – net					15,011				11,810
Prepaid pensions					–				128
Goodwill					1,307				252
Intangibles – net					200				118
Other noncurrent assets					201				116
		Total assets		$	28,498			$	23,423
Liabilities
Current liabilities:
	Accounts payable			$	5,353			$	4,430
	Consideration payable under Libya re-entry agreement				732				–
	Payables to related parties				82				44
	Payroll and benefits payable				344				274
	Accrued taxes				782				397
	Deferred income taxes				450				–
	Accrued interest				96				92
	Long-term debt due within one year				315				16
		Total current liabilities			8,154				5,253
Long-term debt					3,698				4,057
Deferred income taxes					2,030				1,553
Employee benefit obligations					1,321				989
Asset retirement obligations					711				477
Payables to United States Steel					6				5
Deferred credits and other liabilities					438				288
		Total liabilities			16,358				12,622
Minority interest in Marathon Petroleum Company LLC					–				2,559
Minority interests in Equatorial Guinea LNG Holdings Limited					435				131
Commitments and contingencies
Stockholders’ Equity
Common stock issued – 366,925,852 shares at December 31, 2005 and 346,717,785 shares at December 31, 2004 (par value $1 per share, 550,000,000 shares authorized)					367				347
Common stock held in treasury, at cost – 179,977 shares at December 31, 2005 and 34,650 shares at December 31, 2004					(8	)			(1	)
Additional paid-in capital					5,111				4,028
Retained earnings					6,406				3,810
Accumulated other comprehensive loss					(151	)			(64	)
Unearned compensation					(20	)			(9	)
		Total stockholders’ equity			11,705				8,111
		Total liabilities and stockholders’ equity		$	28,498			$	23,423

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Consolidated Statements of Cash Flows

(Dollars in millions)					2005				2004				2003
Increase (decrease) in cash and cash equivalents
Operating activities
Net income					$	3,032			$	1,261			$	1,321
Adjustments to reconcile net income to net cash provided from operating activities:
	Cumulative effect of changes in accounting principles					19				–				(4	)
	Income from discontinued operations					–				(4	)			(305	)
	Deferred income taxes					(208	)			(73	)			71
	Minority interests in income of subsidiaries					376				525				302
	Depreciation, depletion and amortization					1,358				1,217				1,144
	Pension and other postretirement benefits – net					71				82				68
	Exploratory dry well costs and unproved property impairments					113				106				86
	Net gains on disposal of assets					(57	)			(36	)			(166	)
	Impairment of investments					–				–				129
	Changes in the fair value of long-term U.K. natural gas contracts					386				99				66
	Changes in working capital:
		Current receivables				(1,171	)			(709	)			(671	)
		Inventories				(150	)			(41	)			33
		Current accounts payable and accrued expenses				1,067				1,224				496
	All other – net					(98	)			115				112
		Net cash provided from continuing operations				4,738				3,766				2,682
		Net cash provided from discontinued operations				–				–				83
		Net cash provided from operating activities				4,738				3,766				2,765
Investing activities
Capital expenditures						(2,890	)			(2,247	)			(1,909	)
Acquisitions						(506	)			–				(252	)
Disposal of discontinued operations						–				–				612
Disposal of assets						131				76				644
Proceeds from sale of minority interests in Equatorial Guinea LNG Holdings Limited						163				–				–
Restricted cash – deposits						(54	)			(42	)			(108	)
			– withdrawals			41				34				146
Investments – loans and advances						(27	)			(156	)			(91	)
All other – net						15				11				2
Investing activities of discontinued operations						–				–				(29	)
		Net cash used in investing activities				(3,127	)			(2,324	)			(985	)
Financing activities
Payment of debt assumed in acquisitions						(1,920	)			–				(31	)
Commercial paper and revolving credit arrangements – net						–				–				(131	)
Debt issuance costs						–				(4	)			–
Other debt repayments						(8	)			(259	)			(177	)
Issuance of common stock						85				1,047				17
Purchases of common stock						(7	)			(4	)			(6	)
Dividends paid						(436	)			(348	)			(298	)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited						213				95				–
Distributions to minority shareholder of Marathon Petroleum Company LLC						(272	)			–				(262	)
		Net cash provided from (used in) financing activities				(2,345	)			527				(888	)
Effect of exchange rate changes on cash
Continuing operations						(18	)			4				8
Discontinued operations						–				–				8
Net increase (decrease) in cash and cash equivalents						(752	)			1,973				908
Cash and cash equivalents at beginning of year						3,369				1,396				488
Cash and cash equivalents at end of year					$	2,617			$	3,369			$	1,396

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Consolidated Statements of Stockholders’ Equity

						Stockholders’ Equity												Shares in thousands
(Dollars in millions, except per share data)						2005				2004				2003				2005				2004				2003
Common stock:
	Balance at beginning of year					$	347			$	312			$	312				346,718				312,166				312,166
	Issuance(a)						20				35				–				20,208				34,552				–
	Balance at end of year					$	367			$	347			$	312				366,926				346,718				312,166
Common stock held in treasury, at cost:
	Balance at beginning of year					$	(1	)		$	(46	)		$	(60	)			(35	)			(1,744	)			(2,293	)
	Repurchased						(7	)			(4	)			(6	)			(10	)			(129	)			(219	)
	Reissued for employee stock plans						–				49				20				(135	)			1,838				768
	Balance at end of year					$	(8	)		$	(1	)		$	(46	)			(180	)			(35	)			(1,744	)

																		Comprehensive Income
																		2005				2004				2003
Additional paid-in capital:
	Balance at beginning of year					$	4,028			$	3,033			$	3,032
	Common stock issuance(a)						1,065				970				–
	Treasury stock reissued						18				25				1
	Balance at end of year					$	5,111			$	4,028			$	3,033
Unearned compensation:
	Balance at beginning of year					$	(9	)		$	(9	)		$	(7	)
	Changes during year						(11	)			–				(2	)
	Balance at end of year					$	(20	)		$	(9	)		$	(9	)
Retained earnings:
	Balance at beginning of year					$	3,810			$	2,897			$	1,874
	Net income						3,032				1,261				1,321			$	3,032			$	1,261			$	1,321
	Dividends paid (per share: $1.22 in 2005, $1.03 in 2004 and $0.96 in 2003)						(436	)			(348	)			(298	)
	Balance at end of year					$	6,406			$	3,810			$	2,897
Accumulated other comprehensive loss(b) :
	Minimum pension liability adjustments:
		Balance at beginning of year				$	(71	)		$	(93	)		$	(47	)
		Changes during year					(70	)			22				(46	)			(70	)			22				(46	)
		Balance at end of year				$	(141	)		$	(71	)		$	(93	)
	Foreign currency translation adjustments:
		Balance at beginning of year				$	(5	)		$	(4	)		$	(1	)
		Changes during year					–				(1	)			(3	)			–				(1	)			(3	)
		Balance at end of year				$	(5	)		$	(5	)		$	(4	)
	Deferred gains (losses) on derivative instruments:
		Balance at beginning of year				$	12			$	(15	)		$	(21	)
		Reclassification of the cumulative effect adjustment into income					(2	)			(3	)			(3	)			(2	)			(3	)			(3	)
		Changes in fair value					(15	)			(82	)			(50	)			(15	)			(82	)			(50	)
		Reclassification to income					–				112				59				–				112				59
		Balance at end of year				$	(5	)		$	12			$	(15	)
			Total balances at end of year			$	(151	)		$	(64	)		$	(112	)
				Total comprehensive income														$	2,945			$	1,309			$	1,278
Total stockholders’ equity						$	11,705			$	8,111			$	6,075

(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.
(b)	Related income tax provision (credit) on changes and reclassifications during the year:

		2005				2004				2003
Minimum pension liability adjustments		$	(42	)		$	3			$	(25	)
Foreign currency translation adjustments			–				–				(2	)
Net deferred gains (losses) on derivative instruments			(3	)			9				3

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	Notes to Consolidated Financial Statements

	Marathon Oil Corporation (“Marathon”) is engaged in worldwide exploration and production of crude oil and natural gas; domestic refining, marketing and transportation of crude oil and petroleum products; and worldwide marketing and transportation of natural gas and products manufactured from natural gas.
	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 5, 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 variable interest entities (“VIEs”) for which Marathon is the primary beneficiary are consolidated. Equatorial Guinea LNG Holdings Limited (“EGHoldings”), in which Marathon holds a 60% interest and was formed for the purpose of constructing and operating a liquefied natural gas (“LNG”) plant, is a VIE and Marathon is its primary beneficiary. As of December 31, 2005, total expenditures of $1.116 billion related to the LNG plant, including $1.066 billion of capital expenditures, have been incurred.
	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 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 investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. Income from equity method investments represents Marathon’s proportionate share of 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 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 net income per share is calculated based on the weighted average number of common shares outstanding. Diluted net income per share assumes exercise of stock options and warrants and conversion of convertible debt and preferred securities, provided the effect is not antidilutive.
	Segment information – Marathon’s operations consist of three reportable operating segments:

	•	Exploration and Production (“E&P”) – explores for and produces crude oil and natural gas on a worldwide basis;
	•	Refining, Marketing and Transportation (“RM&T”) – refines, markets and transports crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and
	•	Integrated Gas (“IG”) – markets and transports natural gas and products manufactured from natural gas, such as LNG and methanol, on a worldwide basis.

Management has determined that these are its operating segments because these are the components of Marathon (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 to make decisions about resources to be allocated and to assess performance and (3) for which discrete financial information is available. The chief operating decision maker (“CODM”) is responsible for allocating resources to and assessing performance of Marathon’s operating segments. Information on assets by segment is not presented because it is not reviewed by the CODM. The CODM is the manager over the E&P and IG segments. In this role, the CODM is responsible for allocating resources within those segments, reviewing financial results of components within those segments, and assessing the performance of the components. The components within these 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 segment manager of the RM&T segment reports to the CODM. The RM&T segment manager is responsible for allocating resources within the segment, reviewing financial results of components within the segment, and assessing the performance of the components. The CODM reviews these financial results at the RM&T segment level.

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Segment income represents income from operations allocable to operating segments. Marathon’s corporate general and administrative costs are not allocated to operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate activities. These costs also include non-cash effects of stock-based compensation for all employees except those of MPC. Non-cash effects of stock-based compensation for MPC employees are allocated to the RM&T segment. 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 income from operations in Note 8.

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

	Marathon recognizes revenues from the production of oil and natural gas when title is transferred. In the United States and certain international locations, production volumes of liquid hydrocarbons and natural gas are sold immediately and transported via pipeline. At other international locations, production volumes may be stored as inventory and sold at a later time. Royalties on the production of oil and 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 to cost of revenues when the initiating transaction occurs. Incentives that are derived from contractual provisions are accrued based on past experience and recognized in cost of revenues.
	Marathon follows the sales method of accounting for 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 – Marathon considers matching buy/sell transactions to be arrangements in which Marathon agrees to buy a specific quantity and quality of crude oil or refined petroleum products to be delivered at a specific location while simultaneously agreeing to sell a specified quantity and quality of crude oil or refined petroleum products at a different location, usually with the same counterparty. All matching buy/sell transactions are settled in cash and are recorded in both revenues and cost of revenues as separate sales and purchase transactions, or on a “gross” basis. The commodity purchased and the commodity sold generally are similar in nature.

	In a typical matching buy/sell transaction, Marathon enters into a contract to sell a particular grade of crude oil or refined product at a specified location and date to a particular counterparty, and simultaneously agrees to buy a particular grade of crude oil or refined product at a different location on the same or another specified date, typically from the same counterparty. The value of the purchased volumes rarely equals the sales value of the sold volumes. The value differences between purchases and sales are primarily due to (1) grade/ quality differentials, (2) location differentials 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.
	The characteristics of Marathon’s matching buy/sell transactions include gross invoicing between Marathon and its counterparties and cash settlement of the transactions. Nonperformance by one party to deliver generally does not relieve the other party’s obligation to perform. Both transactions require physical delivery of the product. The risks and rewards of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk, counterparty nonperformance risk and the fact that Marathon has the primary obligation to perform.
	Marathon will be required to change its accounting for purchases and sales of inventory with the same counterparty, including certain matching buy/sell transactions, in the second quarter of 2006. See Note 30 for further information.

	Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities generally of three months or less.
	Inventories – Inventories are carried at lower of cost or market. Cost of inventories is determined primarily under the last-in, first-out (LIFO) method.

	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

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	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.

	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 for doubtful accounts 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.
	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 and refined products, the fair value of certain assets and liabilities, future interest expense and certain business transactions denominated in foreign currencies. Changes in the fair values of all derivatives are recognized immediately in income, in revenues, other income, cost of revenues or net interest and other financing costs, unless the derivative qualifies as a hedge of future cash flows or certain foreign currency exposures. Cash flows related to derivatives used to manage commodity price risk and interest rate risk, as well as 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 accumulated other comprehensive income, a component of stockholders’ equity, and is reclassified to income – in revenues, cost of revenues, depreciation, depletion and amortization or net interest and other financing costs – when the underlying forecasted transaction is recognized in income. Any ineffective portion of such hedges is recognized in income as it occurs. For discontinued cash flow hedges, prospective changes in the fair value of the derivative are recognized in income. Any gain or loss in accumulated 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 related gain or loss in accumulated other comprehensive income is immediately reclassified into income.
	For derivatives designated as hedges of the fair value of recognized assets, liabilities or firm commitments, changes in the fair values of both the hedged item and the related derivative are recognized immediately in income – in revenues, cost of revenues or net interest and other financing costs – with an offsetting effect included in the basis of the hedged item. The net effect is to report in income the extent to which the hedge is not effective in achieving offsetting changes in fair value.
	As market conditions change, Marathon may use selective derivative instruments that assume market risk. For derivative instruments that are classified as trading, changes in the fair value are recognized immediately in other income. Any premium received is amortized into income based on the underlying settlement terms of the derivative position. All related effects of a trading strategy, including physical settlement of the derivative position, are recognized in other income.

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

	In the E&P segment, two long-term natural gas delivery commitment contracts in the United Kingdom are classified as nontraditional derivative instruments. These contracts contain pricing provisions that are not clearly and closely related to the underlying commodity and therefore must be accounted for as derivative instruments.
	In the RM&T segment, certain physical commodity contracts are classified as nontraditional derivative instruments because certain volumes under these contracts are physically netted at particular delivery locations. The netting process causes all contracts at that delivery location to be considered derivative instruments. Other physical contracts that involve flash title are also accounted for as nontraditional derivative instruments as Marathon has not elected to treat these contracts as normal purchases or normal sales.

	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

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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 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 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 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.
	Major maintenance activities – Marathon incurs costs for planned major refinery maintenance (“turnarounds”). Such costs are expensed in the same annual period as incurred; however, estimated annual turnaround costs are recognized as expense throughout the year on a pro rata basis.
	Environmental remediation liabilities – Environmental remediation expenditures are capitalized if the costs mitigate past or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Marathon provides for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities

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	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.

	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. Upon adoption of Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143,” on December 31, 2005, conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining facilities were recognized based on the most probable current cost projections. See Note 2 for further information regarding Marathon’s adoption of FIN No. 47.
	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. The depreciation will generally be determined on a units-of-production basis for production facilities and on a straight-line basis for refining facilities, while the accretion to be recognized will escalate 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 has noncontributory defined benefit pension plans covering substantially all domestic employees as well as international employees located in Ireland, Norway and the United Kingdom. In addition, several excess benefits plans exist covering domestic employees within defined regulatory compensation limits. Benefits under these plans are based primarily on years of service and final average pensionable earnings. The benefits provided include both pension and health care.

	Marathon also has defined benefit plans for other postretirement benefits covering most employees. Health care benefits are provided through comprehensive hospital, surgical and major medical benefit provisions subject to various cost sharing features. Life insurance benefits are provided to certain nonunion and union represented retiree beneficiaries. Other postretirement benefits have not been funded in advance.
	Marathon uses a December 31 measurement date for its pension and other postretirement benefit plans.

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

	The Plan replaced the 1990 Stock Plan, the Non-Officer Restricted Stock Plan, the Non-Employee Director Stock Plan, the deferred stock benefit provision of the Deferred Compensation Plan for Non-Employee Directors, the Senior Executive Officer Annual Incentive Compensation Plan, and the Annual Incentive Compensation Plan (collectively, the “Prior Plans”). No new grants will be made from the Prior Plans. Any awards previously granted under the Prior Plans shall continue to vest and/or be exercisable in accordance with their original terms and conditions.
	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. Prior to 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

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	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 all expire ten years from the date they are granted.
	Similar to stock options, stock appreciation rights (“SARs”) represent the right to receive a payment equal to the excess of the fair market value of shares of common stock on the date the right is exercised over the exercise price. In general, SARs that have been granted under the Plan are settled in shares of stock, vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.
	In 2003 and 2004, the Compensation Committee granted stock-based Performance Awards to Marathon’s officers under the Plan. The stock-based Performance Awards represent shares of common stock that are subject to forfeiture provisions and restrictions on transfer. Those restrictions may be removed if certain pre-established performance measures are met. The stock-based Performance Awards granted under the Plan generally vest at the end of a 36-month performance period if certain pre-established performance targets are achieved and the recipient remains employed by Marathon at that date.
	In 2005, the Compensation Committee granted cash-based Performance Awards to Marathon’s and MPC’s officers under the Plan. The cash-based performance units generally vest at the end of a 36-month performance period if certain pre-established performance targets are achieved and the recipient remains employed by Marathon at that date. The target value of each performance unit granted is $1, with the actual payout varying from zero percent to 200 percent of the target value based on actual performance achieved. The Compensation Committee also granted time-based restricted stock to the officers under the Plan in 2005. The restricted stock awards vest three years from the date of grant, contingent on the recipient’s continued employment. Prior to vesting, the restricted stock recipients have the right to vote such stock and receive dividends thereon. The nonvested shares are not transferable and are retained by Marathon until they vest.
	Marathon also grants restricted stock to certain non-officer employees under the Plan based on their performance within certain guidelines and for retention purposes. The restricted stock awards generally vest in one-third increments over a three-year period, contingent on the recipient’s continued employment. Prior to vesting, the restricted stock recipients have the right to vote such stock and receive dividends thereon. The nonvested shares are not transferable and are retained by Marathon until they vest.
	Unearned compensation is charged to stockholders’ equity when restricted stock and performance shares are granted. Compensation expense is recognized over the balance of the vesting period and is adjusted if conditions of the restricted stock or performance share grant are not met. Cash-based performance units are classified as a liability and compensation expense is recognized over the 36-month performance period based on expected payout.
	Marathon maintains an equity compensation program for its non-employee directors under the Plan. Pursuant to the program, non-employee directors must defer 50 percent of their annual retainers in the form of common stock units. In addition, each non-employee director receives an annual grant of non-retainer common stock units under the Plan. In 2005, the value of each grant was $60,000. The program also provides each non-employee director with a matching grant of up to 1,000 shares of common stock on his or her initial election to the Board if he or she purchases an equivalent number of shares within 60 days of joining the Board.
	Effective January 1, 2003, Marathon has applied the fair value based method of accounting to all grants and any modified grants of stock-based compensation. All prior outstanding and unvested awards continue to be accounted for under the intrinsic value method. The following net income and per share data illustrates the effect on net income and net income per share if the fair value method had been applied to all outstanding and unvested awards in each period.

(In millions, except per share data)			2005				2004				2003
Net income:
	As reported		$	3,032			$	1,261			$	1,321
	Add: Stock-based employee compensation expense included in reported net income, net of related tax effects			72				39				23
	Deduct: Total stock-based employee compensation expense determined under the fair value method for all awards, net of related tax effects			(72	)			(32	)			(17	)
Pro forma net income			$	3,032			$	1,268			$	1,327
Basic net income per share:
	– As reported		$	8.52			$	3.75			$	4.26
	– Pro forma		$	8.52			$	3.77			$	4.28
Diluted net income per share:
	– As reported		$	8.44			$	3.73			$	4.26
	– Pro forma		$	8.44			$	3.75			$	4.28

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	Marathon records compensation cost over the stated vesting period for stock options 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. Upon adoption of Statement of Financial Accounting Standards (“SFAS”) No. 123 (Revised 2004), “Share-Based Payment,” such compensation cost will be 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. The compensation cost determined under these two approaches did not differ materially for the periods presented above.
	The above pro forma amounts were based on a Black-Scholes option-pricing model, which included the following information and assumptions:

		2005				2004				2003
Weighted-average grant-date exercise price per share		$	50.28			$	33.61			$	25.58
Expected annual dividends per share		$	1.32			$	1.00			$	0.97
Expected life in years			5.5				5.5				5.0
Expected volatility			28	%			32	%			34	%
Risk-free interest rate			3.8	%			3.9	%			3.0	%
Weighted-average grant-date fair value of options granted during the year, as calculated from above		$	12.30			$	8.83			$	5.37

	Concentrations of credit risk – Marathon is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. While no single customer accounts for more than 10 percent of annual revenues, Marathon has significant exposures to United States Steel arising from the Separation. These exposures are discussed in Note 3.
	Reclassifications – Certain reclassifications of prior years’ data have been made to conform to 2005 classifications.

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

The pro forma net income and net income per share effect as if FIN No. 47 had been applied during 2005, 2004 and 2003 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.

(In millions)
January 1, 2003		$	384
December 31, 2003			438
December 31, 2004			527
December 31, 2005			711

	In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets – an amendment of APB Opinion No. 29.” This amendment eliminates the Accounting Principles Board (“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. Marathon adopted SFAS No. 153 on a prospective basis as of July 1, 2005.
	Effective January 1, 2005, Marathon adopted FASB Staff Position (“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

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	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 14.
	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 qualified production activities income as a special deduction in the years taken.
	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 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.
	Effective July 1, 2004, Marathon adopted FSP No. FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas-Producing Entities.” FSP No. FAS 142-2 states drilling and mineral rights of oil- and gas-producing entities are excluded from SFAS No. 142, “Goodwill and Other Intangible Assets,” and accordingly, should not be classified as intangible assets rather than oil and gas properties. The adoption of FSP No. FAS 142-2 did not have an effect on Marathon’s consolidated financial position, cash flows or results of operations.
	Effective January 1, 2003, Marathon adopted the provisions of SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” relating to the classification of the effects of early extinguishment of debt in the consolidated statement of income. As a result, losses from the early extinguishment of debt, which were previously reported as an extraordinary item, will be included in income from continuing operations before income taxes.
	Effective January 1, 2003, Marathon adopted the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” an amendment of SFAS No. 123, provides alternative methods for the transition of accounting for stock-based compensation from the intrinsic value method to the fair value method. Marathon has applied the fair value method to grants made, modified or settled on or after January 1, 2003.
	Effective January 1, 2003, Marathon adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” The transition adjustment related to adopting SFAS No. 143, was recognized as a cumulative effect of a change in accounting principle. The cumulative effect on net income of adopting SFAS No. 143 was a net favorable effect of $4 million, net of tax of $4 million. At the time of adoption, total assets increased $120 million, and total liabilities increased $116 million.

The 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

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	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.

	The Tax Sharing Agreement incorporates the general tax sharing principles of the former tax allocation policy. In general, Marathon and United States Steel will make payments between them such that, with respect to any consolidated, combined or unitary tax returns for any taxable period or portion thereof ending on or before the Separation Date, the amount of taxes to be paid by each of Marathon and United States Steel will be determined, subject to certain adjustments, as if the former groups each filed their own consolidated, combined or unitary tax return. The Tax Sharing Agreement also provides for payments between Marathon and United States Steel for certain tax adjustments that may be made after the Separation. Other provisions address, but are not limited to, the handling of tax audits, settlements and return filing in cases where both Marathon and United States Steel have an interest in the results of these activities.
	In 2005, 2004 and 2003, in accordance with the terms of the tax sharing agreement, Marathon paid $6 million, $3 million and $16 million to United States Steel in connection with the settlement with the Internal Revenue Service of the consolidated federal income tax returns of USX Corporation for the years 1992 through 1997. Included in discontinued operations in 2003 is an $8 million adjustment to the liabilities to United States Steel under this tax sharing agreement.

Relationship between Marathon and United States Steel after the Separation – As a result of the Separation, Marathon and United States Steel are separate companies and neither has any ownership interest in the other. As of December 31, 2005, Thomas J. Usher was the non-executive chairman of the board of both companies and four of the ten remaining members of Marathon’s board of directors are also directors of United States Steel. Mr. Usher retired as chairman of United States Steel on January 31, 2006. At that date, he and one other Marathon board member left United States Steel’s board of directors.

Sales to United States Steel in 2005, 2004 and 2003 were $31 million, $30 million and $31 million, primarily for natural gas. Purchases from United States Steel in 2005, 2004 and 2003 were $39 million, $27 million and $14 million, primarily for raw materials. Management believes that transactions with United States Steel were conducted under terms comparable to those with unrelated parties. Marathon reimbursed United States Steel $1 million and $3 million, respectively, in 2005 and 2004, for the payment of benefits to retirees, including Mr. Usher, under United States Steel’s 2001 plan of reorganization.

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.

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	At December 31, 2005 and 2004, amounts receivable from or payable to United States Steel included in the consolidated balance sheets were as follows:

(In millions)		December 31	2005				2004
Receivables related to debt and other obligations for which United States Steel has assumed responsibility for repayment:
	Current		$	20			$	15
	Noncurrent			532				587
Noncurrent reimbursements payable under nonqualified employee benefit plans			$	6			$	5

	Marathon remains primarily obligated for $45 million of operating lease obligations assumed by United States Steel, of which $37 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 28 for additional details on these guarantees.

	Related parties include:

	•	Ashland Inc. (“Ashland”), which held a 38 percent ownership interest in MPC, a consolidated subsidiary, until June 30, 2005;
	•	Compania Nacional de Petroleos de Guinea Ecuatorial (“GEPetrol”), Mitsui & Co., Ltd. (“Mitsui”) and Marubeni Corporation (“Marubeni”), which hold ownership interests in EGHoldings, a consolidated subsidiary; 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 Ashland and Pilot Travel Centers LLC (“PTC”) consist primarily of petroleum products. Revenues from related parties were as follows:

(In millions)				2005				2004				2003
Ashland				$	132			$	274			$	258
Equity method investees:
	PTC				1,205				715				635
	Centennial Pipeline LLC (“Centennial”)				47				49				16
	Other				18				13				12
		Total		$	1,402			$	1,051			$	921

	Purchases from related parties were as follows:

(In millions)				2005				2004				2003
Ashland				$	12			$	22			$	24
Equity method investees:
	Centennial				73				56				49
	Other				140				124				136
		Total		$	225			$	202			$	209

	Receivables from related parties were as follows:

(In millions)			December 31	2005				2004
Ashland				$	–			$	18
Equity method investees:
	PTC				34				19
	Alba Plant LLC				3				17
	Centennial				–				16
	Other				1				4
		Total		$	38			$	74

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	Payables to related parties were as follows:

(In millions)			December 31	2005				2004
GEPetrol				$	57			$	23
Equity method investees:
	Alba Plant LLC				14				–
	Centennial				1				12
	Other				10				9
		Total		$	82			$	44

	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, 2004 and 2003.
	Cash of $57 million held in escrow for future contributions to EGHoldings from GEPetrol is classified as restricted cash and is included in investments and long-term receivables as of December 31, 2005.

	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:

(In millions)
Cash(a)			$	487
MPC accounts receivable(a)				911
Marathon common stock(b)				955
Estimated additional consideration related to tax matters				58
Transaction-related costs				10
	Purchase price			2,421
Assumption of debt(c)				1,920
	Total consideration including debt assumption(d)		$	4,341

	(a)	The MAP Limited Liability Company Agreement was amended to eliminate the requirement for MPC to make quarterly cash distributions to Marathon and Ashland between the date the principal transaction agreements were signed and the closing of the Acquisition. Cash and MPC accounts receivable above include $506 million representing Ashland’s 38 percent of MPC’s distributable cash as of June 30, 2005.
	(b)	Ashland shareholders received 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.
	(c)	Assumed debt was repaid on July 1, 2005.
	(d)	Marathon is entitled to the tax deductions for Ashland’s future payments of certain contingent liabilities 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 these future payments. This contingent consideration will be included in the purchase price as such payments are made to Ashland.

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

	•	Marathon believes the outlook for the refining and marketing business is attractive in MPC’s core areas of operation. Complete ownership of MPC provides Marathon the opportunity to leverage MPC’s access to premium U.S. markets where Marathon expects the levels of demand to remain high for the foreseeable future;
	•	The Acquisition increases Marathon’s participation in the RM&T business without the risks commonly associated with integrating a newly acquired business;
	•	MPC provides Marathon with an increased source of cash flow which Marathon believes enhances the geographical balance in its overall risk portfolio;
	•	Marathon anticipates the transaction will 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.

(In millions)
Current assets:
	Cash and cash equivalents				$	518
	Receivables					1,080
	Inventories					1,866
	Other current assets					28
		Total current assets acquired				3,492
	Investments and long-term receivables					484
	Property, plant and equipment					2,671
	Goodwill					735
	Intangibles					112
	Other noncurrent assets					8
		Total assets acquired			$	7,502
Current liabilities:
	Notes payable				$	1,920
	Deferred income taxes					669
	Other current liabilities					1,694
		Total current liabilities assumed				4,283
Long-term debt						16
Deferred income taxes						265
Employee benefits obligations						484
Other liabilities						33
		Total liabilities assumed			$	5,081
			Net assets acquired		$	2,421

	The goodwill arising from the purchase price allocation was $735 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 life 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 a payment of $520 million from Marathon, which was made in January 2006. An additional payment estimated to be approximately $212 million is payable by Marathon within one year of the agreement date.

	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

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	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 is 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. Marathon is in the process of finalizing the fair value estimates for certain assets and liabilities; thus the allocation of the purchase price is preliminary.

(In millions)
Current assets:
	Inventories				$	10
	Other current assets					8
		Total current assets acquired				18
Property, plant and equipment						732
Goodwill						315
		Total assets acquired			$	1,065
Current liabilities:
	Accounts payable				$	10
Other liabilities						4
Deferred income taxes						319
		Total liabilities assumed			$	333
			Net assets acquired		$	732

	The goodwill arising from the preliminary purchase price allocation was $315 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 and other income			$	64,829			$	50,803
Income from continuing operations				3,807				1,559
Net income				3,290				1,563
Per share data:
	Income from continuing operations – basic		$	10.44			$	4.40
	Income from continuing operations – diluted		$	10.35			$	4.38
	Net income – basic		$	9.02			$	4.42
	Net income – diluted		$	8.95			$	4.39

	Khanty Mansiysk Oil Corporation

	On May 12, 2003, Marathon acquired Khanty Mansiysk Oil Corporation (“KMOC”) for $285 million, including the assumption of $31 million in debt. KMOC is engaged in evaluating or developing nine oil fields in the Khanty-Mansiysk region of western Siberia in the Russian Federation. Results of operations for 2003 include the results of KMOC from May 12, 2003.

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

(In millions, except per share amounts)			2003
Revenues and other income			$	41,257
Income from continuing operations				1,005
Net income				1,314
Per share data:
	Income from continuing operations – basic and diluted		$	3.24
	Net income – basic and diluted		$	4.23

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

				2005								2004								2003
(Dollars in millions, except per share data)				Basic				Diluted				Basic				Diluted				Basic				Diluted
Income from continuing operations				$	3,051			$	3,051			$	1,257			$	1,257			$	1,012			$	1,012
Income from discontinued operations					–				–				4				4				305				305
Cumulative effect of changes in accounting principles					(19	)			(19	)			–				–				4				4
Net income				$	3,032			$	3,032			$	1,261			$	1,261			$	1,321			$	1,321
Shares of common stock outstanding (thousands):
		Average number of common shares outstanding			356,003				356,003				336,485				336,485				310,129				310,129
		Effect of dilutive securities – stock options			–				3,078				–				1,768				–				197
		Average common shares including dilutive effect			356,003				359,081				336,485				338,253				310,129				310,326
Per share:
	Income from continuing operations			$	8.57			$	8.49			$	3.74			$	3.72			$	3.26			$	3.26
	Income from discontinued operations			$	–			$	–			$	0.01			$	0.01			$	0.99			$	0.99
	Cumulative effect of changes in accounting principles			$	(0.05	)		$	(0.05	)		$	–			$	–			$	0.01			$	0.01
	Net income			$	8.52			$	8.44			$	3.75			$	3.73			$	4.26			$	4.26

	Revenues by product line were:

(In millions)			2005				2004				2003
Refined products			$	40,040			$	29,780			$	24,092
Merchandise				2,689				2,489				2,395
Liquid hydrocarbons				16,677				13,860				10,500
Natural gas				3,675				3,266				3,796
Transportation and other				230				203				180
	Total		$	63,311			$	49,598			$	40,963

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

(In millions)			2005				2004				2003
Refined products			$	1,817			$	1,226			$	826
Liquid hydrocarbons				10,819				8,016				6,357
	Total		$	12,636			$	9,242			$	7,183

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	The following represents information by operating segment:

				Exploration				Refining,
				and				Marketing and				Integrated
(In millions)				Production				Transportation				Gas				Total
2005
Revenues:
	Customer			$	6,009			$	54,414			$	1,872			$	62,295
	Intersegment(a)				466				198				212				876
	Related parties				11				1,391				–				1,402
		Segment revenues			6,486				56,003				2,084				64,573
	Elimination of intersegment revenues				(466	)			(198	)			(212	)			(876	)
	Loss on long-term U.K. natural gas contracts				(386	)			–				–				(386	)
		Total revenues		$	5,634			$	55,805			$	1,872			$	63,311
Segment income				$	2,988			$	3,013			$	31			$	6,032
Income from equity method investments					67				137				62				266
Depreciation, depletion and amortization (b)					849				468				9				1,326
Capital expenditures(c)					1,460				841				572				2,873
2004
Revenues:
	Customer			$	4,618			$	42,435			$	1,593			$	48,646
	Intersegment(a)				370				152				146				668
	Related parties				8				1,043				–				1,051
		Segment revenues			4,996				43,630				1,739				50,365
	Elimination of intersegment revenues				(370	)			(152	)			(146	)			(668	)
	Loss on long-term U.K. natural gas contracts				(99	)			–				–				(99	)
		Total revenues		$	4,527			$	43,478			$	1,593			$	49,598
Segment income				$	1,696			$	1,406			$	48			$	3,150
Income from equity method investments					20				81				69				170
Depreciation, depletion and amortization (b)					750				416				8				1,174
Capital expenditures(c)					944				794				490				2,228
2003
Revenues:
	Customer			$	4,460			$	33,508			$	2,140			$	40,108
	Intersegment(a)				405				97				108				610
	Related parties				12				909				–				921
		Segment revenues			4,877				34,514				2,248				41,639
	Elimination of intersegment revenues				(405	)			(97	)			(108	)			(610	)
	Loss on long-term U.K. natural gas contracts				(66	)			–				–				(66	)
		Total revenues		$	4,406			$	34,417			$	2,140			$	40,963
Segment income				$	1,580			$	819			$	(3	)		$	2,396
Income from equity method investments(d)					50				82				21				153
Depreciation, depletion and amortization (b)					724				375				12				1,111
Capital expenditures(c)					973				789				131				1,893

	(a)	Management believes intersegment transactions were conducted under terms comparable to those with unrelated parties.
	(b)	Differences between segment totals and Marathon totals represent impairments and amounts related to corporate administrative activities and are included in administrative expenses in the reconciliation below.
	(c)	Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities.
	(d)	Excludes a $124 million loss on the dissolution of MKM Partners L.P., which was not allocated to segments. See Note 13.

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

(In millions)				2005				2004				2003
Segment income				$	6,032			$	3,150			$	2,396
Items not allocated to segments:
	Administrative expenses				(367	)			(307	)			(227	)
	Losses on long-term U.K. natural gas contracts				(386	)			(99	)			(66	)
	Gain on sale of minority interests in EGHoldings				23				–				–
	Impairment of certain oil and gas properties				–				(44	)			–
	Corporate insurance adjustment				–				(32	)			–
	Gain on asset disposition				–				–				106
	Loss on dissolution of MKM Partners L.P.				–				–				(124	)
	Gain (loss) on ownership changes in subsidiaries				–				2				(1	)
		Income from operations		$	5,302			$	2,670			$	2,084

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

						Revenues
						From Unaffiliated				From
(In millions)		Year				Customers				Affiliates				Total				Assets(a)
United States			2005			$	60,242			$	6			$	60,248			$	10,143
			2004				47,354				–				47,354				8,396
			2003				39,377				–				39,377				8,061
United Kingdom			2005			$	1,569			$	64			$	1,633			$	984
			2004				995				–				995				1,076
			2003				849				–				849				1,215
Equatorial Guinea			2005			$	45			$	598			$	643			$	3,018
			2004				247				–				247				2,444
			2003				119				–				119				1,656
Other Foreign Countries			2005			$	1,455			$	2,126			$	3,581			$	2,526
			2004				1,002				1,868				2,870				1,231
			2003				618				1,352				1,970				1,073
Eliminations			2005			$	–			$	(2,794	)		$	(2,794	)		$	–
			2004				–				(1,868	)			(1,868	)			–
			2003				–				(1,352	)			(1,352	)			–
Total			2005			$	63,311			$	–			$	63,311			$	16,671
			2004				49,598				–				49,598				13,147
			2003				40,963				–				40,963				12,005

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

(In millions)				2005				2004				2003
Interest and other financial income:
	Interest income			$	78			$	45			$	16
	Foreign currency adjustments				(17	)			9				13
		Total			61				54				29
Interest and other financing costs:
	Interest incurred(a)				257				262				282
	Less income from interest rate swaps				–				24				23
	Less interest capitalized				83				48				41
		Net interest expense			174				190				218
	Interest on tax issues				22				12				(13	)
	Other				10				13				10
		Total			206				215				215
Net interest and other financing costs				$	145			$	161			$	186

	(a)	Excludes $34 million, $40 million and $34 million paid by United States Steel in 2005, 2004 and 2003 on assumed debt.

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	Aggregate foreign currency losses were included in the consolidated statements of income as follows:

(In millions)			2005				2004				2003
Net interest and other financing costs			$	(17	)		$	9			$	13
Provision for income taxes				(24	)			(15	)			(15	)
	Aggregate foreign currency losses		$	(41	)		$	(6	)		$	(2	)

	Provisions (credits) for income taxes were:

			2005												2004												2003
(In millions)			Current				Deferred				Total				Current				Deferred				Total				Current				Deferred				Total
Federal			$	1,227			$	16			$	1,243			$	473			$	(22	)		$	451			$	280			$	95			$	375
State and local				171				12				183				47				1				48				56				(4	)			52
Foreign				540				(236	)			304				280				(52	)			228				177				(20	)			157
	Total		$	1,938			$	(208	)		$	1,730			$	800			$	(73	)		$	727			$	513			$	71			$	584

	A reconciliation of the federal statutory tax rate (35 percent) applied to income before income taxes to the total provisions for income taxes follows:

(In millions)			2005				2004				2003
Statutory rate applied to income before income taxes			$	1,673			$	694			$	559
Effects of foreign operations, including foreign tax credits				(44	)			26				(7	)
State and local income taxes after federal income tax effects				119				32				35
Credits other than foreign tax credits				(2	)			(2	)			(6	)
Domestic production activities deduction(a)				(39	)			–				–
Excess capital losses generated (utilized)				23				(4	)			–
Effects of partially owned companies				(4	)			(3	)			(6	)
Adjustment of prior years’ federal income taxes				10				(11	)			17
Other				(6	)			(5	)			(8	)
	Total provisions for income taxes		$	1,730			$	727			$	584

	(a)	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 for 2005 under the American Jobs Creation Act of 2004, as a special deduction.

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	Deferred tax assets and liabilities resulted from the following:

(In millions)					December 31	2005				2004
Deferred tax assets:
	Net operating loss carryforwards					$	–			$	2
	Capital loss carryforwards (expiring in 2008 and 2010)						79				57
	State tax loss carryforwards (expiring in 2006 through 2021)						105				122
	Foreign tax loss carryforwards(a)						649				581
	Expected federal benefit for:
		Crediting certain foreign deferred income taxes					123				292
		Deducting state and foreign deferred income taxes					183				37
	Employee benefits						678				341
	Contingencies and other accruals						295				201
	Derivative instruments						196				40
	Investments in subsidiaries and equity method investees						–				4
	Other						101				86
	Valuation allowances(b):
		Federal					(120	)			(57	)
		State					(72	)			(71	)
		Foreign					(435	)			(365	)
			Total deferred tax assets(c)				1,782				1,270
Deferred tax liabilities:
	Property, plant and equipment						3,072				2,174
	Inventory						775				304
	Investments in subsidiaries and equity method investees						94				–
	Prepaid pensions						47				70
	Other						112				88
			Total deferred tax liabilities				4,100				2,636
				Net deferred tax liabilities		$	2,318			$	1,366

	(a)	For 2005, includes $547 million for Norway and $54 million for Angola, both of which have no expiration dates. The remainder expire 2006 through 2019.
	(b)	Valuation allowances related to federal deferred tax assets are associated with capital loss carryforwards. The remaining valuation allowances are primarily associated with net operating loss carryforwards in several state jurisdictions, Norway, Angola and several other foreign jurisdictions.
	(c)	Marathon expects to generate sufficient future taxable income to realize the benefit of the deferred tax assets. In addition, the ability to realize the benefit of foreign tax credits is based on certain assumptions concerning future operating conditions (particularly as related to prevailing oil prices), income generated from foreign sources and Marathon’s tax profile in the years that such credits may be claimed.

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

(In millions)			December 31	2005				2004
Assets:
	Other current assets			$	14			$	127
	Other noncurrent assets				148				60
Liabilities:
	Current deferred income taxes				450				–
	Noncurrent deferred income taxes				2,030				1,553
		Net deferred tax liabilities		$	2,318			$	1,366

	Marathon is continuously undergoing examination of its federal income tax returns by the Internal Revenue Service (“IRS”). Marathon and the IRS have settled tax years through 1997 and Marathon is in appeals for tax years 1998 through 2001. Audits for the tax years 2002 and 2003 are in progress and audits for tax years 2004 and 2005 will commence in 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 on occasion, foreign jurisdiction tax audits. Marathon believes all other audits will be resolved within the amounts paid and/or provided for these liabilities.
	Pretax income from continuing operations included amounts attributable to foreign sources of $1.127 billion in 2005, $534 million in 2004 and $453 million in 2003.
	Undistributed income of certain consolidated foreign subsidiaries at December 31, 2005 amounted to $1.544 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 deferred tax liability of $541 million would have been required.
	See Note 3 for a discussion of the Tax Sharing Agreement between Marathon and United States Steel.

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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 and 2003, Marathon recorded $43 million and $24 million of costs as general and administrative expenses related to these business transformation programs. These charges included employee severance and benefit costs related to the elimination of approximately 700 regular employee positions, relocation costs, net benefit plans settlement and curtailment losses and fixed asset related costs.
	There were minimal charges to expense during 2005 and, 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 and 2003.

			Accrued								Noncash				Cash				Accrued
(In millions)			January 1				Expense				Charges (Gains)				Payments				December 31
2004
Employee severance and termination benefits			$	12			$	15			$	–			$	24			$	3
Net benefit plans settlement and curtailment losses				–				20				20				–				–
Relocation costs				5				8				–				11				2
Fixed asset related costs				1				–				–				1				–
	Total		$	18			$	43			$	20			$	36			$	5
2003
Employee severance and termination benefits			$	–			$	25			$	–			$	13			$	12
Net benefit plans settlement and curtailment gains				–				(10	)			(10	)			–				–
Relocation costs				–				5				–				–				5
Fixed asset related costs				–				4				2				1				1
	Total		$	–			$	24			$	(8	)		$	14			$	18

(In millions)		December 31		2005				2004
Liquid hydrocarbons and natural gas				$	1,093			$	676
Refined products and merchandise					1,763				1,192
Supplies and sundry items					185				127
	Total (at cost)			$	3,041			$	1,995

The LIFO method accounted for 92 percent of total inventory value at December 31, 2005 and 2004. Current acquisition costs were estimated to exceed the LIFO inventory values at December 31, 2005 and 2004 by approximately $1,535 million and $1,294 million. Cost of revenues and income from operations showed no change in 2005 as a result of liquidations of LIFO inventories. Cost of revenues was reduced and income from operations was increased by $4 million in 2004, and $11 million in 2003 as a result of liquidations of LIFO inventories.

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(In millions)			December 31	2005				2004
Equity method investments:
	Alba Plant LLC			$	513			$	432
	Atlantic Methanol Production Company LLC				258				265
	Pilot Travel Centers LLC				516				372
	LOOP LLC				148				60
	Other				220				205
Other investments					5				3
Recoverable environmental costs receivable					57				52
Value-added tax refunds receivable					29				32
Fair value of derivative assets					14				24
Deposits of restricted cash					87				89
Other receivables					17				12
		Total		$	1,864			$	1,546

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

(In millions)			2005				2004				2003
Income data – year:
	Revenues and other income		$	10,088			$	7,419			$	7,036
	Operating income			556				434				435
	Net income			474				330				319
Balance sheet data – December 31:
	Current assets		$	645			$	583
	Noncurrent assets			3,598				3,990
	Current liabilities			668				569
	Noncurrent liabilities			1,477				1,511

	Marathon’s carrying value of its equity method investments is $643 million higher than the underlying net assets of investees. This basis difference is being amortized into income over the remaining useful lives of the underlying net assets 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 $200 million in 2005, $152 million in 2004, and $175 million in 2003.
	On June 30, 2003, Marathon and Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”) dissolved MKM Partners L.P. which had oil and gas production operations in the Permian Basin of Texas. Marathon held an 85 percent noncontrolling interest in the partnership. Prior to the dissolution of the partnership, Kinder Morgan acquired MKM Partners L.P.’s 12.75 percent interest in the SACROC unit for an undisclosed amount. The partnership recorded a loss on the disposal of SACROC of $19 million, of which Marathon’s share was $17 million. Also prior to the dissolution, Marathon recorded a $107 million impairment of its investment in MKM Partners L.P. due to an other-than-temporary decline in the fair value of the investment. The total loss recognized by Marathon related to the dissolution of MKM Partners L.P. was $124 million. The partnership’s interest in the Yates field was distributed to Marathon and Kinder Morgan on dissolution.

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(In millions)		December 31	2005				2004
Production			$	17,262			$	15,162
Refining				4,727				4,398
Marketing				1,895				1,954
Transportation				1,980				1,816
Gas liquefaction				1,067				524
Other				464				382
	Total			27,395				24,236
Less accumulated depreciation, depletion and amortization				12,384				12,426
	Net property, plant and equipment		$	15,011			$	11,810

	Property, plant and equipment includes gross assets acquired under capital leases of $78 million and $49 million at December 31, 2005 and 2004, with related amounts in accumulated depreciation, depletion and amortization of $6 million and $6 million at December 31, 2005 and 2004.
	Deferred exploratory well costs were as follows:

(Dollars in millions)		December 31	2005				2004				2003
Amounts capitalized less than one year after completion of drilling			$	304			$	284			$	165
Amounts capitalized greater than one year after completion of drilling				59				55				78
	Total deferred exploratory well costs		$	363			$	339			$	243
Number of projects with costs capitalized for greater than one year after completion of drilling				2				2				4

	Exploratory well costs capitalized greater than one year after completion of drilling as of December 31, 2005 included $43 million for the Ozona prospect that was primarily incurred in 2001 and 2002 and $16 million for the Flathead prospect that was primarily incurred in 2001. Both prospects are located in the Gulf of Mexico. Marathon’s plans are to develop the Ozona prospect as a subsea tieback to area infrastructure. Commercial terms have been secured for the tieback and processing of Ozona production and Marathon is attempting to secure a drilling rig to drill the development well. Technical evaluations on the Flathead prospect continued during 2005 and are progressing towards a potential re-entry and sidetrack well before 2008. In 2005, a well drilled on a block directly offsetting the Flathead prospect encountered hydrocarbons.
	The net changes in deferred exploratory well costs were as follows:

		Balance at												Transfer to								Balance
		Beginning of								Dry Well				Proved								at End
(In millions)		Period				Additions				Expense				Properties				Other				of Period
Year ended December 31, 2005		$	339			$	135			$	(31	)		$	(80	)		$	–			$	363
Year ended December 31, 2004			243				239				(54	)			(89	)			–				339
Year ended December 31, 2003			148				256				(56	)			(90	)			(15	) (a)			243

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

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	The changes in the carrying amount of goodwill for the years ended December 31, 2005 and 2004, are as follows:

			Exploration				Refining, Marketing
			and				and
(In millions)			Production				Transportation				Total
Balance as of January 1 and December 31, 2004			$	231			$	21			$	252
	Goodwill acquired			315				735				1,050
	Other			–				5				5
Balance as of December 31, 2005			$	546			$	761			$	1,307

	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.

	Intangible assets are as follows:

				Gross								Net
				Carrying				Accumulated				Carrying
(In millions)			December 31	Amount				Amortization				Amount
2005
Amortized intangible assets:
	Branding agreements			$	51			$	16			$	35
	Elba Island delivery rights				42				6				36
	Other				96				36				60
		Total		$	189			$	58			$	131
Unamortized intangible assets:
	Retail marketing tradenames			$	49			$	–			$	49
	Unrecognized prior service costs and other				20				–				20
		Total		$	69			$	–			$	69
2004
Amortized intangible assets:
	Branding agreements			$	53			$	19			$	34
	Elba Island delivery rights				42				5				37
	Other				49				27				22
		Total		$	144			$	51			$	93
Unamortized intangible assets:
	Unrecognized prior service costs and other			$	25			$	–			$	25

	Amortization expense related to intangibles during 2005, 2004 and 2003 totaled $16 million, $7 million and $12 million. Estimated amortization expense for the years 2006-2010 is $20 million, $15 million, $13 million, $12 million and $11 million.

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	The following table sets forth quantitative information by category of derivative instrument at December 31, 2005 and 2004. These amounts are reported on a gross basis by individual derivative instrument.

				2005								2004
(In millions)			December 31	Assets(a)				(Liabilities)(a)				Assets(a)				(Liabilities)(a)
Commodity Instruments
	Fair value hedges(b):
		Exchange traded commodity futures		$	2			$	(2	)		$	2			$	(1	)
		Over-the-counter (“OTC”) commodity swaps			66				(2	)			27				–
	Non-hedge designation:
		Exchange-traded commodity futures		$	281			$	(288	)		$	222			$	(210	)
		Exchange-traded commodity options			70				(65	)			79				(65	)
		OTC commodity swaps			105				(99	)			101				(61	)
		OTC commodity options			3				(6	)			5				(4	)
Nontraditional Instruments
		United Kingdom long-term natural gas contracts(d)		$	–			$	(513	)		$	–			$	(127	)
		Physical commodity contracts(e)			71				(62	)			86				(91	)
Financial Instruments
	Fair value hedges:
		OTC interest rate swaps(f)		$	–			$	(30	)		$	2			$	(12	)
	Cash flow hedges(c):
		OTC foreign currency swaps			–				(2	)			10				(1	)

	(a)	The fair value and carrying value of derivative instruments are the same. The fair values for OTC positions are determined using option-pricing models or dealer quotes. The fair values of exchange-traded positions are based on market quotes derived from major exchanges. The fair value of interest rate and foreign currency swaps is based on dealer quotes. Marathon’s consolidated balance sheet is reported on a net asset/(liability) basis by brokerage firm, as permitted by the master netting agreements.
	(b)	There was no ineffectiveness associated with fair value hedges for 2005 or 2004 because the hedging instruments and the existing firm commitment contracts are priced on the same underlying index. Certain derivative instruments used in the fair value hedges mature between 2006 and 2008.
	(c)	The ineffective portion of changes in the fair value for cash flow hedges, on a before tax basis, was less than $1 million during 2005 and $1 million during 2004. In addition, during 2004, losses of $3 million were recognized in revenues as the result of a discontinuation of a portion of a cash flow hedge related to natural gas and crude oil production. There were no losses recorded in 2005 relating to a discontinuation. Of the unrealized gains and losses recorded in accumulated other comprehensive loss as of December 31, 2005, a net gain of $2 million is expected to be reclassified to income in 2006.
	(d)	The contract price under the U.K. long-term natural gas contracts is reset annually and is indexed to a basket of costs of living and energy commodity indices for the previous twelve months. The fair value of these contracts is determined by applying the difference between the contract price and the U.K. forward gas strip price to the expected sales volumes under these contracts for the next 18 months. The eighteen-month period represents approximately 90 percent of market liquidity in that region.
	(e)	Certain physical commodity contracts are classified as nontraditional derivative instruments because certain volumes covered by these contracts are physically netted at particular delivery locations. Additionally, other physical contracts that involve flash title are accounted for as nontraditional derivative instruments.

	(f)	The fair value of OTC interest rate swaps excludes accrued interest amounts not yet settled. As of December 31, 2005 and 2004, accrued interest approximated $3 million and $4 million. The net fair value of the OTC interest rate swaps as of December 31, 2005 and 2004 is included in long-term debt. See Note 20.

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Fair value of the financial instruments disclosed herein is not necessarily representative of the amount that could be realized or settled, nor does the fair value amount consider the tax consequences of realization or settlement. The following table summarizes financial instruments, excluding derivative financial instruments disclosed in Note 17, by individual balance sheet line item. Marathon’s financial instruments at December 31, 2005 and 2004 were:

				2005								2004
				Fair				Carrying				Fair				Carrying
(In millions)			December 31	Value				Amount				Value				Amount
Financial assets:
	Cash and cash equivalents			$	2,617			$	2,617			$	3,369			$	3,369
	Receivables				3,514				3,514				3,220				3,220
	Receivables from United States Steel				540				552				590				602
	Investments and long-term receivables				268				195				266				188
		Total financial assets		$	6,939			$	6,878			$	7,445			$	7,379
Financial liabilities:
	Accounts payable			$	5,435			$	5,435			$	4,474			$	4,474
	Consideration payable under Libya re-entry agreement				732				732				–				–
	Payables to United States Steel				6				6				5				5
	Accrued interest				96				96				92				92
	Long-term debt due within one year				315				315				16				16
	Long-term debt				4,039				3,560				4,464				3,909
		Total financial liabilities		$	10,623			$	10,144			$	9,051			$	8,496

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

	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 20. At December 31, 2005, there were no commercial paper borrowings outstanding.

	Additionally, as part of the Acquisition on June 30, 2005 discussed in Note 5, Marathon assumed $1.920 billion in debt which was repaid on July 1, 2005.

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(In millions)		December 31		2005				2004
Marathon Oil Corporation:
	Revolving credit facility due 2009(a)			$	–			$	–
	6.650% notes due 2006				300				300
	5.375% notes due 2007(b)				450				450
	6.850% notes due 2008				400				400
	6.125% notes due 2012(b)				450				450
	6.000% notes due 2012(b)				400				400
	6.800% notes due 2032(b)				550				550
	9.375% debentures due 2012				163				163
	9.125% debentures due 2013				271				271
	9.375% debentures due 2022				81				81
	8.500% debentures due 2023				123				123
	8.125% debentures due 2023				229				229
	6.570% promissory note due 2006(b)				2				9
	Series A medium term notes due 2022				3				3
	4.750% – 6.875% obligations relating to industrial development and environmental improvement bonds and notes due 2009 – 2033(c)				453				496
	Sale-leaseback financing due 2006 – 2012(d)				66				71
	Capital lease obligation due 2012(e)				49				51
Consolidated subsidiaries:
	Revolving credit facility due 2009(a)				–				–
	Capital lease obligations due 2006 – 2020				61				44
		Total(f)(g)			4,051				4,091
Unamortized discount					(8	)			(8	)
Fair value adjustments on notes subject to hedging(h)					(30	)			(10	)
Amounts due within one year					(315	)			(16	)
		Long-term debt due after one year		$	3,698			$	4,057

	(a)	Marathon has a $1.5 billion five-year revolving credit agreement and MPC has a $500 million five-year revolving credit facility, both of which terminate in May 2009. These facilities each require a representation at an initial borrowing that there has been no change in the respective borrower’s consolidated financial position or operations, considered as a whole, that would materially and adversely affect such borrower’s ability to perform its obligations under its revolving credit facility. Interest on these facilities is based on defined short-term market rates. During the term of the agreements, Marathon is obligated to pay a variable facility fee on total commitments, which at December 31, 2005 was 0.125%. At December 31, 2005, there were no borrowings against these facilities.
	(b)	These notes contain a make-whole provision allowing Marathon the right to repay the debt at a premium to market price.

	(c)	United States Steel has assumed responsibility for repayment of $428 million of these obligations.

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

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

	(f)	Required payments of long-term debt for the years 2007-2010 are $317 million, $474 million, $417 million and $19 million, respectively. Of these amounts, payments assumed by United States Steel are $16 million, $24 million, $17 million and $19 million, respectively.

	(g)	In the event of a change in control of Marathon, as defined in the related agreements, debt obligations totaling $1.573 billion at December 31, 2005, may be declared immediately due and payable.

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

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. If any receivables were sold under the facility, MPC would not guarantee the transferred receivables and would have no obligations upon default. During the term of the agreement MPC was obligated to pay a facility fee of 0.12%. Subsequent to December 31, 2005, the facility was terminated. No receivables were sold under the agreement during its term.

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(In millions)						2005				2004				2003
Net cash provided from operating activities from continuing operations included:
	Interest and other financing costs paid (net of amounts capitalized)					$	174			$	206			$	254
	Income taxes paid to taxing authorities						1,544				674				537
	Income tax settlements paid to United States Steel						6				3				16
Commercial paper and revolving credit arrangements – net:
	Commercial paper		– issued			$	3,896			$	–			$	4,733
			– repayments				(3,896	)			–				(4,833	)
	Credit agreements		– borrowings				10				–				3
			– repayments				(10	)			–				(34	)
	Ashland credit agreements			– borrowings			–				653				182
				– repayments			–				(653	)			(182	)
			Total			$	–			$	–			$	(131	)
Noncash investing and financing activities:
	Asset retirement costs capitalized					$	171			$	66			$	61
	Debt payments assumed by United States Steel						44				13				5
	Capital lease obligations:
		Assets acquired					18				–				41
		Assumed by United States Steel					8				–				59
	Net assets contributed to joint ventures						7				3				42
	Acquisitions:
		Debt and other liabilities assumed					5,414				–				110
		Common stock issued to seller					955				–				–
		Receivables transferred to seller					911				–				–
	Disposal of assets:
		Asset retirement obligations assumed by buyer					6				–				15
	Joint venture dissolution						–				–				212
	Liabilities assumed by buyer of discontinued operations						–				–				212

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	The following summarizes the obligations and funded status for Marathon’s pension and other postretirement benefit plans:

		Pension Benefits																Other Benefits
		2005								2004								2005				2004
(In millions)		U.S.				Int’l				U.S.				Int’l
Change in benefit obligations
Benefit obligations at January 1		$	1,750			$	322			$	1,591			$	262			$	697			$	733
Service cost			109				11				94				9				20				18
Interest cost			104				16				95				14				38				42
Actuarial (gain) loss			187	(a)			(6	)			160				41				40	(a)			(65	) (b)
Plan amendment			–				–				–				–				10				–
Net settlements and curtailments			–				–				(84	)			–				–				(1	)
Mergers and acquisitions(c)			2				–				–				–				2				–
Benefits paid			(97	)			(5	)			(106	)			(4	)			(31	)			(30	)
Benefit obligations at December 31		$	2,055			$	338			$	1,750			$	322			$	776			$	697
Change in plan assets
Fair value of plan assets at January 1		$	949			$	185			$	936			$	139
Actual return on plan assets			45				16				79				27
Employer contribution			128				26				121				24
Settlement payments			–				–				(81	)			–
Benefits paid from plan assets			(97	)			(5	)			(106	)			(5	)
Fair value of plan assets at December 31		$	1,025			$	222			$	949			$	185
Funded status of plans at December 31		$	(1,030	)		$	(116	)		$	(801	)		$	(137	)		$	(776	)		$	(697	)
Unrecognized net transition asset			–				–				(4	)			–				–				–
Unrecognized prior service costs (credits)			23				–				33				–				(64	)			(91	)
Unrecognized net losses			651				106				730				127				184				183
Accrued benefit cost		$	(356	)		$	(10	)		$	(42	)		$	(10	)		$	(656	)		$	(605	)
Amounts recognized in the consolidated balance sheet:
Prepaid benefit cost		$	–			$	–			$	128			$	–			$	–			$	–
Accrued benefit liability			(520	)			(91	)			(257	)			(81	)			(656	)			(605	)
Intangible asset			16				–				20				–				–				–
Accumulated other comprehensive income(d)			148				81				67				71				–				–
Prepaid (accrued) benefit cost		$	(356	)		$	(10	)		$	(42	)		$	(10	)		$	(656	)		$	(605	)

	(a)	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 obligations by $109 million.
	(b)	Includes the impact related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, which reduced the obligation by $93 million.
	(c)	Includes the addition of certain employees of the maleic anhydride business acquired as part of the Acquisition.
	(d)	Excludes the effects of minority interest as of December 31, 2004 and income taxes.

	The accumulated benefit obligation for all defined benefit pension plans was $1.748 billion and $1.423 billion at December 31, 2005 and 2004, respectively. Other Benefits in the above table is not applicable to Marathon’s foreign subsidiaries as those subsidiaries do not sponsor any postretirement plans other than pension plans.
	The following summarizes all defined benefit pension plans that have accumulated benefit obligations in excess of plan assets:

		2005								2004
(In millions)	December 31	U.S.				Int’l				U.S.				Int’l
Projected benefit obligations		$	(2,055	)		$	(338	)		$	(1,248	)		$	(322	)
Accumulated benefit obligations			(1,435	)			(313	)			(790	)			(265	)
Fair value of plan assets			1,025				222				535				185

On June 30, 2005, as a result of the Acquisition, MPC’s pension and other postretirement benefit 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 pension and other postretirement benefit plans. As a result, obligations related to the pension and other postretirement benefit plans increased by $264 million and $28 million.

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	The following summarizes the net periodic benefit costs for Marathon’s pension and other postretirement benefit plans.

			Pension Benefits																								Other Benefits
			2005								2004								2003								2005				2004				2003
(In millions)			U.S.				Int’l				U.S.				Int’l				U.S.				Int’l
Components of net periodic benefit cost
Service cost			$	109			$	11			$	94			$	9			$	87			$	7			$	20			$	18			$	21
Interest cost				104				16				95				14				90				11				38				42				46
Expected return on plan assets				(83	)			(12	)			(84	)			(10	)			(84	)			(7	)			–				–				–
Amortization	– net transition gain			(3	)			–				(4	)			–				(4	)			–				–				–				–
	– prior service costs (credits)			4				–				4				–				5				–				(12	)			(14	)			(10	)
	– actuarial loss			47				8				39				7				32				5				7				11				12
Multi-employer and other plans				2				–				2				–				2				–				3				3				2
Settlement, curtailment and termination losses (gains)(a)				–				–				37				–				6				1				–				(9	)			(16	)
Net periodic benefit cost			$	180			$	23			$	183			$	20			$	134			$	17			$	56			$	51			$	55

	(a)	Includes business transformation costs.

		Pension Benefits																								Other Benefits
		2005								2004								2003								2005				2004				2003
(In millions)		U.S.				Int’l				U.S.				Int’l				U.S.				Int’l
Increase (decrease) in minimum liability included in other comprehensive income, excluding tax effects and minority interest		$	81			$	10			$	(18	)		$	(13	)		$	33			$	52				N/A				N/A				N/A

	The following summarizes the assumptions used to determine the benefit obligations and net periodic benefit costs for Marathon’s pension and other postretirement benefit plans.

			Pension Benefits																								Other Benefits
			2005								2004								2003								2005				2004				2003
			U.S.				Int’l				U.S.				Int’l				U.S.				Int’l
Weighted-average assumptions used to determine benefit obligation at December 31:
	Discount rate			5.50%				4.70%				5.75%				5.30%				6.25%				5.40%				5.75%				5.75%				6.25%
	Rate of compensation increase			4.50%				4.55%				4.50%				4.60%				4.50%				4.50%				4.50%				4.50%				4.50%
Weighted average actuarial assumptions used to determine net periodic benefit cost for years ended December 31:
	Discount rate(a)			5.57%				5.30%				6.25%				5.40%				6.50%				5.50%				5.57%				6.25%				6.50%
	Expected long-term return on plan assets			8.50%				6.87%				9.00%				6.87%				9.00%				7.00%				N/A				N/A				N/A
	Rate of compensation increase			4.50%				4.60%				4.50%				4.50%				4.50%				4.25%				4.50%				4.50%				4.50%

	(a)	On June 30, 2005 due to the Acquisition, MPC’s discount rate was decreased to 5.25% from 5.75%.

Historical markets are studied and long-term historical relationships between equities and fixed income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long term. 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 historical returns for reasonableness and appropriateness.

	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

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	2.5 percent greater than the yield on local government bonds. Expected returns on debt securities are taken directly at market yields and cash is taken at the local currency base rate.

	The following summarizes the assumed health care cost trend rates:

December 31		2005				2004				2003
Health care cost trend rate assumed for next year			8.5	%			9.0	%			9.5	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)			5.0	%			5.0	%			5.0	%
Year that the rate reaches the ultimate trend rate			2012				2012				2012

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

		1-Percentage-				1-Percentage-
(In millions)		Point Increase				Point Decrease
Effect on total of service and interest cost components		$	11			$	(9	)
Effect on other postretirement benefit obligations			120				(102	)

	The following summarizes the pension plans’ weighted-average asset allocations by asset category:

			2005								2004
			U.S.				Int’l				U.S.				Int’l
Equity securities				76	%			74	%			78	%			73	%
Debt securities				22	%			24	%			21	%			24	%
Real estate				2	%			–				1	%			–
Other				–				2	%			–				3	%
	Total			100	%			100	%			100	%			100	%

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 equities and 25 percent debt securities. Management of the plans’ assets is delegated to the United States Steel and Carnegie Pension Fund. The fund manager has discretion to move away from the target allocations based upon the manager’s judgment as to current confidence or concern for the capital markets. Investments are diversified by industry and type, limited by grade and maturity. The policy prohibits investments in any securities in the steel industry and allows derivatives subject to strict guidelines. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.

The objective of the investment policy is to achieve a long-term return which is consistent with assumptions made by the actuary in determining the funding requirements of the plans. The target asset allocation of approximately 75 percent equities and 25 percent debt securities and the unitized pool approach meets this objective and controls the various risks to which the plans’ assets are exposed, including matching the timing of estimated future obligations to the maturities of the plans’ assets. The day-to-day management of the plans’ assets 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.

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	Marathon expects to make contributions to their funded pension plans in 2006 of between $155 million and $345 million. Cash contributions to be paid from the general assets of the Company for both the unfunded pension and postretirement benefit plans are expected to be approximately $3 million and $39 million in 2006.

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

		Pension								Other
		Benefits								Benefits(a)
(In millions)		U.S.				Int’l
2006		$	122			$	5			$	39
2007			136				6				41
2008			153				7				43
2009			171				8				47
2010			186				9				50
2011 through 2015			1,144				65				293

	(a)	Expected Medicare reimbursements for 2006 through 2015 total $50 million.

	Marathon also contributes to several defined contribution plans for eligible employees. Contributions to these plans totaled $39 million in 2005, $35 million in 2004 and $37 million in 2003.

	Changes in asset retirement obligations during the year were:

(In millions)			2005				2004
Asset retirement obligations as of January 1			$	477			$	390
	Liabilities incurred			20				17
	Liabilities settled			(9	)			(3	)
	Accretion expense (included in depreciation, depletion and amortization)			29				24
	Adoption of FIN No. 47			53				–
	Revisions of previous estimates			141				49
Asset retirement obligations as of December 31			$	711			$	477

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

			Shares				Price(a)
Balance December 31, 2002				8,064,610			$	28.70
	Granted			1,729,800				25.58
	Exercised			(642,265	)			24.48
	Canceled			(145,765	)			30.27
Balance December 31, 2003				9,006,380				28.33
	Granted			2,067,300				33.28
	Exercised			(2,963,546	)			17.17
	Canceled			(96,886	)			30.78
Balance December 31, 2004				8,013,248				29.84
	Granted			1,894,720				50.28
	Exercised			(3,786,828	)			29.37
	Canceled			(161,486	)			34.96
Balance December 31, 2005(b)				5,959,654				36.50

	(a)	Weighted-average exercise price.
	(b)	Of the options outstanding as of December 31, 2005, 4,851,892 and 1,107,762 were outstanding under the 2003 Incentive Compensation Plan and 1990 Stock Plan.

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	The following table presents information on stock options and SARs at December 31, 2005:

			Outstanding												Exercisable
			Number												Number
Range of			of Shares				Weighted-Average								of Shares
Exercise			Under				Remaining				Weighted-Average				Under				Weighted-Average
Prices			Option				Contractual Life				Exercise Price				Option				Exercise Price
$22.38 – 25.52				1,267,428				6.6			$	25.49				744,830			$	25.48
$26.91 – 30.88				637,360				5.6				28.44				625,694				28.43
$32.52 – 34.00				2,190,246				7.7				33.48				897,602				33.30
$47.65 – 51.67				1,864,620				9.5				50.28				–				–
	Total			5,959,654				7.9				36.50				2,268,126				29.39

	The following table presents information on restricted stock grants:

			2005				2004				2003
2003 Incentive Compensation Plan:(a)
	Number of shares granted			633,420				360,070				293,710
	Weighted-average grant-date fair value per share		$	54.24			$	34.42			$	26.01
1990 Stock Plan:(b)
	Number of shares granted			–				99,613				39,960
	Weighted-average grant-date fair value per share			–			$	33.61			$	25.52

	(a)	Of the shares granted under the 2003 Incentive Compensation Plan, 52,226 have vested and 95,656 have been cancelled or forfeited. In addition to the shares, 140,000 restricted stock units have been granted to international participants under the plan, 4,182 have vested and 1,900 have been cancelled or forfeited. Thus, as of December 31, 2005, 1,139,318 shares and 133,918 units were outstanding under the plan.
	(b)	Of the shares granted under the 1990 Stock Plan, 610,016 have vested and 314,956 have been cancelled or forfeited. As of December 31, 2005, no additional shares remain outstanding under the plan.

	In 2005, 6,975,600 cash-based performance units were granted to officers under the 2003 Incentive Compensation Plan, none have vested and 144,800 have been cancelled or forfeited. Thus, as of December 31, 2005, 6,830,800 units were outstanding under the Plan. The target value of each performance unit granted is $1, with actual payout varying from zero percent to 200 percent of the target value based on a 36-month measurement period.
	On January 1, 2005 and 2004, each non-employee director was granted additional stock-based compensation valued at $60,000 and $40,000, respectively, in the form of common stock units. Common stock units are book entry units equal in value to a share of stock. During 2005, 2004 and 2003, 24,982, 21,786 and 15,799 units of stock were issued.

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:

			Capital				Operating
			Lease				Lease
(In millions)			Obligations				Obligations
2006			$	27			$	111
2007				36				61
2008				27				52
2009				27				43
2010				28				35
Later years				96				258
Sublease rentals				–				(43	)
	Total minimum lease payments			241			$	517
Less imputed interest costs				65
	Present value of net minimum lease payments included in long-term debt		$	176

	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

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	primarily obligated for payments under these leases. Minimum lease payments under these operating lease obligations of $37 million have been included above and an equal amount has been reported as sublease rentals.
	Of the $176 million present value of net minimum capital lease payments, $115 million was related to obligations assumed by United States Steel under the Financial Matters Agreement. Of the $517 million total minimum operating lease payments, $8 million was assumed by United States Steel under the Financial Matters Agreement.
	During 2005, Marathon renewed the lease for its corporate headquarters in Houston, Texas. Future minimum lease obligations associated with this operating lease are included in the table above.
	During 2003, Marathon purchased two LNG tankers which were previously leased. A $17 million charge was recorded on the termination of the operating leases. These tankers are used to transport LNG from Kenai, Alaska to Tokyo, Japan.

	Operating lease rental expense was:

(In millions)		2005				2004				2003
Minimum rental		$	165	(a)		$	168	(a)		$	182	(a)
Contingent rental			21				15				15
Sublease rentals			(14	)			(12	)			(9	)
Net rental expense		$	172			$	171			$	188

	(a)	Excludes $10 million, $11 million and $23 million paid by United States Steel in 2005, 2004 and 2003 on assumed leases.

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, respectively, 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 holds a 60 percent interest in EGHoldings, with GEPetrol holding a 25 percent interest and Mitsui and Marubeni holding 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 – net.

	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, 2005 and 2004, accrued liabilities for remediation totaled $103 million and $110 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 $68 million and $65 million at December 31, 2005 and 2004, respectively.

On May 11, 2001, MPC entered into a consent decree with the U.S. Environmental Protection Agency which commits it to complete certain agreed on environmental projects over an eight-year period primarily aimed at reducing air emissions at its seven refineries. The court approved this consent decree on August 28, 2001. The total one-time expenditures for these environmental projects are estimated to be approximately $420 million over the eight-year period, with about $265 million incurred through December 31, 2005. In addition, MPC has nearly completed certain agreed on supplemental environmental projects as part of this settlement of an enforcement action for alleged Clean Air Act violations, at a cost of $9 million. Marathon believes that this settlement will provide the Company with increased permitting and operating flexibility while achieving significant emission reductions.

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Guarantees – Marathon has issued the following guarantees:

					Maximum Potential
					Undiscounted Payments
					as of December 31,
(In millions)			Term		2005
Indebtedness of equity method investees:
	LOCAP(a)		Perpetual-Loan Balance Varies		$	23
	LOOP(a)		2006-2024			160
	Centennial(b)		2007-2024			75
Guarantees/indemnifications related to asset sales:
	Yates(c)		Indefinite			228
	Canada(d)		Indefinite			568
	Miscellaneous asset sales(e)		2006-Indefinite			68
Other:
	United States Steel(f)		2006-2012			651
	Centennial Pipeline catastrophic event(g)		Indefinite			50
	Alliance Pipeline(h)		2006-2015			69
	Kenai Kachemak Pipeline LLC(i)		2006-2017			15
	Corporate assets(j)		(j)			14
	Mobile transportation equipment leases(k)		2006-2010			6

(a)	Marathon holds interests in an offshore oil port, LOOP LLC (“LOOP”), and a crude oil pipeline system, LOCAP LLC (“LOCAP”). Both LOOP and LOCAP have secured various project financings with throughput and deficiency 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. Assuming non-payment by the investees, the maximum potential amount of future payments under the guarantees is estimated to be $183 million. Included in these amounts are a LOOP revolving credit facility of $25 million and a LOCAP revolving credit facility of $23 million. The undrawn portion of the revolving credit facilities is $34 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. If Centennial defaults on its outstanding balance, the estimated maximum potential amount of future payments is $75 million.
(c)	In 2003, Marathon sold its interest in the Yates field and gathering system to Kinder Morgan. In accordance with this transaction, Marathon indemnified Kinder Morgan from inaccuracies in Marathon’s representations, warranties, covenants and agreement. There is not a specified term on these guarantees and the maximum potential amount of future cash payments is estimated at $228 million.
(d)	In conjunction with the sale of certain Canadian assets to Husky Oil Operations Limited (“Husky”) during 2003, Marathon guaranteed Husky with regards to unknown environmental obligations and inaccuracies in representations, warranties, covenants and agreements by Marathon. These indemnifications are part of the normal course of doing business and selling assets. Per the Purchase and Sale Agreement, the maximum potential amount of future payments associated with these guarantees is $568 million.
(e)	Marathon entered into certain performance and general guarantees and environmental and general indemnifications in connection with certain asset sales. The terms vary from 2005 to indefinite and the maximum potential amount of future payments under the guarantees and indemnifications is estimated to be $68 million.
(f)	United States Steel is the sole general partner of Clairton 1314B Partnership, L.P., which owns certain cokemaking facilities formerly owned by United States Steel. Marathon has guaranteed to the limited partners all obligations of United States Steel under the partnership documents. In addition to the commitment to fund operating cash shortfalls of the partnership discussed in Note 3, United States Steel, under certain circumstances, is required to indemnify the limited partners if the partnership product sales fail to qualify for the credit under Section 29 of the Internal Revenue Code. United States Steel has estimated the maximum potential amount of this indemnity obligation, including interest and tax gross-up, was approximately $650 million. Furthermore, United States Steel under certain circumstances has indemnified the partnership for environmental obligations. The maximum potential amount of this indemnity obligation is not estimable.
(g)	The agreement between Centennial and its members allows each member to contribute cash in lieu of Centennial procuring separate insurance in the event of third-party liability arising from a catastrophic event. There is an indefinite term for the agreement and each member is to contribute cash in proportion to its ownership interest, up to a maximum amount of $50 million.
(h)	Marathon is a party to a long-term transportation services agreement with Alliance Pipeline L.P. (“Alliance”). The agreement requires Marathon to pay minimum annual charges of approximately $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. This agreement runs through 2015 and has a maximum potential payout of $69 million. As a result of the Canadian sale discussed above, Husky has indemnified Marathon for any claims related to these guarantees.
(i)	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 but the maximum potential payment is estimated at $15 million.
(j)	Marathon has entered into leases of corporate assets containing general lease indemnities and guaranteed residual value clauses. There is not a specified term and the maximum potential future payment is estimated to be $14 million.
(k)	These leases contain terminal rental adjustment clauses which provide that Marathon will indemnify the lessor to the extent that the proceeds from the sale of the asset at the end of the lease fall short of the specified minimum percentage of the fair market value of the asset at the time of sale.

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	Contract commitments – At December 31, 2005 and 2004, Marathon’s contract commitments to acquire property, plant and equipment totaled $668 million and $1.094 billion, respectively. The $426 million decrease is primarily due to the continued progress of the construction of the Equatorial Guinea LNG plant.
	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.

On January 29, 2006, Marathon’s Board of Directors authorized the repurchase of up to $2 billion of common stock over a period of two years. Such purchases will be made during this period as Marathon’s financial condition and market conditions warrant. Any purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. The repurchase program does not include specific price targets or timetables, and is subject to termination prior to completion. Marathon will use cash on hand, cash generated from operations, or cash from available borrowings to acquire shares. Shares of common stock repurchased under the program will be held as treasury shares.

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 FASB’s interim 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. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Marathon is currently studying the provisions of this Statement to determine the impact on its consolidated financial statements.

	In September 2005, the FASB ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The issue defines when a purchase and a sale of inventory with the same party that operates in the same line of business is recorded at fair value or considered a single nonmonetary transaction subject to the fair value exception of APB Opinion No. 29. 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. In general, two or more transactions with the same party are treated as one if they are entered into in contemplation of each other. The rules apply to new arrangements entered into in reporting periods beginning after March 15, 2006. The accounting for certain of the transactions that Marathon considers as matching buy/sell transactions will be affected by this consensus and therefore, upon adoption, these transactions will no longer be recorded on a gross basis. Marathon is currently studying the provisions of this consensus to determine the impact on its consolidated financial statements; however, management does not believe any impact on net income would be material. There will be no impact on cash flows from operations as a result of adoption.
	In May 2005, the FASB issued 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. SFAS No. 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005.
	In December 2004, the FASB issued SFAS No. 123 (Revised 2004), “Share-Based Payment,” (“SFAS No. 123(R)”) 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 will be recognized over the period during which an employee is required to provide service in exchange for the award, usually the vesting period. In addition, awards classified as liabilities will be remeasured each reporting period. Marathon adopted the fair value method under SFAS No. 123 for grants made, modified or settled on or after January 1, 2003. Accordingly, Marathon does not expect the adoption of SFAS No. 123(R) to have a material effect on its consolidated results of operations, financial position or

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	cash flows. The statement provided for an effective date of July 1, 2005, for Marathon. However, in April 2005, the Securities and Exchange Commission adopted a rule that, for Marathon, deferred the effective date until January 1, 2006. Marathon adopted the provisions of this statement on January 1, 2006.
	In November 2004, the FASB issued 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. Marathon is required to implement this statement in the first quarter of 2006. Marathon does not expect the adoption of SFAS No. 151 to have a material effect on its consolidated results of operations, financial position or cash flows.

			2005																2004
(In millions, except per share data)			4th Qtr.				3rd Qtr.				2nd Qtr.				1st Qtr.				4th Qtr.				3rd Qtr.				2nd Qtr.				1st Qtr.
Revenues			$	17,186			$	17,174			$	16,019			$	12,932			$	14,183			$	12,249			$	12,514			$	10,652
Income from operations				2,052				1,268				1,358				624				821				542				829				478
Income from continuing operations				1,284				770				673				324				429				222				348				258
Income from discontinued operations				–				–				–				–				–				–				4				–
Income before cumulative effect of changes in accounting principle				1,284				770				673				324				429				222				352				258
Net income				1,265				770				673				324				429				222				352				258
Common stock data
Net income per share:
	– Basic		$	3.46			$	2.11			$	1.94			$	0.94			$	1.24			$	0.64			$	1.02			$	0.83
	– Diluted		$	3.43			$	2.09			$	1.92			$	0.93			$	1.23			$	0.64			$	1.02			$	0.83
Dividends paid per share			$	0.33			$	0.33			$	0.28			$	0.28			$	0.28			$	0.25			$	0.25			$	0.25
Price range of common stock(a):
	– Low		$	56.28			$	54.69			$	44.00			$	35.73			$	36.67			$	33.98			$	32.22			$	30.78
	– High		$	69.21			$	70.83			$	55.58			$	48.76			$	42.13			$	41.52			$	37.84			$	36.06

(a)	Composite tape

December 31, 2005

Company

Country

Ownership

Activity

Alba Plant LLC

Cayman Islands

52%(a)

Liquified Petroleum Gas

Atlantic Methanol Production Company LLC

Cayman Islands

45%

Methanol Production

Centennial Pipeline LLC

United States

50%

Pipeline & Storage Facility

Kenai Kachemak Pipeline, LLC

United States

60%(a)

Natural Gas Transmission

Kenai LNG Corporation

United States

30%

Natural Gas Liquefaction

LOCAP LLC

United States

59%(a)

Pipeline & Storage Facilities

LOOP LLC

United States

51%(a)

Offshore Oil Port

Minnesota Pipe Line Company

United States

33%

Pipeline Facility

Muskegon Pipeline LLC

United States

60%(a)

Pipeline Facility

Odyssey Pipeline L.L.C.

United States

29%

Pipeline Facility

Pilot Travel Centers LLC

United States

50%

Travel Centers

Poseidon Oil Pipeline Company, L.L.C.

United States

28%

Crude Oil Transportation

Southcap Pipe Line Company

United States

22%

Crude Oil Transportation

(a)	Represents a noncontrolling interest.

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					United												Other
(In millions)			December 31		States				Europe				Africa				Int’l				Total
2005 Capitalized costs:
		Proved properties			$	7,015			$	6,349			$	1,897			$	342			$	15,603
		Unproved properties				428				107				573				193				1,301
		Suspended exploratory wells				111				31				204				17				363
			Total			7,554				6,487				2,674				552				17,267
	Accumulated depreciation, depletion and amortization:
		Proved properties				4,752				4,476				288				111				9,627
		Unproved properties				27				–				9				32				68
			Total			4,779				4,476				297				143				9,695
	Net capitalized costs				$	2,775			$	2,011			$	2,377			$	409			$	7,572
	Share of equity method investees’ capitalized costs				$	13			$	–			$	395			$	–			$	408
2004 Capitalized costs:
		Proved properties			$	6,508			$	5,689			$	1,376			$	231			$	13,804
		Unproved properties				454				115				181				215				965
		Suspended exploratory wells				115				15				174				35				339
			Total			7,077				5,819				1,731				481				15,108
	Accumulated depreciation, depletion and amortization:
		Proved properties				4,432				4,209				201				55				8,897
		Unproved properties				22				–				9				33				64
			Total			4,454				4,209				210				88				8,961
	Net capitalized costs				$	2,623			$	1,610			$	1,521			$	393			$	6,147
	Share of equity method investees’ capitalized costs				$	14			$	–			$	377			$	–			$	391

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

					United												Other				Continuing				Discontinued
(In millions)					States				Europe				Africa				Int’l				Operations				Operations				Total
2005 Property acquisition:
		Proved			$	3			$	–			$	390			$	–			$	393			$	–			$	393
		Unproved				31				–				381				–				412				–				412
	Exploration					186				48				95				24				353				–				353
	Development					465				531				32				85				1,113				–				1,113
	Capitalized asset retirement costs(b)					35				108				12				3				158				–				158
			Total			720				687				910				112				2,429				–				2,429
	Share of investees’ costs incurred					–				–				31				–				31				–				31
2004 Property acquisition:
		Proved			$	9			$	–			$	3			$	–			$	12			$	–			$	12
		Unproved				10				–				1				–				11				–				11
	Exploration					96				27				127				41				291				–				291
	Development					316				151				140				102				709				–				709
	Capitalized asset retirement costs(b)					14				49				5				(5	)			63				–				63
			Total			445				227				276				138				1,086				–				1,086
	Share of investees’ costs incurred					1				–				128				1				130				–				130
2003 Property acquisition:
		Proved			$	1			$	1			$	–			$	66			$	68			$	–			$	68
		Unproved				5				3				1				244				253				–				253
	Exploration					114				35				53				29				231				17				248
	Development					266				148				352				33				799				26				825
	Capitalized asset retirement costs(b)(c)					9				47				3				14				73				–				73
			Total			395				234				409				386				1,424				43				1,467
	Share of investees’ costs incurred					29				4				80				12				125				–				125

(a)	Includes costs incurred whether capitalized or expensed.
(b)	Includes the effect of foreign currency fluctuations.
(c)	Excludes $161 million cumulative effect of adopting SFAS No. 143.

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				United												Other
(In millions)				States				Europe				Africa				Int’l				Total
2005		Revenues and other income:
		Sales(a)		$	2,227			$	1,136			$	71			$	165			$	3,599
		Transfers			422				38				810				161				1,431
		Other income(b)			22				–				–				–				22
		Total revenues			2,671				1,174				881				326				5,052
		Expenses:
		Production costs			(448	)			(170	)			(82	)			(197	)			(897	)
		Transportation costs(c)			(114	)			(40	)			(27	)			(13	)			(194	)
		Exploration expenses			(118	)			(31	)			(27	)			(43	)			(219	)
		Depreciation, depletion and amortization(d)			(411	)			(255	)			(87	)			(56	)			(809	)
		Administrative expenses			(34	)			(8	)			(5	)			(25	)			(72	)
		Total expenses			(1,125	)			(504	)			(228	)			(334	)			(2,191	)
		Other production-related income(f)			2				44				–				–				46
		Results before income taxes			1,548				714				653				(8	)			2,907
		Income taxes(g)			555				249				193				3				1,000
		Results of continuing operations		$	993			$	465			$	460			$	(11	)		$	1,907
		Share of equity method investees’ results of operations		$	–			$	–			$	50			$	–			$	50
2004		Revenues and other income:
		Sales(a)		$	1,631			$	876			$	260			$	56			$	2,823
		Transfers			392				28				159				75				654
		Total revenues			2,023				904				419				131				3,477
		Expenses:
		Production costs			(381	)			(166	)			(55	)			(96	)			(698	)
		Transportation costs(c)			(112	)			(35	)			(6	)			(7	)			(160	)
		Exploration expenses			(79	)			(19	)			(28	)			(44	)			(170	)
		Depreciation, depletion and amortization(d)			(356	)			(275	)			(56	)			(26	)			(713	)
		Impairments(e)			–				–				–				(44	)			(44	)
		Administrative expenses			(39	)			(4	)			(15	)			(24	)			(82	)
		Total expenses			(967	)			(499	)			(160	)			(241	)			(1,867	)
		Other production-related income(f)			–				15				–				–				15
		Results before income taxes			1,056				420				259				(110	)			1,625
		Income taxes (credits)(g)			378				156				97				(28	)			603
		Results of continuing operations		$	678			$	264			$	162			$	(82	)		$	1,022
		Share of equity method investees’ results of operations		$	1			$	–			$	9			$	1			$	11
2003		Revenues and other income:
		Sales(a)		$	1,777			$	728			$	139			$	43			$	2,687
		Transfers			424				20				127				24				595
		Other income (loss)(b)			(88	)			65				(1	)			–				(24	)
		Total revenues			2,113				813				265				67				3,258
		Expenses:
		Production costs			(410	)			(136	)			(55	)			(53	)			(654	)
		Transportation costs(c)			(120	)			(32	)			(5	)			(3	)			(160	)
		Exploration expenses			(118	)			(18	)			(15	)			(28	)			(179	)
		Depreciation, depletion and amortization(d)(h)			(407	)			(227	)			(42	)			(11	)			(687	)
		Impairments(e)			(3	)			–				–				–				(3	)
		Administrative expenses			(43	)			(17	)			(4	)			(36	)			(100	)
		Total expenses			(1,101	)			(430	)			(121	)			(131	)			(1,783	)
		Other production-related income(f)			1				26				–				–				27
		Results before income taxes			1,013				409				144				(64	)			1,502
		Income taxes (credits)(g)			352				146				4				(27	)			475
		Results of continuing operations		$	661			$	263			$	140			$	(37	)		$	1,027
		Results of discontinued operations		$	–			$	–			$	–			$	41			$	41
		Share of equity method investees’ results of operations		$	8			$	4			$	6			$	–			$	18

(a)	Excludes noncash effects of changes in the fair value of certain long-term gas sales contracts in the United Kingdom.
(b)	Includes net gains (losses) on asset dispositions.
(c)	Includes the cost to prepare and move liquid hydrocarbons and natural gas to their points of sale.
(d)	Includes accretion of interest on asset retirement obligations.
(e)	Includes impairment of unproved and producing oil and gas properties.
(f)	Includes revenues, net of associated costs, from third-party activities that are an integral part of Marathon’s production operations which may include the processing and/or transportation of third-party production, and the purchase and subsequent resale of gas utilized in reservoir management.
(g)	Computed by adjusting results before income taxes by nontaxable and nondeductible items and multiplying the result by the 35 percent statutory rate and adjusting for applicable tax credits.
(h)	Excludes the cumulative effect on net income of the adoption of SFAS No. 143.

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(In millions)			2005				2004				2003
Results before income taxes			$	2,907			$	1,625			$	1,502
Items not included in results of continuing oil and gas operations:
	Marketing income and technology costs			17				16				24
	Income from equity method investments			67				12				20
	Other			(3	)			(1	)			(5	)
Items not allocated to E&P segment income:
	Impairment of certain unproved and producing oil and gas properties			–				44				–
	Gain on asset disposition			–				–				(85	)
	Loss on joint venture dissolution			–				–				124
	E&P segment income		$	2,988			$	1,696			$	1,580

		United												Other
		States				Europe				Africa				Int’l				Total
2005		$	7.11			$	6.45			$	3.33			$	20.35			$	7.26
2004			5.58				5.39				3.35				16.76				5.75
2003			4.92				4.35				3.98				14.56				4.95

(a)	Computed using production costs, excluding transportation costs, as disclosed in the Results of Operations for Oil and Gas Activities and as defined by the Securities and Exchange Commission. Natural gas volumes were converted to barrels of oil equivalent using a conversion factor of six mcf of natural gas to one barrel of oil.

			United												Other				Continuing				Discontinued
			States				Europe				Africa				Int’l				Operations				Operations
(excluding derivative gains and losses)
2005 Liquid hydrocarbons (per bbl)			$	45.41			$	52.99			$	46.27			$	33.47			$	45.42			$	–
	Natural gas (per mcf)(a)			6.42				5.72				0.25				–				5.61				–
2004 Liquid hydrocarbons (per bbl)			$	32.76			$	37.16			$	35.11			$	22.65			$	33.31			$	–
Natural gas (per mcf) (a)				4.89				4.11				0.25				–				4.31				–
2003 Liquid hydrocarbons (per bbl)			$	26.92			$	28.50			$	26.29			$	18.33			$	26.72			$	28.96
Natural gas (per mcf) (a)				4.53				3.32				0.25				–				3.96				5.43
(including derivative gains and losses)
2005 Liquid hydrocarbons (per bbl)			$	45.41			$	52.99			$	46.27			$	33.47			$	45.42			$	–
Natural gas (per mcf) (a)				6.40				5.72				0.25				–				5.59				–
2004 Liquid hydrocarbons (per bbl)			$	29.11			$	33.65			$	35.11			$	22.62			$	30.73			$	–
Natural gas (per mcf) (a)				4.85				4.11				0.25				–				4.28				–
2003 Liquid hydrocarbons (per bbl)			$	26.09			$	27.27			$	26.29			$	18.33			$	25.96			$	28.96
Natural gas (per mcf) (a)				4.31				3.32				0.25				–				3.81				5.43

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

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			United												Other				Continuing				Discontinued
			States				Europe				Africa(a)				Int’l				Operations				Operations
Liquid Hydrocarbons (Millions of barrels)
Proved developed and undeveloped reserves:
	Beginning of year – 2003			245				76				203				3				527				10
	Purchase of reserves in place(b)			–				–				–				64				64				–
	Exchange of reserves in place(c)			173				–				–				–				173				–
	Revisions of previous estimates			–				(4	)			25				11				32				–
	Improved recovery			4				–				–				4				8				–
	Extensions, discoveries and other additions			10				2				–				14				26				–
	Production			(39	)			(15	)			(10	)			(4	)			(68	)			(1	)
	Sales of reserves in place(b)			(183	)			–				–				(3	)			(186	)			(9	)
	End of year – 2003			210				59				218				89				576				–
	Purchase of reserves in place(b)			1				–				2				–				3				–
	Revisions of previous estimates			(1	)			3				14				(51	)			(35	)			–
	Improved recovery			1				–				–				–				1				–
	Extensions, discoveries and other additions			9				60				1				7				77				–
	Production			(29	)			(15	)			(12	)			(6	)			(62	)			–
	Sales of reserves in place(b)			–				–				–				–				–				–
	End of year – 2004			191				107				223				39				560				–
	Purchase of reserves in place(b)			–				–				3				–				3				–
	Re-entry to Libya concessions			–				–				165				–				165				–
	Revisions of previous estimates			10				4				1				3				18				–
	Improved recovery			2				–				–				–				2				–
	Extensions, discoveries and other additions			15				–				–				12				27				–
	Production			(28	)			(13	)			(19	)			(10	)			(70	)			–
	Sales of reserves in place(b)			(1	)			–				–				–				(1	)			–
	End of year – 2005			189				98				373				44				704				–
Proved developed reserves:
	Beginning of year – 2003			226				63				113				2				404				9
	End of year – 2003			193				47				120				31				391				–
	End of year – 2004			171				41				147				27				386				–
	End of year – 2005			165				39				368				31				603				–

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			United												Other				Continuing				Discontinued
			States				Europe				Africa(a)				Int’l				Operations				Operations
Share of equity method investees’ proved developed and undeveloped reserves:
	Beginning of year – 2003			183				–				–				–				183				–
	End of year – 2003			–				–				–				2				2				–
Proved developed reserves:																								–
	Beginning of year – 2003			177				–				–				–				177				–
	End of year – 2003			–				–				–				2				2				–
Natural Gas (Billions of cubic feet)
Proved developed and undeveloped reserves:
	Beginning of year – 2003			1,724				562				653				–				2,939				379
	Purchase of reserves in place(b)			7				–				–				–				7				–
	Revisions of previous estimates			20				(7	)			36				–				49				–
	Extensions, discoveries and other additions			161				24				–				–				185				8
	Production(d)			(267	)			(95	)			(24	)			–				(386	)			(27	)
	Sales of reserves in place(b)			(10	)			–				–				–				(10	)			(360	)
	End of year – 2003			1,635				484				665				–				2,784				–
	Purchase of reserves in place(b)			1				–				–				–				1				–
	Revisions of previous estimates			(230	)			7				916				–				693				–
	Extensions, discoveries and other additions			189				150				11				–				350				–
	Production(d)			(231	)			(97	)			(28	)			–				(356	)			–
	Sales of reserves in place(b)			–				–				–				–				–				–
	End of year – 2004			1,364				544				1,564				–				3,472				–
	Purchase of reserves in place(b)			–				–				24				–				24				–
	Revisions of previous estimates			(78	)			18				298				–				238				–
	Extensions, discoveries and other additions			135				3				–				–				138				–
	Production(d)			(211	)			(79	)			(34	)			–				(324	)			–
	Sales of reserves in place(b)			(1	)			–				–				–				(1	)			–
	End of year – 2005			1,209				486				1,852				–				3,547				–
Proved developed reserves:
	Beginning of year – 2003			1,206				408				552				–				2,166				290
	End of year – 2003			1,067				421				528				–				2,016				–
	End of year – 2004			992				376				570				–				1,938				–
	End of year – 2005			943				326				638				–				1,907				–
Share of equity method investees’ proved developed and undeveloped reserves:
	Beginning of year – 2003			–				59				–				–				59				–
Proved developed reserves:
	Beginning of year – 2003			–				36				–				–				36				–

(a)	Consists of estimated reserves from properties governed by production sharing contracts.
(b)	The net positive or negative balance of proved reserves acquired or relinquished in property trades within the same geographic area is reported as purchases of reserves in place or sales of reserves in place, respectively.
(c)	Reserves represent the transfer of certain mineral interests on the dissolution of MKM Partners, L.P.
(d)	Excludes the resale of purchased gas utilized in reservoir management.

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			United												Other
(In millions)		December 31	States				Europe				Africa				Int’l				Total
2005
	Future cash inflows		$	17,346			$	10,007			$	18,088			$	1,415			$	46,856
	Future production, transportation and administrative costs			(5,046	)			(2,007	)			(1,910	)			(1,010	)			(9,973	)
	Future development costs			(853	)			(1,531	)			(751	)			(61	)			(3,196	)
	Future income tax expenses			(3,738	)			(3,199	)			(9,687	)			(55	)			(16,679	)
	Future net cash flows		$	7,709			$	3,270			$	5,740			$	289			$	17,008
	10 percent annual discount for estimated timing of cash flows			(2,862	)			(829	)			(2,427	)			(73	)			(6,191	)
	Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$	4,847			$	2,441			$	3,313			$	216			$	10,817
2004
	Future cash inflows		$	12,377			$	7,742			$	5,709			$	750			$	26,578
	Future production, transportation and administrative costs			(4,337	)			(1,950	)			(951	)			(565	)			(7,803	)
	Future development costs			(585	)			(1,801	)			(294	)			(82	)			(2,762	)
	Future income tax expenses			(2,581	)			(1,753	)			(1,265	)			(16	)			(5,615	)
	Future net cash flows		$	4,874			$	2,238			$	3,199			$	87			$	10,398
	10 percent annual discount for estimated timing of cash flows			(1,740	)			(737	)			(1,419	)			(33	)			(3,929	)
	Standardized measure of discounted future net cash flows relating to proved oil and gas reserves		$	3,134			$	1,501			$	1,780			$	54			$	6,469
2003
	Future cash inflows		$	13,331			$	3,955			$	4,471			$	1,593			$	23,350
	Future production, transportation and administrative costs			(4,919	)			(1,050	)			(1,161	)			(827	)			(7,957	)
	Future development costs			(758	)			(435	)			(175	)			(229	)			(1,597	)
	Future income tax expenses			(2,612	)			(870	)			(780	)			(163	)			(4,425	)
	Future net cash flows			5,042				1,600				2,355				374				9,371
	10 percent annual discount for estimated timing of cash flows			(1,789	)			(301	)			(1,112	)			(168	)			(3,370	)
	Standardized measure of discounted future net cash flows relating to proved oil and gas reserves(a)		$	3,253			$	1,299			$	1,243			$	206			$	6,001
	Share of equity method investee’s standardized measure of discounted future net cash flow		$	–			$	–			$	–			$	8			$	8

(a)	Excludes $(26) million of discounted future net cash flows from the effects of hedging transactions for 2003.

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(In millions)		2005				2004				2003
Sales and transfers of oil and gas produced, net of production, transportation, and administrative costs		$	(3,868	)		$	(2,715	)		$	(2,487	)
Net changes in prices and production, transportation and administrative costs related to future production			6,783				950				1,178
Extensions, discoveries and improved recovery, less related costs			790				1,352				618
Development costs incurred during the period			1,115				711				802
Changes in estimated future development costs			(600	)			(556	)			(478	)
Revisions of previous quantity estimates			837				494				348
Net changes in purchases and sales of minerals in place			4,556				33				(531	)
Net change in exchanges of minerals in place			–				–				403
Accretion of discount			1,130				790				807
Net change in income taxes			(6,723	)			(529	)			65
Timing and other			328				(62	)			(165	)
Net change for the year			4,348				468				560
Beginning of year			6,469				6,001				5,441
End of year		$	10,817			$	6,469			$	6,001
Net change for the year from discontinued operations		$	–			$	–			$	(384	)

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							2005				2004				2003				2002				2001
Net Liquid Hydrocarbon Sales (thousands of barrels per day)(a)
	United States (by business unit)
		Northern						25				25				26				28				29
		Southern						51				56				81				89				98
			Total United States					76				81				107				117				127
	International
		Australia						–				–				1				1				–
		Equatorial Guinea						40				19				12				8				–
		Gabon						12				13				15				17				16
		Norway						2				2				1				1				–
		United Kingdom						34				38				40				51				46
		Russian Federation						27				16				9				–				–
			Total International					115				88				78				78				62
				Consolidated				191				169				185				195				189
	Equity method investee							–				1				6				8				9
					Total Continuing Operations			191				170				191				203				198
					Discontinued Operations			–				–				3				4				11
					Worldwide Total			191				170				194				207				209
Natural gas liquids included in above								18				15				18				20				19
Net Natural Gas Sales (millions of cubic feet per day)(a)
	United States (by business unit)
		Northern						351				367				392				405				397
		Southern						227				264				340				340				396
			Total United States					578				631				732				745				793
	International
		Equatorial Guinea						92				76				66				53				–
		Ireland						50				58				62				81				79
		Norway						34				27				16				15				5
		United Kingdom – equity						140				188				184				203				234
– other (b)								38				19				23				4				8
			Total International					354				368				351				356				326
				Consolidated				932				999				1,083				1,101				1,119
	Equity method investee							–				–				13				25				31
					Total Continuing Operations			932				999				1,096				1,126				1,150
					Discontinued Operations			–				–				74				104				123
					Worldwide Total			932				999				1,170				1,230				1,273
Average Sales Prices (excluding derivative gains and losses)
	Liquid Hydrocarbons (dollars per barrel)
		United States					$	45.41			$	32.76			$	26.92			$	22.18			$	20.62
		International						45.43				33.82				26.45				23.86				23.74
			Consolidated					45.42				33.31				26.72				22.86				21.65
		Equity method investee						–				21.10				25.91				24.59				23.41
					Total Continuing Operations			45.42				33.24				26.70				22.93				21.73
					Discontinued Operations			–				–				28.96				23.29				21.26
					Worldwide			45.42				33.24				26.73				22.94				21.71
	Natural Gas (dollars per thousand cubic feet)
		United States					$	6.42			$	4.89			$	4.53			$	2.87			$	3.69
		International						4.28				3.33				2.77				2.30				2.78
			Consolidated					5.61				4.31				3.96				2.69				3.42
		Equity method investee						–				–				3.70				3.05				3.39
					Total Continuing Operations			5.61				4.31				3.95				2.70				3.42
					Discontinued Operations			–				–				5.43				3.30				4.17
					Worldwide			5.61				4.31				4.05				2.75				3.49
Net Proved Reserves at year-end (developed and undeveloped)
	Liquid Hydrocarbons (millions of barrels)
		United States						189				191				210				245				268
		International						515				369				366				292				118
			Consolidated					704				560				576				537				386
		Equity method investee						–				–				2				183				184
					Total			704				560				578				720				570
	Developed reserves as a percentage of total net reserves							86	%			69	%			68	%			82	%			90	%
	Natural Gas (billions of cubic feet)
		United States						1,209				1,364				1,635				1,724				1,793
		International						2,338				2,108				1,149				1,594				1,014
			Consolidated					3,547				3,472				2,784				3,318				2,807
		Equity method investee						–				–				–				59				51
					Total			3,547				3,472				2,784				3,377				2,858
	Developed reserves as a percentage of total net reserves							54	%			56	%			72	%			74	%			74	%

(a)	Amounts represent net sales after royalties, except for the U.K., Ireland and the Netherlands where amounts are shown before royalties for the applicable periods.
(b)	Represents gas acquired for injection and subsequent resale. Effective July 1, 2005, the methodology for allocating sales volumes between gas produced from the Brae complex and third-party gas production was modified, resulting in an increase in volumes representing gas acquired for injection and subsequent resale.

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						2005(a)				2004(a)				2003(a)				2002(a)				2001(a)
Refinery Operations (thousands of barrels per day)
	In-use crude oil capacity at year-end						974				948				935				935				935
	Refinery runs			– crude oil refined			973				939				917				906				929
				– other charge and blend stocks			205				171				138				148				143
	In-use crude oil capacity utilization rate						102	%			99	%			98	%			97	%			99	%
Source of Crude Processed (thousands of barrels per day)
	United States						447				416				422				433				403
	Canada						111				130				122				114				115
	Middle East and Africa						301				276				266				232				347
	Other International						114				117				107				127				64
		Total					973				939				917				906				929
Refined Product Yields (thousands of barrels per day)
	Gasoline						644				608				567				581				581
	Distillates						318				299				284				285				286
	Propane						21				22				21				21				22
	Feedstocks and special products						96				94				93				80				69
	Heavy fuel oil						28				25				24				20				39
	Asphalt						85				77				72				72				76
		Total					1,192				1,125				1,061				1,059				1,073
Refined Product Sales Volumes (thousands of barrels per day)(b)
	Gasoline						836				807				776				773				748
	Distillates						385				373				365				346				345
	Propane						22				22				21				22				21
	Feedstocks and special products						96				92				97				82				71
	Heavy fuel oil						29				27				24				20				41
	Asphalt						87				79				74				75				78
		Total					1,455				1,400				1,357				1,318				1,304
	Matching buy/sell volumes included in above						77				71				64				71				45
Refined Products Sales Volumes by Class of Trade (as a % of total)
	Wholesale & spot market – independent private-brand marketers and consumers						72	%			72	%			71	%			69	%			66	%
	Marathon brand jobbers and dealers						13	%			13	%			13	%			13	%			13	%
	Speedway SuperAmerica retail outlets						15	%			15	%			16	%			18	%			21	%
		Total					100	%			100	%			100	%			100	%			100	%
Refined Products (dollars per barrel)
	Average sales price					$	66.42			$	49.53			$	38.55			$	32.26			$	34.54
	Average cost of crude oil throughput					$	51.85			$	39.16			$	29.77			$	25.41			$	23.47
Refining and Wholesale Marketing Margin (dollars per gallon)(c)						$	0.1582			$	0.0877			$	0.0603			$	0.0387			$	0.1167
Refined Product Marketing Outlets at year-end
	MPC operated terminals						85				84				88				86				87
	Retail		– Marathon brand				4,003				3,912				3,885				3,822				3,800
			– Speedway SuperAmerica				1,638				1,669				1,775				2,006				2,104
Speedway SuperAmerica
	Gasoline & distillates sales (millions of gallons)						3,226				3,152				3,332				3,604				3,572
	Gasoline & distillates gross margin (dollars per gallon)					$	0.1230			$	0.1186			$	0.1229			$	0.1007			$	0.1206
	Merchandise sales (millions)					$	2,531			$	2,335			$	2,244			$	2,380			$	2,253
	Merchandise gross margin (millions)					$	626			$	571			$	555			$	576			$	527
Petroleum Inventories at year-end (thousands of barrels)
	Crude oil, raw materials and natural gas liquids						32,343				31,577				31,862				32,600				32,741
	Refined products						39,925				38,653				37,650				37,729				36,310
Pipelines (miles of common carrier pipelines)(d)
	Crude Oil			– gathering lines			68				68				68				200				271
				– trunklines			3,806				3,893				4,105				4,459				4,511
	Products			– trunklines			3,824				3,850				3,861				3,732				2,847
		Total					7,698				7,811				8,034				8,391				7,629
Pipeline Barrels Handled (in millions)(e)
	Crude Oil			– gathering lines			6.6				6.8				12.7				14.1				16.3
				– trunklines			597.8				577.9				583.3				575.7				570.6
	Products			– trunklines			444.7				406.8				371.3				367.6				345.6
		Total					1,049.1				991.5				967.3				957.4				932.5
River Operations
	Barges		– owned/leased				173				167				155				150				156
	Boats		– owned/leased				10				9				7				7				8

(a)	Statistics include 100 percent of MPC.
(b)	Total average daily volumes of refined product sales to wholesale, branded and retail (SSA) customers.
(c)	Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation.
(d)	Pipelines for downstream operations also include non-common carrier, leased and equity method investees.
(e)	Pipeline barrels handled on owned common carrier pipelines, excluding equity method investees.

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(Dollars in millions, except as noted)					2005				2004				2003				2002				2001
Revenues and Other Income
	Revenues by product:
		Refined products			$	40,040			$	29,780			$	24,092			$	19,729			$	20,841
		Merchandise				2,689				2,489				2,395				2,521				2,506
		Liquid hydrocarbons				16,677				13,860				10,500				6,517				6,502
		Natural gas				3,675				3,266				3,796				2,362				2,801
		Transportation and other products				230				203				180				166				146
			Total revenues			63,311				49,598				40,963				31,295				32,796
	Gain (loss) on ownership change in MPC					–				2				(1	)			12				(6	)
	Other(a)					362				307				272				248				272
			Total revenues and other income		$	63,673			$	49,907			$	41,234			$	31,555			$	33,062
Income From Operations
	Exploration and production
		Domestic			$	1,564			$	1,073			$	1,155			$	726			$	1,150
		International				1,424				623				425				333				229
			E&P segment income			2,988				1,696				1,580				1,059				1,379
	Refining, marketing and transportation					3,013				1,406				819				372				1,927
	Integrated gas					31				48				(3	)			23				21
			Segment income			6,032				3,150				2,396				1,454				3,327
	Items not allocated to segments:
		Administrative expenses				(367	)			(307	)			(227	)			(194	)			(187	)
		Gain on disposal of assets				–				–				106				24				–
		Inventory market valuation adjustments				–				–				–				71				(71	)
		Impairment of certain oil and gas properties				–				(44	)			–				–				–
		Loss on dissolution of MKM Partners LLP				–				–				(124	)			–				–
		Gain (loss) on U.K. long-term gas contracts				(386	)			(99	)			(66	)			18				–
		Other items				23				(30	)			(1	)			(3	)			39
			Income from operations			5,302				2,670				2,084				1,370				3,108
	Minority interest in income of MPC					384				532				302				173				704
	Minority interest in loss of EGHoldings					(8	)			(7	)			–				–				–
	Net interest and other financing costs					145				161				186				321				172
	Provision for income taxes					1,730				727				584				369				827
Income From Continuing Operations					$	3,051			$	1,257			$	1,012			$	507			$	1,405
	Per common share – basic (in dollars)				$	8.57			$	3.74			$	3.26			$	1.63			$	4.54
		– diluted (in dollars)			$	8.49			$	3.72			$	3.26			$	1.63			$	4.54
Net Income					$	3,032			$	1,261			$	1,321			$	516			$	377
	Per common share – basic (in dollars)				$	8.52			$	3.75			$	4.26			$	1.66			$	1.22
		– diluted (in dollars)			$	8.44			$	3.73			$	4.26			$	1.66			$	1.22
Balance Sheet Position at year-end
	Current assets				$	9,383			$	8,866			$	6,040			$	4,479			$	4,411
	Net property, plant and equipment					15,011				11,810				10,830				10,390				9,552
	Total assets					28,498				23,423				19,482				17,812				16,129
	Short-term debt					315				16				272				161				215
	Other current liabilities					7,839				5,237				3,935				3,498				3,253
	Long-term debt					3,698				4,057				4,085				4,410				3,432
	Minority interest in subsidiaries					435				2,690				2,011				1,971				1,963
	Common stockholders’ equity					11,705				8,111				6,075				5,082				4,940
Cash Flow Data – Continuing Operations
	Net cash from operating activities				$	4,738			$	3,766			$	2,682			$	2,331			$	2,749
	Capital expenditures					2,890				2,247				1,909				1,520				1,533
	Disposal of assets					131				76				644				146				83
	Dividends paid					436				348				298				285				284
	Dividends paid per share					1.22				1.03				0.96				0.92				0.92
Employee Data
	Marathon:
		Total employment costs			$	1,746			$	1,672			$	1,560			$	1,481			$	1,498
		Average number of employees				26,916				26,580				27,677				28,237				30,791
		Number of pensioners at year-end				3,029				3,117				3,291				3,122				3,105
	Speedway SuperAmerica LLC (included in Marathon totals):
		Total employment costs			$	453			$	446			$	464			$	480			$	496
		Average number of employees				17,514				17,077				17,911				18,943				21,449
		Number of pensioners at year-end				223				245				234				214				205
Stockholder Data at year-end
	Number of common shares outstanding (in millions)					366.7				346.7				310.4				309.9				309.4
	Registered shareholders (in thousands)					69.2				58.6				61.9				66.4				69.7
	Market price of common stock				$	60.97			$	37.61			$	33.09			$	21.29			$	30.00

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

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

Item 9A.	Controls and Procedures

Item 9B.	Other Information

Item 10.	Directors and Executive Officers of the Registrant

Albert G. Adkins		58		Vice President, Accounting
Philip G. Behrman		55		Senior Vice President, Worldwide Exploration
Clarence P. Cazalot, Jr.		55		President and Chief Executive Officer, and Director
Janet F. Clark		51		Senior Vice President and Chief Financial Officer
Gary R. Heminger		52		Executive Vice President
Steven B. Hinchman		47		Senior Vice President, Worldwide Production
Jerry Howard		57		Senior Vice President, Corporate Affairs
Alard Kaplan		55		Vice President, Major Projects
Kenneth L. Matheny		58		Vice President, Investor Relations and Public Affairs
Paul C. Reinbolt		50		Vice President, Finance and Treasurer
William F. Schwind, Jr.		61		Vice President, General Counsel and Secretary

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Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

	•	2003 Incentive Compensation Plan
	•	1990 Stock Plan – No additional awards will be granted under this plan.
	•	Deferred Compensation Plan for Non-Employee Directors – No additional awards will be granted under this plan.
	•	2001 Non-Officer Restricted Stock Plan – No additional awards will be granted under this plan.

(a)

(b)

(c)

Number of securities remaining

Number of securities to

Weighted-average

available for future issuance

be issued upon exercise

exercise price of

under equity compensation

of outstanding options,

outstanding options,

plans (excluding securities

Plan category

warrants and rights

warrants and rights

reflected in column (a))

Equity compensation plans approved by stockholders

6,590,421(a

)

$

36.50

12,871,252

(b)

Equity compensation plans not approved by stockholders(c)

89,363(d

)

N/A

–

Total

6,679,784(a

)

$

36.50

12,871,252

(b)

(a)	This number includes the following:

	•	4,851,892 stock options and stock appreciation rights outstanding under the 2003 Incentive Compensation Plan (the “Incentive Plan”).
	•	1,107,762 stock options outstanding under the 1990 Stock Plan.
	•	448,600 performance shares granted to officers under the Incentive Plan but not yet earned as of December 31, 2005. The number of shares, if any, to be issued will be determined based on a formula that measures Marathon’s total shareholder return over the applicable performance period relative to the total shareholder return of its industry peers.
	•	48,249 phantom shares that have been credited to non-employee directors pursuant to the non-employee director deferred compensation program and the annual director stock award program established under the Incentive Plan. When a non-employee director leaves the Board, he or she will be issued actual shares of Marathon common stock in place of the phantom shares.
	•	133,918 restricted stock phantom units granted to non-officers under the Incentive Plan and outstanding as of December 31, 2005.

	The weighted-average exercise price shown in column (b) does not take the officer performance shares, the phantom shares or the restricted stock units into account since these awards have no exercise price.
(b)	This number reflects the shares available for issuance under the Incentive Plan. No more than 6,690,250 of these shares may be issued for awards other than stock options or stock appreciation rights. In addition, shares subject to awards that are forfeited, terminated, expire unexercised, or are settled in such manner that all or some of the shares are not issued to a participant shall immediately become available for future grants.

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(c)	This reflects awards made under the Deferred Compensation Plan for Non-Employee Directors and the 2001 Non-Officer Restricted Stock Plan prior to April 30, 2003.
(d)	This number includes the following:

	•	57,243 phantom shares that were awarded to non-employee directors under the Deferred Compensation Plan for Non-Employee Directors prior to April 30, 2003. When a non-employee director leaves the Board, he or she will be issued actual shares of Marathon common stock in place of the phantom shares.
	•	32,120 restricted stock phantom units granted under the 2001 Non-Officer Restricted Stock Plan and outstanding as of December 31, 2005.

	Equity Compensation Plans Not Approved by Stockholders

Item 13.	Certain Relationships and Related Transactions

Item 14.	Principal Accounting Fees and Services

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Item 15.	Exhibits and Financial Statement Schedules

	1.	Financial Statements (see Part II, Item 8. of this report regarding financial statements)
	2.	Financial Statement Schedules

	Financial Statement Schedules listed under SEC rules but not included in this report are omitted because they are not applicable or the required information is contained in the financial statements or notes thereto.
	Schedule II – Valuation and Qualifying Accounts is provided on page 66.

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 (incorporated by reference to Exhibit 2.1 to USX Corporation’s Form 8-K filed on July 2, 2001).
	2.2			Agreement and Plan of Reorganization, dated as of July 31, 2001, by and between USX Corporation and United States Steel LLC (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-4 (File No. 333-69090) of USX Corporation filed on September 7, 2001).
	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).
	2.7††			Amendment No. 2, dated as of March 18, 2004, and Amendment No. 3 dated as of April 27, 2005, to the Amended and Restated Limited Liability Company Agreement of Marathon Ashland Petroleum LLC (incorporated by reference to Exhibit 2.6 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).
	3.			Articles of Incorporation and Bylaws
	3.1			Restated Certificate of Incorporation of Marathon Oil Corporation (incorporated by reference to Exhibit 3(a) to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001).
	3.2			By-laws of Marathon Oil Corporation (incorporated by reference to Exhibit 3(b) to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002).
	4.			Instruments Defining the Rights of Security Holders, Including Indentures
	4.1			Five Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, ABN Ambro Bank N.V., Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended June 30, 2004).
	4.2			Five Year Credit Agreement dated as of May 20, 2004 among Marathon Ashland Petroleum LLC, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, ABN Ambro Bank N.V., Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent (incorporated by reference to Exhibit 4.2 to Marathon Oil Corporation’s Form 10-Q for the quarter ended June 30, 2004).

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Exhibit
No.				Description
	4.3			Senior Indenture dated February 26, 2002 between Marathon Oil Corporation and JPMorgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 8-K, filed on March 4, 2002).
	4.4			Senior Indenture dated June 14, 2002 among Marathon Global Funding Corporation, Issuer, Marathon Oil Corporation, Guarantor, and JPMorgan Chase Bank, Trustee (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 8-K, filed on June 21, 2002).
	4.5			Senior Supplemental Indenture No. 1 dated as of September 5, 2003 among Marathon Global Funding Corporation, Issuer, Marathon Oil Corporation, Guarantor, and JPMorgan Chase Bank, Trustee to the Indenture dated as of June 14, 2002 (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2003).
				Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon. Marathon hereby agrees to furnish a copy of any such instrument to the Commission upon its request.
	10.			Material Contracts
	10.1			Amended and Restated Limited Liability Company Agreement of Marathon Ashland Petroleum LLC, dated as of December 31, 1998 (incorporated by reference to Exhibit 10.1 to Marathon Oil Corporation’s Amendment No. 1 to Form 8-K/A, filed on November 29, 2004).
	10.2			Amendment No. 1 dated as of March 17, 2004, to the Amended and Restated Limited Liability Company Agreement of Marathon Ashland Petroleum LLC, dated as of December 31, 1998, by and between Marathon Oil Company and Ashland, Inc. (incorporated by reference to Exhibit 10.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
	10.3			Tax Sharing 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 99.3 to Marathon Oil Corporation’s Form 8-K filed January 3, 2002).
	10.4			Financial Matters Agreement between USX Corporation and United States Steel LLC (converted into United States Steel Corporation) dated as of December 31, 2001 (incorporated by reference to Exhibit 99.5 to Marathon Oil Corporation’s Form 8-K, filed on January 3, 2002).
	10.5			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).
	10.6			License Agreement between USX Corporation and United States Steel LLC (converted into United States Steel Corporation) dated as of December 31, 2001 (incorporated by reference to Exhibit 99.7 to Marathon Oil Corporation’s Form 8-K, filed on January 3, 2002).
	10.7			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).
	10.8			Marathon Oil Corporation 1990 Stock Plan, as Amended and Restated Effective January 1, 2002 (incorporated by reference to Exhibit 10(a) to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001).
	10.9			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).
	10.10			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).
	10.11			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).
	10.12			Form of Non-Qualified Stock Option Grant for Chief Executive Officer granted under Marathon Oil Corporation’s 1990 Stock Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.2 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
	10.13			Form of Non-Qualified Stock Option Grant for Executive Officers granted under Marathon Oil Corporation’s 1990 Stock Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.3 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
	10.14*			Form of Non-Qualified Stock Option Grant for MAP officers granted under Marathon Oil Corporation’s 1990 Stock Plan, as amended and restated effective January 1, 2002.
	10.15			Form of Non-Qualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 (incorporated by reference to Exhibit 10.4 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).

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Exhibit
No.				Description
	10.16			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).
	10.17			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).
	10.18*			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.
	10.19			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).
	10.20			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).
	10.21			Form of 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 10.9 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
	10.22			Form of Non-Qualified Stock Option Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 99.1 to Marathon Oil Corporation’s Form 8-K, filed on May 27, 2005).
	10.23			Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 99.2 to Marathon Oil Corporation’s Form 8-K, filed on May 27, 2005).
	10.24*			Form of Performance Share Award Agreement (2004-2006 Performance Cycle) granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003.
	10.25			Form of Performance Unit Award Agreement (2005-2007 Performance Cycle) granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 99.3 to Marathon Oil Corporation’s Form 8-K filed on May 27, 2005).
	10.26*			Form of Cash Retention Award Agreement.
	10.27*			Marathon Oil Company Excess Benefit Plan.
	10.28*			Marathon Oil Company Deferred Compensation Plan.
	10.29*			Marathon Petroleum Company LLC Excess Benefit Plan.
	10.30*			Marathon Petroleum Company LLC Deferred Compensation Plan.
	10.31*			Speedway SuperAmerica LLC Excess Benefit Plan.
	10.32*			Speedway SuperAmerica LLC Excess Benefit Plan Amendment.
	10.33*			Pilot JV Amendment to Deferred Compensation Plans and Excess Benefits Plans.
	10.34*			EMRO Marketing Company Deferred Compensation Plan.
	10.35			Form of Change of Control Agreement between USX Corporation and Various Officers (incorporated by reference to Exhibit 10.12 to Amendment No. 1 to the Registration Statement on Form S-4/A (File No. 333-69090) of USX Corporation filed on September 20, 2001).
	10.36			Agreement between Marathon Oil Company and Clarence P. Cazalot, Jr., executed February 28, 2000 (incorporated by reference to Exhibit 10(h) to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003).
	10.37			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).
	10.38			General Release dated June 11, 2005, signed by Stephen J. Lowden (incorporated by reference to Exhibit 10.1 to Marathon Oil Corporation’s Form 8-K, filed on June 16, 2005).
	12.1*			Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
	12.2*			Computation of Ratio of Earnings to Fixed Charges.
	14.1			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.

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Exhibit
No.				Description
	31.2*			Certification of Senior Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.
	32.1*			Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
	32.2*			Certification of Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

*	Filed herewith

††	Marathon agrees to furnish supplementally a copy of any omitted schedule to the United States Securities and Exchange Commission upon request.

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								Additions
				Balance at				Charged to				Charged to								Balance at
				Beginning of				Cost and				Other								End of
(In millions)				Period				Expenses				Accounts				Deductions(a)				Period
Year ended December 31, 2005
Reserves deducted in the balance sheet from the assets to which they apply:
	Allowance for doubtful accounts – current			$	6			$	11			$	–			$	14			$	3
	Allowance for doubtful accounts – noncurrent				10				1				–				1				10
	Tax valuation allowances:
		Federal			57				–				70	(b)			7				120
		State			71				–				2				1				72
		Foreign			365				–				70				–				435
Year ended December 31, 2004
Reserves deducted in the balance sheet from the assets to which they apply:
	Allowance for doubtful accounts – current			$	5			$	13			$	–			$	12			$	6
	Allowance for doubtful accounts – noncurrent				10				–				–				–				10
	Tax valuation allowances:
		Federal			67				–				–				10				57
		State			73				–				–				2				71
		Foreign			283				–				82	(c)			–				365
Year ended December 31, 2003
Reserves deducted in the balance sheet from the assets to which they apply:
	Allowance for doubtful accounts – current			$	6			$	10			$	–			$	11			$	5
	Allowance for doubtful accounts – noncurrent				14				2				–				6				10
	Tax valuation allowances:
		Federal			–				–				67	(d)			–				67
		State			78				–				–				5				73
		Foreign			357				–				–				74				283

(a)	Deductions for the allowance for doubtful accounts and long-term receivables include amounts written off as uncollectible, net of recoveries. Deductions in the state tax valuation allowance are due to expiring net operating losses and reduced investment tax credit allowances. Deductions in the foreign tax valuation allowance for 2003 relate to the sale of the exploration and production operations in western Canada and reduction in Norway’s valuation allowance due to additional deferred tax liabilities. Deductions in the federal valuation allowance reflect the amount of excess capital losses utilized during the year.
(b)	Reflects valuation allowances established for deferred tax assets generated in 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.
(c)	Reflects valuation allowances established for deferred tax assets generated in 2004, primarily related to net operating losses.
(d)	Reflects valuation allowances established for deferred tax assets generated in 2003, resulting from excess capital losses related to the sale of exploration and production operations in western Canada.

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	By:	/s/ALBERT G. ADKINS

	Albert G. Adkins
	Vice President, Accounting

Signature				Title
/s/ THOMAS J. USHER Thomas J. Usher				Chairman of the Board and Director
/s/ CLARENCE P. CAZALOT, JR. Clarence P. Cazalot, Jr.				President & Chief Executive Officer and Director
/s/ JANET F. CLARK Janet F. Clark				Senior Vice President and Chief Financial Officer
/s/ ALBERT G. ADKINS Albert G. Adkins				Vice President, Accounting
/s/ CHARLES F. BOLDEN, JR. Charles F. Bolden, Jr.				Director
/s/ DAVID A. DABERKO David A. Daberko				Director
/s/ WILLIAM L. DAVIS William L. Davis				Director
/s/ SHIRLEY ANN JACKSON Shirley Ann Jackson				Director
/s/ PHILLIP LADER Phillip Lader				Director
/s/ CHARLES R. LEE Charles R. Lee				Director
/s/ DENNIS H. REILLEY Dennis H. Reilley				Director
/s/ SETH E. SCHOFIELD Seth E. Schofield				Director
/s/ DOUGLAS C. YEARLEY Douglas C. Yearley				Director

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Ashland		Ashland Inc.
bbl		barrel
bcf		billion cubic feet
bcfd		billion cubic feet per day
BLM		Bureau of Land Management
BOE		barrels of oil equivalent
BOEPD		barrels of oil equivalent per day
bpd		barrels per day
CAA		Clean Air Act
CERCLA		Comprehensive Environmental Response, Compensation, and Liability Act
Clairton 1314B		Clairton 1314B Partnership, L.P.
CLAM		CLAM Petroleum B.V.
CWA		Clean Water Act
DOE		Department of Energy
downstream		refining, marketing and transportation operations
E&P		exploration and production
EG		Equatorial Guinea
EGHoldings		Equatorial Guinea LNG Holdings Limited
EPA		U.S. Environmental Protection Agency
exploratory		wildcat and delineation, i.e., exploratory wells
FASB		Financial Accounting Standards Board
FEED		front-end engineering and design
FIN		FASB Interpretation
GEPetrol		Compania Nacional de Petroleos de Guinea Ecuatorial
GTL		gas-to-liquids
IMV		inventory market valuation
Kinder Morgan		Kinder Morgan Energy Partners, L.P.
KKPL		Kenai Kachemak Pipeline LLC
KMOC		Khanty Mansiysk Oil Corporation
LNG		liquefied natural gas
LOCAP		LOCAP LLC
LOOP		LOOP LLC
LPG		liquefied petroleum gas
MPC		Marathon Petroleum Company LLC
Marathon		Marathon Oil Corporation and its consolidated subsidiaries
Marathon Stock		USX-Marathon Group Common Stock
mbpd		thousand barrels per day
mcf		thousand cubic feet
MKM		MKM Partners L.P.
mmcfd		million cubic feet per day
MTBE		methyl tertiary-butyl ether
NOL		net operating loss
NOx		nitrogen oxide
NYMEX		New York Mercantile Exchange
OCI		other comprehensive income
OPA-90		Oil Pollution Act of 1990
OTC		over the counter
Pilot		Pilot Corporation
PRB		Powder River Basin
PRP(s)		potentially responsible party (ies)
PTC		Pilot Travel Centers LLC
RCRA		Resource Conservation and Recovery Act
RM&T		refining, marketing and transportation
SFAS		statement of financial accounting standards
SPEs		special-purposes entities
SSA		Speedway SuperAmerica LLC
Steel Stock		USX-U. S. Steel Group Common Stock
United States Steel		United States Steel Corporation
upstream		exploration and production operations
USTs		underground storage tanks
VIE		variable interest entity
WTI		West Texas Intermediate

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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 (incorporated by reference to Exhibit 2.1 to USX Corporation’s Form 8-K filed on July 2, 2001).
	2	.2		Agreement and Plan of Reorganization, dated as of July 31, 2001, by and between USX Corporation and United States Steel LLC (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-4 (File No. 333-69090) of USX Corporation filed on September 7, 2001).
	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).
	2	.7††		Amendment No. 2, dated as of March 18, 2004, and Amendment No. 3 dated as of April 27, 2005, to the Amended and Restated Limited Liability Company Agreement of Marathon Ashland Petroleum LLC (incorporated by reference to Exhibit 2.6 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).
	3	.		Articles of Incorporation and Bylaws
	3	.1		Restated Certificate of Incorporation of Marathon Oil Corporation (incorporated by reference to Exhibit 3(a) to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001).
	3	.2		By-laws of Marathon Oil Corporation (incorporated by reference to Exhibit 3(b) to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002).
	4	.		Instruments Defining the Rights of Security Holders, Including Indentures
	4	.1		Five Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, ABN Ambro Bank N.V., Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended June 30, 2004).
	4	.2		Five Year Credit Agreement dated as of May 20, 2004 among Marathon Ashland Petroleum LLC, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, ABN Ambro Bank N.V., Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent (incorporated by reference to Exhibit 4.2 to Marathon Oil Corporation’s Form 10-Q for the quarter ended June 30, 2004).
	4	.3		Senior Indenture dated February 26, 2002 between Marathon Oil Corporation and JPMorgan Chase Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 8-K, filed on March 4, 2002).
	4	.4		Senior Indenture dated June 14, 2002 among Marathon Global Funding Corporation, Issuer, Marathon Oil Corporation, Guarantor, and JPMorgan Chase Bank, Trustee (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 8-K, filed on June 21, 2002).
	4	.5		Senior Supplemental Indenture No. 1 dated as of September 5, 2003 among Marathon Global Funding Corporation, Issuer, Marathon Oil Corporation, Guarantor, and JPMorgan Chase Bank, Trustee to the Indenture dated as of June 14, 2002 (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2003).

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Exhibit No.				Description
				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	.1		Amended and Restated Limited Liability Company Agreement of Marathon Ashland Petroleum LLC, dated as of December 31, 1998 (incorporated by reference to Exhibit 10.1 to Marathon Oil Corporation’s Amendment No. 1 to Form 8-K/A, filed on November 29, 2004).
	10	.2		Amendment No. 1 dated as of March 17, 2004, to the Amended and Restated Limited Liability Company Agreement of Marathon Ashland Petroleum LLC, dated as of December 31, 1998, by and between Marathon Oil Company and Ashland, Inc. (incorporated by reference to Exhibit 10.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
	10	.3		Tax Sharing 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 99.3 to Marathon Oil Corporation’s Form 8-K filed January 3, 2002).
	10	.4		Financial Matters Agreement between USX Corporation and United States Steel LLC (converted into United States Steel Corporation) dated as of December 31, 2001 (incorporated by reference to Exhibit 99.5 to Marathon Oil Corporation’s Form 8-K, filed on January 3, 2002).
	10	.5		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	.6		License Agreement between USX Corporation and United States Steel LLC (converted into United States Steel Corporation) dated as of December 31, 2001 (incorporated by reference to Exhibit 99.7 to Marathon Oil Corporation’s Form 8-K, filed on January 3, 2002).
	10	.7		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	.8		Marathon Oil Corporation 1990 Stock Plan, as Amended and Restated Effective January 1, 2002 (incorporated by reference to Exhibit 10(a) to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001).
	10	.9		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	.10		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	.11		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	.12		Form of Non-Qualified Stock Option Grant for Chief Executive Officer granted under Marathon Oil Corporation’s 1990 Stock Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.2 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
	10	.13		Form of Non-Qualified Stock Option Grant for Executive Officers granted under Marathon Oil Corporation’s 1990 Stock Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.3 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
	10	.14*		Form of Non-Qualified Stock Option Grant for MAP officers granted under Marathon Oil Corporation’s 1990 Stock Plan, as amended and restated effective January 1, 2002.
	10	.15		Form of Non-Qualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 (incorporated by reference to Exhibit 10.4 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
	10	.16		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).

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Exhibit No.				Description
	10	.17		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	.18*		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.
	10	.19		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	.20		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	.21		Form of 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 10.9 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
	10	.22		Form of Non-Qualified Stock Option Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 99.1 to Marathon Oil Corporation’s Form 8-K, filed on May 27, 2005).
	10	.23		Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 99.2 to Marathon Oil Corporation’s Form 8-K, filed on May 27, 2005).
	10	.24*		Form of Performance Share Award Agreement (2004-2006 Performance Cycle) granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003.
	10	.25		Form of Performance Unit Award Agreement (2005-2007 Performance Cycle) granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 99.3 to Marathon Oil Corporation’s Form 8-K filed on May 27, 2005).
	10	.26*		Form of Cash Retention Award Agreement.
	10	.27*		Marathon Oil Company Excess Benefit Plan.
	10	.28*		Marathon Oil Company Deferred Compensation Plan.
	10	.29*		Marathon Petroleum Company LLC Excess Benefit Plan.
	10	.30*		Marathon Petroleum Company LLC Deferred Compensation Plan.
	10	.31*		Speedway SuperAmerica LLC Excess Benefit Plan.
	10	.32*		Speedway SuperAmerica LLC Excess Benefit Plan Amendment.
	10	.33*		Pilot JV Amendment to Deferred Compensation Plans and Excess Benefits Plans.
	10	.34*		EMRO Marketing Company Deferred Compensation Plan.
	10	.35		Form of Change of Control Agreement between USX Corporation and Various Officers (incorporated by reference to Exhibit 10.12 to Amendment No. 1 to the Registration Statement on Form S-4/A (File No. 333-69090) of USX Corporation filed on September 20, 2001).
	10	.36		Agreement between Marathon Oil Company and Clarence P. Cazalot, Jr., executed February 28, 2000 (incorporated by reference to Exhibit 10(h) to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003).
	10	.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).
	10	.38		General Release dated June 11, 2005, signed by Stephen J. Lowden (incorporated by reference to Exhibit 10.1 to Marathon Oil Corporation’s Form 8-K, filed on June 16, 2005).
	12	.1*		Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
	12	.2*		Computation of Ratio of Earnings to Fixed Charges.
	14	.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.

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Exhibit No.				Description
	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 Senior Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.
	32	.1*		Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
	32	.2*		Certification of Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

*	Filed herewith

††	Marathon agrees to furnish supplementally a copy of any omitted schedule to the United States Securities and Exchange Commission upon request.