Edgar Filing: MARATHON OIL CORP

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the Quarterly Period Ended September 30, 2005

		OR

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

For the transition period from to

Commission File Number: 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)

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

5555 San Felipe Road, Houston, TX 77056-2723
(Address of principal executive offices)

(713) 629-6600
(Registrant’s telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes ý No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No ý

There were 366,479,353 shares of Marathon Oil Corporation common stock outstanding as of September 30, 2005.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended September 30, 2005

INDEX

PART I - FINANCIAL INFORMATION

Item 1.	Financial Statements:

	Consolidated Statements of Income (Unaudited)

	Consolidated Balance Sheets (Unaudited)

	Consolidated Statements of Cash Flows (Unaudited)

	Notes to Consolidated Financial Statements (Unaudited)

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3.	Quantitative and Qualitative Disclosures about Market Risk

Item 4.	Controls and Procedures

	Supplemental Statistics (Unaudited)

PART II - OTHER INFORMATION

Item 1.	Legal Proceedings

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Item 6.	Exhibits

Unless the context otherwise indicates, references in this Form 10-Q to “Marathon,” “we,” “our,” or “us” are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon exerts significant influence by virtue of its ownership interest, typically between 20 and 50 percent). On September 1, 2005, subsequent to the acquisition discussed on page 7, Marathon Ashland Petroleum LLC changed its name to Marathon Petroleum Company LLC. In this Form 10-Q, references to Marathon Petroleum Company LLC (“MPC”) are references to the entity formerly known as Marathon Ashland Petroleum LLC.

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)

	Third Quarter Ended September 30,						Nine Months Ended September 30,
(Dollars in millions, except per share data)	2005			2004			2005			2004
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	13,345		$	9,701		$	35,271		$	27,935
Revenues from matching buy/sell transactions	3,433			2,263			9,807			6,714
Sales to related parties	396			285			1,047			766
Income from equity method investments	69			38			154			108
Net gains on disposal of assets	12			17			46			25
Gain on ownership change in Marathon Petroleum Company LLC	—			1			—			2
Other income (loss) – net	(7		)	11			34			51
Total revenues and other income	17,248			12,316			46,359			35,601

Costs and expenses:
Cost of revenues (excluding items shown below)	10,833			7,699			27,790			21,676
Purchases related to matching buy/sell transactions	3,038			2,197			9,312			6,588
Purchases from related parties	44			58			163			152
Consumer excise taxes	1,217			1,137			3,511			3,327
Depreciation, depletion and amortization	331			296			993			896
Selling, general and administrative expenses	325			261			853			763
Other taxes	128			80			352			242
Exploration expenses	64			46			135			108
Total costs and expenses	15,980			11,774			43,109			33,752
Income from operations	1,268			542			3,250			1,849
Net interest and other financing costs	32			40			99			129
Minority interests in income (loss) of:
Marathon Petroleum Company LLC	—			148			384			385
Equatorial Guinea LNG Holdings Limited	(3		)	(1		)	(4		)	(5		)
Income from continuing operations before income taxes	1,239			355			2,771			1,340
Provision for income taxes	469			133			1,004			512
Income from continuing operations	770			222			1,767			828
Discontinued operations	—			—			—			4
Net income	$	770		$	222		$	1,767		$	832

Income Per Share (Unaudited)

	Third Quarter Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Basic:
Income from continuing operations	$	2.11	$	0.64	$	5.01	$	2.48
Net income	$	2.11	$	0.64	$	5.01	$	2.49
Diluted:
Income from continuing operations	$	2.09	$	0.64	$	4.97	$	2.47
Net income	$	2.09	$	0.64	$	4.97	$	2.48
Dividends paid per share	$	0.33	$	0.25	$	0.89	$	0.75

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

(Dollars in millions, except per share data)	September 30, 2005			December 31, 2004
Assets
Current assets:
Cash and cash equivalents	$	1,043		$	3,369
Receivables, less allowance for doubtful accounts of $3 and $6	3,808			3,146
Receivables from United States Steel	21			15
Receivables from related parties	102			74
Inventories	3,338			1,995
Other current assets	211			267
Total current assets	8,523			8,866
Investments and long-term receivables, less allowance for doubtful accounts of $11 and $10	1,830			1,546
Receivables from United States Steel	576			587
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $12,060 and $12,426	13,704			11,810
Prepaid pensions	102			128
Goodwill	950			252
Intangibles	184			118
Other assets	116			116
Total assets	$	25,985		$	23,423

Liabilities
Current liabilities:
Commercial paper payable	$	285		$	—
Accounts payable	5,194			4,430
Payables to related parties	52			44
Payables to United States Steel	6			—
Payroll and benefits payable	279			274
Accrued taxes	576			397
Deferred income taxes	496			—
Accrued interest	52			92
Long-term debt due within one year	316			16
Total current liabilities	7,256			5,253
Long-term debt	3,728			4,057
Deferred income taxes	1,777			1,553
Employee benefits obligations	1,204			989
Asset retirement obligations	505			477
Payables to United States Steel	5			5
Deferred credits and other liabilities	451			288
Total liabilities	14,926			12,622
Minority interest in Marathon Petroleum Company LLC	—			2,559
Minority interests in Equatorial Guinea LNG Holdings Limited	417			131
Commitments and contingencies
Stockholders’ Equity
Common stock:
Common stock issued – 366,705,131 shares at September 30, 2005 and 346,727,029 shares at December 31, 2004 (par value $1 per share, 550,000,000 shares authorized)	367			347
Common stock held in treasury – 225,778 shares at September 30, 2005 and 29,569 shares at December 31, 2004	(9		)	(1		)
Additional paid-in capital	5,092			4,028
Retained earnings	5,261			3,810
Accumulated other comprehensive loss	(56		)	(64		)
Unearned compensation	(13		)	(9		)
Total stockholders’ equity	10,642			8,111
Total liabilities and stockholders’ equity	$	25,985		$	23,423

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

		Nine Months Ended September 30,
(Dollars in millions)		2005			2004
*Increase (decrease) in cash and cash equivalents*

Operating activities
Net income		$	1,767		$	832
Adjustments to reconcile net income to net cash provided from operating activities:
Income from discontinued operations		—			(4		)
Deferred income taxes		(83		)	(26		)
Minority interests in income of subsidiaries		380			380
Depreciation, depletion and amortization		993			896
Pension and other postretirement benefits - net		21			30
Exploratory dry well costs		66			44
Net gains on disposal of assets		(46		)	(25		)
Changes in the fair value of long-term natural gas contracts in the United Kingdom		306			210
Changes in working capital:
Current receivables		(1,577		)	(441		)
Inventories		(457		)	(372		)
Current accounts payable and accrued expenses		727			554
All other - net		(134		)	(101		)

Net cash provided from operating activities		1,963			1,977

Investing activities
Capital expenditures		(2,015		)	(1,377		)
Acquisition		(506		)	—
Disposal of assets		99			47
Proceeds from sale of minority interests in Equatorial Guinea LNG Holdings Limited		163			—
Restricted cash	- deposits	(27		)	(25		)
	- withdrawals	19			6
Investments - loans and advances		(40		)	(152		)
All other - net		6			3
Net cash used in investing activities		(2,301		)	(1,498		)

Financing activities
Payment of debt assumed in acquisition		(1,920		)	—
Commercial paper and revolving credit arrangements - net		285			—
Debt issuance costs		—			(5		)
Other debt repayments		(7		)	(257		)
Issuance of common stock		77			1,036
Dividends paid		(314		)	(251		)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited		175			95
Distributions to minority shareholder of Marathon Petroleum Company LLC		(272		)	–
Net cash provided from (used in) financing activities		(1,976		)	618
Effect of exchange rate changes on cash		(12		)	(1		)
Net increase (decrease) in cash and cash equivalents		(2,326		)	1,096
Cash and cash equivalents at beginning of period		3,369			1,396
Cash and cash equivalents at end of period		$	1,043		$	2,492

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for a fair presentation of the results for the periods presented. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America for complete financial statements. Certain reclassifications of prior year data have been made to conform to 2005 classifications. These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation (“Marathon”) 2004 Annual Report on Form 10-K.

2. New Accounting Standards

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 Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” SFAS No. 19 requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. When a classification of proved reserves cannot yet be made, FSP No. FAS 19-1 allows exploratory well costs to continue to be capitalized when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. Marathon’s 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 were included in the footnotes to Marathon’s consolidated financial statements in its 2004 Annual Report on Form 10-K.

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets – an amendment of APB Opinion No. 29.” This amendment eliminates the APB Opinion No. 29 exception for fair value recognition of nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance. Marathon adopted SFAS No. 153 on a prospective basis as of July 1, 2005.

3. Information about United States Steel

The Separation – On December 31, 2001, in a tax-free distribution to holders of Marathon’s USX—U. S. Steel Group class of common stock (“Steel Stock”), Marathon exchanged the common stock of its wholly owned subsidiary United States Steel Corporation (“United States Steel”) for all outstanding shares of Steel Stock on a one-for-one basis (the “Separation”).

Amounts Receivable from or Payable to United States Steel Arising from the Separation – 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.

Amounts receivable from and payable to United States Steel included in the consolidated balance sheet were as follows:

	September 30,		December 31,
(In millions)	2005		2004
Receivables related to debt and other obligations for which United States Steel has assumed responsibility for repayment:
Current	$	21	$	15
Noncurrent	576		587

Current income tax settlement and related interest payable	$	6	$	—
Noncurrent reimbursements payable under nonqualified employee benefit plans	5		5

Marathon remains primarily obligated for $46 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.

4. Acquisition

On June 30, 2005, Marathon acquired the 38 percent ownership interest in Marathon Ashland Petroleum LLC (“MAP”) previously held by Ashland Inc. (“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)	Amount
Cash (a)	$	487
MPC accounts receivable (a)	913
Marathon common stock (b)	955
Estimated additional consideration related to tax matters (c)	44
Transaction-related costs	10
Purchase price	$	2,409
Assumption of debt (d)	1,920
Total consideration including debt assumption(e)	$	4,329

(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 $509 million representing Ashland’s 38 percent of MPC’s estimated 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) Includes $9 million paid during the quarter ended September 30, 2005, for estimated tax obligations of Ashland under Internal Revenue Service Code Section 355(e).

(d) Assumed debt was repaid on July 1, 2005.

(e) 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.

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 downstream 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 allocation of the purchase price to specific assets and liabilities was based primarily on a third-party appraisal of the fair value of the acquired assets. The allocation of the purchase price is preliminary, pending the completion of that third-party valuation. The following table summarizes the preliminary purchase price allocation to the 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	482
Property, plant and equipment	2,691
Goodwill	694
Intangibles	109
Other assets	8
Total assets acquired	$	7,476

Current liabilities:
Notes payable	$	1,920
Deferred income taxes	669
Other current liabilities	1,700
Total current liabilities assumed	4,289

Long-term debt	16
Deferred income taxes	246
Employee benefits obligations	483
Other liabilities	33
Total liabilities assumed	$	5,067
Net assets acquired	$	2,409

The preliminary valuations and lives of acquired intangible assets are as follows:

(In millions)	Lives	Amount
Retail marketing tradenames	Various	$	52
Refinery permits and plans	15 years	26
Marketing brand agreements	5-10 years	13
Refining technology	5-15 years	12
Other	Various	6
Total		$	109

The goodwill arising from the preliminary allocation was $694 million, which was assigned to the refining, marketing and transportation segment. None of the goodwill is deductible for tax purposes. The goodwill decreased $109 million from the initial estimated purchase price allocation as of June 30, 2005 primarily as a result of an $80 million reduction in the estimated additional consideration related to tax matters.

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 goodwill related to the equity investments.

The following unaudited pro forma results of operations are as if the Acquisition 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.

	Third Quarter Ended September 30,				Nine Months Ended September 30,
(In millions, except per share data)	2005		2004		2005		2004
Revenues and other income	$	17,248	$	12,326	$	46,405	$	35,656
Net income	$	770	$	294	$	1,976	$	1,025
Net income per share:
Basic	$	2.11	$	0.81	$	5.42	$	2.92
Diluted	$	2.09	$	0.81	$	5.38	$	2.91

5. Computation of Income Per Share

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

	Third Quarter Ended September 30,
	2005				2004
(Dollars in millions, except per share data)	Basic		Diluted		Basic		Diluted
Net income	$	770	$	770	$	222	$	222
Shares of common stock outstanding (in thousands):
Average number of common shares outstanding	365,137		365,137		345,037		345,037
Effect of dilutive securities – stock options	—		3,427		—		1,932
Average common shares including dilutive effect	365,137		368,564		345,037		346,969

Net income per share	$	2.11	$	2.09	$	0.64	$	0.64

	Nine Months Ended September 30,
	2005				2004
(Dollars in millions, except per share data)	Basic		Diluted		Basic		Diluted
Income from continuing operations	$	1,767	$	1,767	$	828	$	828
Income from discontinued operations	—		—		4		4
Net income	$	1,767	$	1,767	$	832	$	832
Shares of common stock outstanding (in thousands):
Average number of common shares outstanding	352,807		352,807		333,456		333,456
Effect of dilutive securities – stock options	—		2,919		—		1,713
Average common shares including dilutive effect	352,807		355,726		333,456		335,169

Per share:
Income from continuing operations	$	5.01	$	4.97	$	2.48	$	2.47
Income from discontinued operations	$	—	$	—	$	0.01	$	0.01
Net income	$	5.01	$	4.97	$	2.49	$	2.48

6. Stock-Based Compensation Plans

The following presents the effect on net income and net income per share if the fair value method had been applied to all outstanding awards in each period:

	Third Quarter Ended September 30,						Nine Months Ended September 30,
(In millions, except per share data)	2005			2004			2005			2004
Net income:
As reported	$	770		$	222		$	1,767		$	832
Add: Stock-based compensation expense included in reported net income, net of related tax effects	28			19			69			43
Deduct: Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects	(28		)	(15		)	(69		)	(31		)
Pro forma net income	$	770		$	226		$	1,767		$	844
Basic net income per share:
As reported	$	2.11		$	0.64		$	5.01		$	2.49
Pro forma	$	2.11		$	0.65		$	5.01		$	2.53
Diluted net income per share:
As reported	$	2.09		$	0.64		$	4.97		$	2.48
Pro forma	$	2.09		$	0.65		$	4.97		$	2.52

Marathon records compensation cost over the stated vesting period for stock options that are subject to specific vesting conditions and specify (i) that an employee vests in the award upon becoming “retirement eligible” or (ii) that the employee will continue to vest in the award after retirement without providing any additional service. Upon adoption of 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.

7. Segment Information

Marathon’s operations consist of three operating segments: 1) Exploration and Production (“E&P”) - explores for and produces crude oil and natural gas on a worldwide basis; 2) Refining, Marketing and Transportation (“RM&T”) - refines, markets and transports crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and 3) Integrated Gas (“IG”) – markets and transports natural gas and products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis.

The following presents information by operating segment:

(In millions)	E&P			RM&T			IG			Total Segments
Third Quarter 2005
Revenues:
Customer	$	1,400		$	14,989		$	471		$	16,860
Intersegment(a)	104			78			46			228
Related parties	3			393			—			396
Segment revenues	1,507			15,460			517			17,484
Elimination of intersegment revenues	(104		)	(78		)	(46		)	(228		)
Loss on long-term U.K. gas contracts	(82		)	—			—			(82		)
Total revenues	$	1,321		$	15,382		$	471		$	17,174

Segment income	$	627		$	814		$	(6	)	$	1,435
Income from equity method investments	15			38			16			69
Depreciation, depletion and amortization(b)	198			123			2			323
Capital expenditures(c)	387			201			205			793

Third Quarter 2004
Revenues:
Customer	$	1,110		$	10,578		$	405		$	12,093
Intersegment (a)	99			38			42			179
Related parties	2			283			—			285
Segment revenues	1,211			10,899			447			12,557
Elimination of intersegment revenues	(99		)	(38		)	(42		)	(179		)
Loss on long-term U.K. gas contracts	(129		)	—			—			(129		)
Total revenues	$	983		$	10,861		$	405		$	12,249

Segment income	$	351		$	391		$	18		$	760
Income from equity method investments	8			17			13			38
Depreciation, depletion and amortization(b)	180			105			2			287
Capital expenditures(c)	249			146			58			453

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

(b) Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities and are included in administrative expenses in the reconciliation below.

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

(In millions)	E&P			RM&T			IG			Total Segments
Nine Months 2005
Revenues:
Customer	$	4,139		$	39,939		$	1,306		$	45,384
Intersegment(a)	291			161			134			586
Related parties	8			1,039			—			1,047
Segment revenues	4,438			41,139			1,440			47,017
Elimination of intersegment revenues	(291		)	(161		)	(134		)	(586		)
Loss on long-term U.K. gas contracts	(306		)	—			—			(306		)
Total revenues	$	3,841		$	40,978		$	1,306		$	46,125

Segment income	$	1,958		$	1,847		$	12		$	3,817
Income from equity method investments	34			71			49			154
Depreciation, depletion and amortization(b)	631			332			6			969
Capital expenditures(c)	1,000			498			513			2,011

Nine Months 2004
Revenues:
Customer	$	3,421		$	30,262		$	1,176		$	34,859
Intersegment(a)	261			95			114			470
Related parties	9			757			—			766
Segment revenues	3,691			31,114			1,290			36,095
Elimination of intersegment revenues	(261		)	(95		)	(114		)	(470		)
Loss on long-term U.K. gas contracts	(210		)	—			—			(210		)
Total revenues	$	3,220		$	31,019		$	1,176		$	35,415

Segment income	$	1,253		$	1,017		$	25		$	2,295
Income from equity method investments	17			48			43			108
Depreciation, depletion and amortization(b)	560			307			6			873
Capital expenditures(c)	601			419			346			1,366

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

(b) Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities and are included in administrative expenses in the reconciliation below.

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

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

	Third Quarter Ended September 30,
(In millions)	2005			2004
Segment income	$	1,435		$	760
Items not allocated to segments:
Administrative expenses	(108		)	(90		)
Loss on long-term U.K. gas contracts	(82		)	(129		)
Gain on ownership change in MPC	—			1
Gain on sale of minority interests in Equatorial Guinea LNG Holdings Limited	23			—
Total income from operations	$	1,268		$	542

	Nine Months Ended September 30,
(In millions)	2005			2004
Segment income	$	3,817		$	2,295
Items not allocated to segments:
Administrative expenses	(284		)	(238		)
Loss on long-term U.K. gas contracts	(306		)	(210		)
Gain on ownership change in MPC	—			2
Gain on sale of minority interests in Equatorial Guinea LNG Holdings Limited	23			—
Total income from operations	$	3,250		$	1,849

8. Pensions and Other Postretirement Benefits

The following summarizes the components of net periodic benefit costs:

		Pension Benefits						Other Benefits
		Third Quarter Ended September 30,
(In millions)		2005			2004			2005			2004
Service cost		$	31		$	24		$	5		$	4
Interest cost		30			26			10			8
Expected return on plan assets		(24		)	(23		)	—			—
Amortization	– net transition gain	(1		)	(1		)	—			—
	– prior service costs (credits)	1			1			(3		)	(2		)
	– actuarial loss	12			12			2			—
Multi-employer and other plans		1			—			1			1
Settlement and curtailment losses (gains) (a)		—			19			—			(9		)
Net periodic benefit cost(b)		$	50		$	58		$	15		$	2

(a) Includes $10 million in costs related to business transformation programs for the third quarter of 2004.

(b) Includes MPC’s net periodic pension cost of $34 million and $29 million and other benefits cost of $9 million and $6 million for the third quarter of 2005 and 2004. Includes international net periodic pension cost of $5 million and $6 million for the third quarter of 2005 and 2004.

		Pension Benefits						Other Benefits
		Nine Months Ended September 30,
(In millions)		2005			2004			2005			2004
Service cost		$	88		$	76		$	14		$	14
Interest cost		88			80			29			32
Expected return on plan assets		(70		)	(69		)	—			—
Amortization	– net transition gain	(3		)	(3		)	—			—
	– prior service costs (credits)	3			3			(9		)	(10		)
	– actuarial loss	42			38			7			8
Multi-employer and other plans		2			1			2			2
Settlement and curtailment losses (gains) (c)		—			29			—			(9		)
Net periodic benefit cost (d)		$	150		$	155		$	43		$	37

(d) Includes MPC’s net periodic pension cost of $102 million and $88 million and other benefits cost of $26 million and $25 million for the first nine months of 2005 and 2004. Includes international net periodic pension cost of $16 million and $17 million for the first nine months of 2005 and 2004.

During the nine months ended September 30, 2005, MPC contributed $127 million to its qualified pension plan and Marathon contributed $16 million to its international pension plans. Marathon expects to contribute an additional $15 million to its international pension plans during the remainder of 2005. In addition, during the nine months ended September 30, 2005, contributions made from the general assets of Marathon to cover current benefit payments related to unfunded pension and other postretirement benefit plans were $2 million and $24 million.

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 $263 million and $28 million.

In addition, certain employees of the maleic anhydride business were granted credit for prior service and extended pension and other postretirement benefits under the MPC plans which increased MPC’s obligations by $5 million for both the pension and other postretirement benefit plans. There was not a material impact to future net periodic benefit cost for the remainder of 2005.

9. Income Taxes

The provision for income taxes for interim periods is based on Marathon’s best estimate of the effective tax rate expected to be applicable for the current fiscal year plus any adjustments arising from a change in the estimated amount of taxes related to prior periods.

In the second quarter of 2005, the state of Ohio enacted legislation which phases out Ohio’s income-based franchise taxes over a five-year period. Marathon’s provision for income taxes for the first nine months of 2005 includes a $15 million benefit related to the reversal of deferred income taxes as a result of this change in tax law. The state of Ohio replaced the income-based franchise tax with a commercial activity tax based on gross receipts which will be phased in over five years. The commercial activity tax will be reported in costs and expenses.

In the first quarter of 2005, the state of Kentucky enacted legislation which causes limited liability companies to be subject to Kentucky’s corporation income tax. In the first nine months of 2005, Marathon’s provision for income taxes includes $13 million related to the effects of this Kentucky income tax on deferred tax assets and liabilities as of January 1, 2005. The unfavorable effect on net income (after minority interest) was $6 million.

Also beginning in the first quarter of 2005, Marathon’s effective tax rate reflects the estimated impact of a special deduction for qualified domestic production expected to be taken as a result of the American Jobs Creation Act of 2004. This deduction will be treated as a permanent difference. Based on Marathon’s best estimate of taxable income for 2005, the deduction will reduce the effective tax rate by approximately one-half percent.

10. Comprehensive Income

The following presents Marathon’s comprehensive income for the periods shown:

	Third Quarter Ended September 30,						Nine Months Ended September 30,
(In millions)	2005			2004			2005			2004
Net income	$	770		$	222		$	1,767		$	832
Other comprehensive income (loss), net of tax
Minimum pension liability adjustments	—			—			24			—
Change in fair value of derivative instruments	(1		)	(5		)	(16		)	(26		)
Total comprehensive income	$	769		$	217		$	1,775		$	806

During the third quarter and first nine months of 2004, $2 million of losses related to derivative instruments, net of tax, were reclassified into net income as it was no longer probable the related forecasted transactions would occur.

11. Inventories

Inventories are carried at lower of cost or market. Cost of inventories of crude oil and refined products is determined primarily under the last-in, first-out (“LIFO”) method.

(In millions)	September 30, 2005		December 31, 2004
Liquid hydrocarbons and natural gas	$	1,340	$	676
Refined products and merchandise	1,862		1,192
Supplies and sundry items	136		127
Total (at cost)	$	3,338	$	1,995

12. Suspended Exploratory Well Costs

Marathon’s suspended exploratory well costs at September 30, 2005 were $344 million, an increase of $5 million from December 31, 2004, due to drilling activities in several countries offset by transfers to proved properties and dry well expense. During the first nine months of 2005, there were no impairments of exploratory well costs that had been capitalized for a period of greater than one year after the completion of drilling at December 31, 2004.

During the quarter ended September 30, 2005, $22 million of exploratory well costs related to the Annapolis project offshore Nova Scotia were written off. Sufficient progress toward an economically viable project had not been made since completion of drilling in this prospect in the third quarter of 2004.

13. Debt

At September 30, 2005, Marathon had no borrowings against its $1.5 billion long-term revolving credit facility and had $285 million of commercial paper outstanding under its U.S. commercial paper program that is backed by the long-term revolving credit facility. Certain banks provide Marathon with uncommitted short-term lines of credit totaling $200 million. At September 30, 2005, there were no borrowings against these facilities. Additionally, as part of the Acquisition on June 30, 2005 discussed in Note 4, Marathon assumed $1.920 billion in debt which was repaid on July 1, 2005.

MPC has a $500 million long-term revolving credit facility that terminates in May 2009. At September 30, 2005, there were no borrowings against this facility.

In the event of a change in control of Marathon, debt obligations totaling $1.574 billion at September 30, 2005 may be declared immediately due and payable. In such event, Marathon may also be required to either repurchase certain equipment at United States Steel’s Fairfield Works for $82 million or provide a letter of credit to secure the remaining obligation.

14. MPC Receivables Purchase and Sale Facility

On July 1, 2005, MPC entered into a $200 million, three-year Receivables Purchase and Sale Agreement with certain purchasers. The program is structured to allow MPC to periodically sell a participating interest in pools of eligible accounts receivable. If any receivables are sold under the facility, MPC will not guarantee the transferred receivables and will have no obligations upon default. During the term of the agreement MPC is obligated to pay a facility fee of 0.12%. As of September 30, 2005 no receivables had been sold under this agreement.

15. Supplemental Cash Flow Information

			Nine Months Ended September 30,
(In millions)			2005			2004
Net cash provided from operating activities included:
Interest and other financing costs paid (net of amount capitalized)			$	167		$	198
Income taxes paid to taxing authorities			917			539
Commercial paper and revolving credit arrangements - net:
Commercial paper	– issued		$	3,863		$	—
	– repayments		(3,578		)	—
Credit agreements	– borrowings		10			—
	– repayments		(10		)	—
Ashland credit agreements		– borrowings	—			653
		– repayments	—			(653		)
Total			$	285		$	—
Noncash investing and financing activities:
Asset retirement costs capitalized			$	12		$	17
Debt payments assumed by United States Steel			8			13
Disposal of assets:
Asset retirement obligations assumed by buyer			3			—
Acquisitions:
Debt and other liabilities assumed			4,162			—
Common stock issued to seller			955			—
Receivables transferred to seller			913			—

16. Sale of Minority Interests in EGHoldings

In connection with the formation of Equatorial Guinea LNG Holdings Limited (“EGHoldings”), Compania Nacional de Petroleos de Guinea Ecuatorial (“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 & Co., Ltd. (“Mitsui”) and a subsidiary of Marubeni Corporation (“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 the quarter ended September 30, 2005, Marathon received net proceeds of $163 million in connection with the transactions and recorded a gain of $23 million, which is included in other income (loss) – net.

17. Contingencies and Commitments

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

Environmental matters – Marathon is subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance. At September 30, 2005 and December 31, 2004, accrued liabilities for remediation totaled $109 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 $69 million at September 30, 2005, and $65 million at December 31, 2004.

Contract commitments – At September 30, 2005, Marathon’s contract commitments to acquire property, plant and equipment and long-term investments totaled $1.026 billion.

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

18. Accounting Standards Not Yet Adopted

In December 2004, the FASB issued 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. In 2003, Marathon adopted the fair value method 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 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, defers the effective date until January 1, 2006. Marathon plans to adopt the provisions of this statement 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.

In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143.” This interpretation clarifies that an entity is required to recognize a liability for a legal obligation to perform asset retirement activities when the retirement is conditional on a future event if the liability’s fair value can be reasonably estimated. If the liability’s fair value cannot be reasonably estimated, then the entity must disclose (a) a description of the obligation, (b) the fact that a liability has not been recognized because the fair value cannot be reasonably estimated, and (c) 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 is required to implement this interpretation no later than December 31, 2005 and is currently studying its provisions to determine the impact, if any, on its consolidated financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” SFAS No. 154 requires companies to recognize (i) voluntary changes in accounting principle and (ii) 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 corrections of errors made in fiscal years beginning after December 15, 2005.

In September 2005, the FASB ratified the consensus reached by the Emerging Issues Task Force regarding 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. Marathon is currently studying the provisions of this consensus to determine the impact on its consolidated financial statements.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Marathon Oil Corporation is engaged in worldwide exploration and production of crude oil and natural gas; domestic refining, marketing and transportation of crude oil and petroleum products; and worldwide marketing and transportation of natural gas and products manufactured from natural gas. Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements. The discussion of the Consolidated Statements of Income should be read in conjunction with the Supplemental Statistics provided on page 33.

Certain sections of Management’s Discussion and Analysis include forward-looking statements concerning trends or events potentially affecting Marathon. These statements typically contain words such as ‘‘anticipates,’’ ‘‘believes,’’ ‘‘estimates,’’ ‘‘expects,’’ ‘‘targets,’’ “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. For additional risk factors affecting our businesses, see the information preceding Part I in our 2004 Annual Report on Form 10-K and subsequent filings.

Unless specifically noted, amounts for MPC include the 38 percent interest held by Ashland prior to the Acquisition, and amounts for EGHoldings include the 25 percent interest held by GEPetrol and the cumulative 15 percent interest held by Mitsui and Marubeni subsequent to July 25, 2005.

Overview and Outlook

We acquired the 38 percent interest in MPC held by Ashland Inc. on June 30, 2005. For additional information on the Acquisition, see Note 4 to the Consolidated Financial Statements. Third quarter 2005 results benefited from full ownership of MPC. We believe the outlook for the refining and marketing business is attractive in our core areas of operation and expect the levels of demand to remain high for the foreseeable future. This acquisition increases our participation in the downstream business without the risks commonly associated with integrating a newly acquired business.

During the third quarter of 2005, our U.S. Gulf Coast operations were significantly impacted by Hurricanes Katrina and Rita. Operationally, our oil and natural gas production facilities in the Gulf of Mexico sustained only minimal damage from these storms, and we have nearly returned to our pre-storm production levels in the Gulf of Mexico. Our refining and transportation operations also sustained relatively minor damage and were able to resume operations within days after the storms, providing much needed transportation fuels to the markets we serve.

While these hurricanes disrupted our operations, resulting in a reduction in our third quarter upstream sales of approximately 20,000 barrels of oil equivalent per day (“boepd”) and a loss of approximately 40,000 barrels per day (“bpd”) of refinery throughput, we still had sound operating and financial performances during the quarter. The consistent performance of both our upstream and downstream businesses allowed us to capture the value of continued high commodity prices and strong refining margins.

Exploration and Production

Crude oil and natural gas sales during the quarter averaged 291,500 boepd. Production available for sale during the third quarter of 2005 averaged 321,000 boepd. The variance between actual sales volumes and production available for sale for the quarter is primarily a result of the timing of international crude oil liftings, primarily in the United Kingdom and Equatorial Guinea.

While our third quarter production results were negatively impacted by hurricanes in the Gulf of Mexico, other portions of our business continued to generate production increases, particularly in Equatorial Guinea and Russia. In Equatorial Guinea, we realized the benefits of strong condensate production and the full ramp-up of the recently completed liquefied petroleum gas (“LPG”) expansion project. During the third quarter, total liquids production available for sale in Equatorial Guinea averaged 45,000 net bpd. In addition, we continued development activities in the East Kamennoye field in Russia where we have an ongoing drilling program. These activities have driven total Russian production available for sale from an average of 14,000 net bpd during third quarter of 2004 to 28,000 net bpd during third quarter of 2005.

Our cost of storm-related repairs in the Gulf of Mexico is not expected to be significant. Work continues to restore our remaining operated and outside-operated production, with current Gulf of Mexico production at more than 95 percent of pre-storm levels of approximately 60,000 boepd. The restart of remaining oil and gas production is primarily dependent upon restoration of production from the outside-operated Ursa platform. Despite the negative effects of hurricanes on third quarter production levels, we estimate 2005 average daily production available for sale to be 340,000 to 350,000 boepd, excluding the impact of any acquisitions or dispositions. Daily production available for sale for the fourth quarter is estimated to be 350,000 to 370,000 boepd.

During the third quarter, we continued our exploration success offshore Angola with the Astraea and Hebe discoveries on Block 31. In addition, we have participated in an appraisal well on the Gengibre discovery on Block 32. Results of this well will be released upon partner and government approvals. We hold a 10 percent interest in outside-operated Block 31 and a 30 percent interest in outside-operated Block 32.

Marathon is currently participating in an appraisal well on the Plutao discovery in Angola Block 31, an exploration well on the Mostarda Prospect in Angola Block 32, a deep shelf exploration well on the Aquarius prospect in the Gulf of Mexico, an exploration well on the Davan prospect in the United Kingdom, and an appraisal well on the Gudrun discovery offshore Norway.

In Norway, the Alvheim/Vilje development project is 29 percent complete and progressing on schedule with first production projected in 2007.

The above discussion includes forward-looking statements with respect to the timing and levels of our worldwide liquid hydrocarbon, natural gas and condensate production, the possibility of developing Blocks 31 and 32 offshore Angola, the development of the Alvheim and Vilje fields and estimated costs of storm-related repairs. Some factors that could potentially affect this forward-looking information include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, acquisitions or dispositions of oil and gas properties, regulatory constraints, timing of commencing production from new wells, drilling rig availability, inability or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response and other geological, operating and economic considerations. Other factors that could affect the development of Blocks 31 and 32 offshore Angola include presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. Actual costs of storm-related repairs could be different than estimates as new information about the extent of damage inflicted by the storms becomes available. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Refining, Marketing and Transportation

Our RM&T segment benefited from a higher refining and wholesale marketing margin in the third quarter due to the impact that Hurricanes Katrina and Rita had on refined product margins. Our Garyville, Louisiana and Texas City, Texas refineries returned to operation safely with a minimum amount of downtime. These refineries sustained minimal damage during these storms and were able to be brought back on-line within days after the hurricanes, allowing us to meet the demand for transportation fuels during this period of reduced supply. The repair cost associated with these hurricanes was not significant.

While spot market gasoline and distillate prices peaked at all time highs during the third quarter our RM&T prices and realizations were constrained by competitive pricing at the wholesale and retail levels.

Refinery crude runs during the third quarter of 2005 averaged 979,600 bpd, with total throughput averaging 1,194,800 bpd. This record throughput was achieved despite the loss of approximately 40,000 bpd of refinery capacity due to the hurricanes. In addition to the temporary complete shut-down of the Garyville and Texas City refineries, we experienced minor reductions in throughputs at some of our Midwest refineries due to the temporary closure of crude oil pipelines originating in the U.S. Gulf Coast after Hurricane Katrina.

We expect our average crude oil throughput for the total year 2005 to exceed the crude oil throughput record set in 2004.

Speedway SuperAmerica LLC (“SSA”) realized increased same-store merchandise sales of approximately 11 percent when compared to the third quarter of 2004. In addition, SSA also increased its same store gasoline sales volume during the third quarter by approximately 5 percent compared to the same quarter last year.

Our $300 million, 26,000 bpd Detroit, Michigan refinery crude oil throughput expansion and Tier II low sulfur fuels project is in the final stages of completion. The refinery was shut down on September 29, 2005 to accommodate the installation and integration of key project components and other related work. The refinery is expected to restart in

mid-November 2005 with a total crude processing capacity of 100,000 bpd. The expansion also will enable the refinery to meet the Federal Tier II low-sulfur fuels regulations which become fully effective in 2006.

We plan to pursue an expansion of our 245,000 bpd Garyville, Louisiana, refinery. The project, estimated to cost approximately $2.2 billion, is expected to increase the refinery’s crude throughput capacity by 180,000 bpd to 425,000 bpd, with completion possibly as early as the fourth quarter of 2009. The initial phase of the expansion will include front-end engineering and design (“FEED”) work that could lead to the start of construction in 2007. Anticipated project investments include the installation of a new crude distillation unit, hydrocracker, reformer, kerosene hydrotreater, delayed coker, additional sulfur recovery capacity and other infrastructure investments. The new facilities will incorporate the latest safety and environmental control technologies. The proposed refinery configuration also will be designed to provide maximum feedstock flexibility, enabling us to process more heavy sour crude oils.

The above discussion includes forward-looking statements with respect to refinery throughputs, the Detroit capital project and the planned expansion of the Garyville refinery. Some factors that could potentially cause the actual results from the Detroit construction project to be different than expected include availability of materials and labor, unforeseen hazards such as weather conditions, and other risks customarily associated with construction projects. Some factors that could affect refinery throughputs include unexpected downtime due to operating problems, weather conditions, and labor issues. Some factors that could affect the Garyville expansion include satisfactory results of the FEED work, Marathon board and necessary regulatory approvals, crude oil supply and transportation logistics, necessary permits, a continued favorable investment climate, availability of materials and labor, unforeseen hazards such as weather conditions, and other risks customarily associated with construction projects. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas

Our Equatorial Guinea LNG train 1 project made continued progress during the quarter and remains on-track to begin first shipment of LNG in 2007. The project was 58 percent complete on an engineering, procurement and construction basis and expenditures totaled $1 billion of the total gross estimated project cost of $1.4 billion as of September 30, 2005. Also, the Equatorial Guinea LNG project partners continue to explore the feasibility of adding a second LNG train in an effort to create a regional gas hub that would commercialize stranded gas from various sources in the surrounding Gulf of Guinea region.

We sold minority interests totaling 15 percent in EGHoldings and recorded a gain of $23 million. Following the closing of the transaction on July 25, 2005, we now hold a 60 percent interest in this consolidated subsidiary.

The above discussion contains forward-looking statements with respect to the estimated construction cost and startup dates of a LNG liquefaction plant and related facilities and the possible expansion thereof. Factors that could affect the estimated construction cost and startup dates of the LNG liquefaction plant and related facilities include, without limitation, unforeseen problems arising from construction, inability or delay in obtaining necessary government and third-party approvals, unanticipated changes in market demand or supply, environmental issues, availability or construction of sufficient LNG vessels, and unforeseen hazards such as weather conditions. In addition to these factors, other factors that could affect the possible expansion of the current LNG project and the development of additional LNG capacity through additional projects include partner approvals, access to sufficient gas volumes through exploration or commercial negotiations with other resource owners and access to sufficient regasification capacity. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Results of Operations

Revenues for the third quarter and first nine months of 2005 and 2004 are summarized in the following table:

	Third Quarter Ended September 30,						Nine Months Ended September 30,
(In millions)	2005			2004			2005			2004
E&P	$	1,507		$	1,211		$	4,438		$	3,691
RM&T	15,460			10,899			41,139			31,114
IG	517			447			1,440			1,290
Segment revenues	17,484			12,557			47,017			36,095
Elimination of intersegment revenues	(228		)	(179		)	(586		)	(470		)
Loss on long-term U.K. gas contracts	(82		)	(129		)	(306		)	(210		)
Total revenues	$	17,174		$	12,249		$	46,125		$	35,415
Items included in both revenues and costs and expenses:
Consumer excise taxes on petroleum products and merchandise	$	1,217		$	1,137		$	3,511		$	3,327

Matching crude oil, gas and refined product buy/sell transactions settled in cash:
E&P	$	30		$	45		$	100		$	127
RM&T	3,403			2,218			9,707			6,587
Total buy/sell transactions	$	3,433		$	2,263		$	9,807		$	6,714

E&P segment revenues increased by $296 million in the third quarter of 2005 from the comparable prior-year period. For the first nine months of 2005, revenues increased by $747 million from the prior-year period. These increases were primarily due to higher worldwide liquid hydrocarbon and natural gas prices and international liquid hydrocarbon sales volumes partially offset by lower domestic natural gas and liquid hydrocarbon sales volumes. Derivative losses totaled $9 million and $11 million in the third quarter and the first nine months of 2005, compared to losses of $75 million and $128 million in the third quarter and first nine months of 2004. Matching buy/sell transactions decreased by $15 million and $27 million in the third quarter and first nine months of 2005 from the comparable prior-year periods due to decreased crude oil buy/sell transactions, partially offset by higher domestic liquid hydrocarbon prices.

Excluded from the E&P segment revenues were losses of $82 million and $306 million for the third quarter and the first nine months of 2005 and losses of $129 million and $210 million for the third quarter and the first nine months of 2004 on long-term gas contracts in the United Kingdom that are accounted for as derivative instruments.

RM&T segment revenues increased by $4.561 billion in the third quarter of 2005 from the comparable prior-year period. For the first nine months of 2005, revenues increased by $10.025 billion from the prior-year period. The increases primarily reflected higher refined product and crude oil prices and increased refined product sales volumes, partially offset by decreased crude oil sales volumes. Matching buy/sell transaction revenues increased by $1.185 billion and $3.120 billion in the third quarter and first nine months of 2005 from the comparable prior-year periods primarily due to increased crude oil prices and volumes and increased refined product prices, partially offset by decreased refined product sales volumes.

IG segment revenues increased by $70 million in the third quarter of 2005 from the comparable prior-year period. For the first nine months of 2005, revenues increased by $150 million from the comparable prior-year period. These increases primarily reflected higher natural gas marketing prices. Derivative losses totaled $13 million and $9 million in the third quarter and the first nine months of 2005, compared to gains of $4 million and $14 million in the third quarter and first nine months of 2004.

For additional information on segment results, see “Results of Operations by Segment” on page 23.

Cost of revenues for the third quarter of 2005 increased by $3.134 billion from the comparable prior-year period. For the first nine months of 2005, cost of revenues increased by $6.114 billion from the comparable prior-year period. The increases in the RM&T segment primarily reflected higher acquisition costs for crude oil, other refinery charge and blend stocks and refined products and higher manufacturing expenses. This was partially offset by decreases in E&P as a result of lower crude oil marketing activity.

Purchases related to matching buy/sell transactions for the third quarter and first nine months of 2005 increased by $841 million and $2.724 billion from the comparable prior-year periods. The increases are primarily due to increased crude oil and refined product prices and increased crude oil purchase volumes, partially offset by decreased refined product purchase volumes. Differences between revenues from matching buy/sell transactions and purchases related to matching buy/sell transactions for the third quarter and first nine months of 2005 are primarily due to timing differences between the delivery and receipt of certain matching transaction volumes. There is no effect on income as a result these timing differences.

Selling, general and administrative expenses for the third quarter and the first nine months of 2005 increased by $64 million and $90 million from the comparable prior-year periods. The increase in the third quarter of 2005 was primarily due to increased stock-based compensation expense, employee benefit expenses and other employee related costs as well as contributions to hurricane relief efforts. The increase in the first nine months of 2005 was primarily a result of increased stock-based compensation expense partially offset by prior year severance and pension plan curtailment charges and start-up costs related to EGHoldings.

Exploration expenses for the third quarter and the first nine months of 2005 increased by $18 million and $27 million, compared to the same periods in 2004. During the quarter ended September 30, 2005, $22 million of exploratory well costs related to the Annapolis project offshore Nova Scotia were written off. Sufficient progress toward an economically viable project had not been made since completion of drilling in this prospect in the third quarter of 2004. The subsea wellhead remains in place and could be tied back into a development in the future. We continue to evaluate further drilling in this area.

Net interest and other financing costs for the third quarter and the first nine months of 2005 decreased by $8 million and $30 million, compared to the same periods in 2004. The decrease in the third quarter is primarily due to increased capitalized interest partially offset by a decrease in interest income. The decrease in the first nine months of 2005 is primarily a result of increased interest income on investments and capitalized interest, partially offset by increased interest on potential tax deficiencies and higher foreign exchange losses.

Minority interest in income of MPC decreased $148 million and $1 million in the third quarter and the first nine months of 2005 from the comparable prior-year periods due to the completion of the acquisition of Ashland’s 38 percent interest in MPC on June 30, 2005.

Provision for income taxes in the third quarter and the first nine months of 2005 increased by $336 million and $492 million from the comparable prior-year periods primarily due to increases of $884 million and $1.431 billion in income before income taxes.

In the first quarter of 2005, the state of Kentucky enacted legislation which causes limited liability companies to be subject to Kentucky’s corporation income tax. Our provision for income taxes for the first nine months of 2005 includes $13 million related to the effects of this Kentucky income tax on deferred tax assets and liabilities as of January 1, 2005. The unfavorable effect on net income (after minority interest) was $6 million. In the second quarter of 2005, the state of Ohio enacted legislation which phases out Ohio’s income-based franchise taxes over a five-year period. Our provision for income taxes in the first nine months of 2005 includes a $15 million benefit related to the reversal of deferred income taxes as a result of this change in tax law. The state of Ohio replaced the income-based franchise tax with a commercial activity tax based on gross receipts which will be phased in over five years. The commercial activity tax will be reported in costs and expenses.

The effective tax rate for the first nine months of 2005 was 36.2 percent compared to 38.2 percent for the comparable period in 2004. The decrease in the rate is primarily related to the effects of foreign operations and the legislation discussed above.

Net income for the third quarter and the first nine months of 2005 increased by $548 million and $935 million from the comparable prior-year periods, primarily reflecting the elimination of the minority interest in our downstream business and the factors discussed above.

Results of Operations by Segment

Income from operations for the third quarter and the first nine months of 2005 and 2004 is summarized in the following table:

	Third Quarter Ended September 30,						Nine Months Ended September 30,
(In millions)	2005			2004			2005			2004
E&P
Domestic	$	397		$	244		$	1,096		$	835
International	230			107			862			418
E&P segment income	627			351			1,958			1,253
RM&T	814			391			1,847			1,017
IG	(6		)	18			12			25
Segment income	1,435			760			3,817			2,295
Items not allocated to segments:
Administrative expenses	(108		)	(90		)	(284		)	(238		)
Loss on long-term U.K. gas contracts	(82		)	(129		)	(306		)	(210		)
Gain on ownership change in MPC	—			1			—			2
Gain on sale of minority interests in EGHoldings	23			—			23			—
Income from operations	$	1,268		$	542		$	3,250		$	1,849

Domestic E&P income in the third quarter of 2005 increased by $153 million from the third quarter of 2004. Income in the first nine months of 2005 increased by $261 million from the same period in 2004. The increases were due to higher liquid hydrocarbon and natural gas prices partially offset by lower sales volumes. These lower volumes resulted primarily from weather-related downtime in the Gulf of Mexico and natural field declines in the Permian Basin. The first nine months of 2005 included business interruption insurance recoveries of $53 million related to Hurricane Ivan storm-related claims. Derivative losses totaled $9 million and $11 million in the third quarter and the first nine months of 2005, compared to losses of $58 million and $98 million in the third quarter and first nine months of 2004.

Our domestic average realized liquid hydrocarbon price excluding derivative activity was $52.38 and $44.24 per barrel (“bbl”) in the third quarter and first nine months of 2005, compared with $35.56 and $32.23 per bbl in the comparable prior-year periods. Domestic average gas prices were $6.56 and $5.76 per thousand cubic feet (“mcf”) excluding derivative activity in the third quarter and first nine months of 2005, compared with $4.76 and $4.83 per mcf in the corresponding 2004 periods.

Domestic net liquid hydrocarbon sales volumes decreased to 75.9 thousand barrels per day (“mbpd”) in the first nine months of 2005, down 12 percent from the 2004 comparable period, as a result of lower production primarily as a result of storm-related downtime in the Gulf of Mexico and natural field declines in the Permian Basin. Domestic net natural gas sales volumes averaged 570.4 million cubic feet per day (“mmcfd”) in the first nine months of 2005, down 12 percent from the 2004 comparable period as a result of lower production in the Permian Basin and Camden Hills in the Gulf of Mexico due to natural field declines and downtime associated with Hurricane Ivan.

International E&P income in the third quarter of 2005 increased by $123 million from the third quarter of 2004. Income in the first nine months of 2005 increased by $444 million from the same period in 2004. The increases were primarily a result of higher product prices and liquid hydrocarbon sales volumes, partially offset by higher production taxes in Russia, dry well expenses and lower natural gas production. Derivative losses totaled $17 million and $30 million in the third quarter and the first nine months of 2004. There was no derivative activity in 2005.

Our international average realized liquid hydrocarbon price excluding derivative activity was $48.24 and $44.42 per bbl in the third quarter and the first nine months of 2005, compared with $37.07 and $31.78 per bbl in the 2004 comparable periods. International average gas prices were $3.12 and $3.62 per mcf excluding derivative activity in the third quarter and the first nine months of 2005, compared with $2.79 and $3.15 per mcf in the corresponding 2004 periods.

International net liquid hydrocarbon sales volumes increased to 103.8 mbpd in the first nine months of 2005, up 20 percent from the 2004 comparable period, as a result of increased production in Equatorial Guinea and Russia. International net natural gas sales volumes averaged 337.1 mmcfd in the first nine months of 2005, down 5 percent from the 2004 comparable period, as a result of reduced U.K. spot gas sales.

RM&T segment income in the third quarter of 2005 increased by $423 million from the third quarter of 2004. Income in the first nine months of 2005 increased by $830 million from the same period in 2004. The increases were due to higher refining and wholesale marketing margins. The higher refined product margins in the third quarter were due primarily to the impacts of Hurricanes Katrina and Rita. The refining and wholesale marketing margin in the third quarter and the first nine months of 2005 averaged 17.7 and 13.7 cents per gallon, versus the 2004 comparable period levels of 9.0 and 8.5 cents per gallon. We also benefited from wider crack spreads and sweet/sour crude differentials.

Losses from derivative activity included in the refining and wholesale marketing margin were $271 million and $410 million in the third quarter and the first nine months of 2005 as compared to $67 million and $270 million in the same periods of 2004. Generally, losses on derivatives included in the refining and wholesale marketing margin are offset by gains on the underlying physical transactions.

Additionally, losses from derivative trading opportunities were $42 million and $76 million in the third quarter and the first nine months of 2005 as compared to gains of $2 million and $14 million in the comparable prior-year periods.

The IG segment had a loss of $6 million in the third quarter of 2005 compared to income of $18 million in the third quarter of 2004. Income in the first nine months of 2005 decreased by $13 million from the same period in 2004. The decrease in the third quarter was primarily the result of mark-to-market changes in the fair value of derivatives used to support gas marketing activities. The methanol operations in Equatorial Guinea have been operating at a 98 percent on-stream factor in 2005 and posted index prices for methanol have remained strong.

Dividends to Stockholders

On October 26, 2005, our Board of Directors (the “Board”) declared a dividend of 33 cents per share, payable December 12, 2005, to stockholders of record at the close of business on November 16, 2005.

Cash Flows

Net cash provided from operating activities was $1.963 billion in the first nine months of 2005, compared with $1.977 billion in the first nine months of 2004. The $14 million decrease reflects working capital changes, primarily due to the $913 million in receivables which were transferred to Ashland on June 30, 2005, as a part of the Acquisition and higher inventories in the current period, partially offset by higher net income in the first nine months of 2005.

Capital expenditures in the first nine months of 2005 totaled $2.015 billion compared with $1.377 billion in the same period of 2004. The $638 million increase mainly reflected increased spending in the E&P segment related to the Alvheim development offshore Norway and increased spending in the IG segment related to continuing construction of our natural gas liquefaction plant in Equatorial Guinea. For information regarding capital expenditures by segment, refer to the Supplemental Statistics.

Acquisition included cash payments of $506 million for the first nine months of 2005 for the Acquisition. For additional information on the Acquisition, see Note 4 to the Consolidated Financial Statements.

Net cash used in financing activities was $1.976 billion in the first nine months of 2005, compared with net cash provided from financing activities of $618 million in the first nine months 2004. The change was due to the repayment of $1.920 billion of debt assumed as a part of the Acquisition in 2005 and to the issuance of 34,500,000 shares of common stock on March 31, 2004, resulting in net proceeds of $1.004 billion in 2004. These effects were partially offset by a net $285 million of commercial paper borrowings in the first nine months of 2005 and the repayment on maturity of $250 million of 7.2% notes in the first quarter of 2004. The first nine months of 2005 included contributions of $175 million from the minority shareholders of EGHoldings and $272 million of distributions to the minority shareholder of MPC prior to the Acquisition.

Derivative Instruments

See “Quantitative and Qualitative Disclosures About Market Risk” for discussion of derivative instruments and associated market risk.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, committed and uncommitted credit facilities, an uncommitted accounts receivables sales facility, and access to both the debt and equity capital markets. Our ability to access the debt capital market is supported by our investment grade credit ratings. Our senior unsecured debt is currently rated investment grade by Standard and Poor’s Corporation, Moody’s Investor Services, Inc. and Fitch Ratings with ratings of BBB+, Baa1, and BBB+. Because of the liquidity and capital resource alternatives available to us, including internally generated cash flow, we believe that our short-term and long-term liquidity is adequate to fund operations, including our capital spending programs, repayment of debt maturities for the years 2005, 2006 and 2007, and any amounts that may ultimately be paid in connection with contingencies.

We have a committed $1.5 billion five-year revolving credit facility that terminates in May 2009. At September 30, 2005, there were no borrowings against this facility. At September 30, 2005, we had $285 million in commercial paper outstanding under the U.S. commercial paper program that is backed by the five-year revolving credit facility. Additionally, we have other uncommitted short-term lines of credit totaling $200 million, of which no amounts were drawn at September 30, 2005.

MPC has a committed $500 million five-year revolving credit facility with third-party financial institutions that terminates in May 2009. At September 30, 2005, there were no borrowings against this facility. On July 1, 2005, MPC originated an uncommitted $200 million accounts receivable sale facility. This facility allows MPC to sell interests in certain of its receivables to a third-party financial institution on a non-recourse basis. If any receivables are sold under the facility, MPC will not guarantee the transferred receivables and will have no obligations upon default. There have been no receivables sold as of the filing of this report.

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

As of September 30, 2005, there was $1.7 billion aggregate amount of common stock, preferred stock and other equity securities, debt securities, trust preferred securities or other securities, including securities convertible into or exchangeable for other equity or debt securities available to be issued under the $2.7 billion universal shelf registration statement filed with the Securities and Exchange Commission in 2002. On June 30, 2005, we issued $955 million of common stock to Ashland shareholders through a separate registration statement filed with the Securities and Exchange Commission which was declared effective May 20, 2005.

Our cash-adjusted debt-to-capital ratio (total-debt-minus-cash to total-debt-plus-equity-minus-cash) was 24 percent at September 30, 2005, compared to 8 percent at year-end 2004 as shown below. This includes $587 million of debt that is serviced by United States Steel Corporation (“United States Steel”). We continually monitor our spending levels, market conditions and related interest rates to maintain what we perceive to be reasonable debt levels.

(Dollars in millions)	September 30, 2005			December 31, 2004
Commercial paper	$	285		$	—
Long-term debt due within one year	316			16
Long-term debt	3,728			4,057
Total debt	$	4,329		$	4,073
Cash	$	1,043		$	3,369
Equity	$	10,642		$	8,111
Calculation
Total debt	$	4,329		$	4,073
Minus cash	1,043			3,369
Total debt minus cash	3,286			704
Total debt	4,329			4,073
Plus equity	10,642			8,111
Minus cash	1,043			3,369
Total debt plus equity minus cash	$	13,928		$	8,815
Cash-adjusted debt-to-capital ratio	24		%	8		%

As a condition of the closing agreements for the Acquisition, we are required to maintain MPC on a stand-alone basis financially for a two-year period. During this period of time, we are precluded from making capital contributions into MPC and MPC is prohibited from incurring additional debt, except for borrowings under an existing intercompany loan facility to fund an expansion project at MPC’s Detroit refinery and in the event of limited extraordinary circumstances. MPC may only use its revolving credit facility for short-term working capital requirements in a manner consistent with past practices. MPC may use its accounts receivable sale facility to maintain an adequate level of liquidity to manage its operations. We believe these facilities and cash provided from MPC’s operations will be adequate to meet its liquidity requirements.

Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as determined by various measures, including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies.

Contractual Cash Obligations

Subsequent to December 31, 2004, there have been no significant changes to our obligations to make future payments under existing contracts. The portion of our obligations to make future payments under existing contracts that have been assumed by United States Steel has not changed significantly subsequent to December 31, 2004.

Off-Balance Sheet Arrangements

Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources; and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources. There have been no significant changes to our off-balance sheet arrangements subsequent to December 31, 2004.

Nonrecourse Indebtedness of Investees

Certain of our equity investees have incurred indebtedness that we do not support through guarantees or otherwise. If we were obligated to share in this debt on a pro rata ownership basis, our share would have been $269 million as of September 30, 2005. Of this amount, $144 million relates to Pilot Travel Centers LLC (“PTC”). If any of these equity investees default, we have no obligation to support the debt. Our partner in PTC has guaranteed $157 million of the total PTC debt.

Obligations Associated with the Separation of United States Steel

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

As of September 30, 2005, we have obligations totaling $643 million that have been assumed by United States Steel. Of the total $643 million, obligations of $597 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet (current portion - $21 million; long-term portion - $576 million). The remaining $46 million was related to operating lease obligations of United States Steel.

Environmental Matters

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately recovered in the prices of our products and services, operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil and refined products.

Tier II gasoline and on-road diesel fuel rules require substantially reduced sulfur levels for gasoline and diesel starting in 2004 and 2006. We expect the combined capital costs to achieve compliance with the gasoline and diesel regulations to be approximately $900 million over the period between 2002 and 2006 and includes costs that could be incurred as part of other refinery upgrade projects. This is a forward-looking statement. Costs incurred through September 30, 2005, were approximately $740 million. Some factors (among others) that could potentially affect gasoline and diesel fuel compliance costs include completion of project detailed engineering, construction and start-up activities.

During 2001, we entered into a New Source Review consent decree and settlement of alleged Clean Air Act (‘‘CAA’’) and other violations with the U. S. Environmental Protection Agency covering all of our refineries. The settlement committed us to specific control technologies and implementation schedules for environmental expenditures and improvements to our refineries over approximately an eight-year period. The total one-time expenditures for these environmental projects are estimated to be approximately $380 million over the eight-year period, with about $255 million incurred through September 30, 2005. The impact of the settlement on ongoing operating expenses is expected to be immaterial. In addition, we have nearly completed certain agreed upon supplemental environmental projects as part of this settlement of an enforcement action for alleged CAA violations, at a cost of $9 million. We believe this settlement will provide increased permitting and operating flexibility while achieving significant emission reductions. During the second quarter of 2005, the court approved a first amendment to the consent decree pertaining to the Texas City Refinery which allows greater operational flexibility to the refinery during periods of amine shortages, while we otherwise agreed to pollution-reducing measures at that refinery. We will also contribute at least $100,000 as a supplemental environmental project to install diesel retrofit technologies on sanitation trucks owned by Texas City, Texas. The consent decree requires us to publicly state that this is part of a settlement of an enforcement action for alleged CAA violations.

There have been no other significant changes to our environmental matters subsequent to December 31, 2004. Changes in accrued liabilities for remediation and receivables for recoverable costs since December 31, 2004 are described in Note 17 to the Consolidated Financial Statements.

Other Contingencies

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

Other Matters

We suspended operations in Sudan in 1985, but continue to hold an interest in an exploration and production sharing agreement. We have derived no economic benefit from our Sudan interests. We have and will continue to abide by all U.S. sanctions related to Sudan and will not resume any activity regarding our interests there until such time as it is permitted under U.S. law.

We discovered the Ash Shaer and Cherrife gas fields in Syria in the 1980’s. We submitted four plans of development to the Syrian Petroleum Company in the 1990’s, but none were approved. The Syrian government subsequently claimed that the production sharing contract for these fields had expired. We have been involved in an ongoing dispute with the Syrian Petroleum Company and Syrian government over our interest in these fields, and are currently discussing a settlement under which a new production sharing contract would be executed, and we would have the right to sell all or a significant portion of our interest to a third party. We have and will continue to comply with all U.S. sanctions related to Syria.

We are continuing to work with our partners and the Libyan government to finalize the terms of the group’s reentry agreement. We also opened an office in Tripoli during the second quarter of 2005.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Management Opinion Concerning Derivative Instruments

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

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

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

Our E&P segment primarily uses commodity derivative instruments selectively to protect against price decreases on portions of our future production when deemed advantageous to do so. We also use derivatives to protect the value of natural gas purchased and injected into storage in support of production operations. We use financial derivative instruments to manage foreign currency exchange rate exposure on foreign currency denominated capital expenditures, operating expenses and foreign tax payments.

Our RM&T segment uses commodity derivative instruments to:

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

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

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

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

• protect against decreases in future crack spreads,

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

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

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

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

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

Commodity Price Risk

Sensitivity analyses of the incremental effects on income from operations of hypothetical 10 percent and 25 percent changes in commodity prices for open derivative instruments as of September 30, 2005 are provided in the following table:

	Incremental Decrease in Income from Operations Assuming a Hypothetical Price Change of: (a)
(In millions)	10%			25%
Commodity Derivative Instruments:(b)(c)
Natural gas(d)	$	69	(e)	$	172	(e)
Refined products(d)	6		(e)	18		(e)

(a) We remain at risk for possible changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying hedged item. Effects of these offsets are not reflected in the sensitivity analyses. Amounts reflect hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at September 30, 2005. The hypothetical price changes of 10 percent and 25 percent would result in incremental decreases in income from operations of $79 million and $198 million related to long-term 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 commodity derivative instruments on an ongoing basis and add or revise strategies to reflect anticipated market conditions and changes in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review, including the use of master netting agreements to the extent practical. Changes to the portfolio after September 30, 2005, would cause future income from operations effects to differ from those presented in the table.

(b) Net open contracts for the combined E&P and IG segments varied throughout the third quarter of 2005, from a low of 1,243 contracts at August 28 to a high of 1,717 contracts at September 30, and averaged 1,462 for the quarter. The number of net open contracts for the RM&T segment varied throughout the third quarter of 2005, from a low of 11,734 contracts at August 8 to a high of 26,554 contracts at July 20, and averaged 20,093 for the quarter. The commodity derivative 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 reflects that which would result in the largest incremental decrease in income from operations when applied to the commodity derivative instruments used to hedge that commodity.

(e) Price increase.

E&P Segment

At September 30, 2005, we had no open equity production derivative contracts. We evaluate the commodity price risk of our equity production on an ongoing basis and may enter into commodity derivative instruments when it is deemed advantageous.

Derivative losses included in the E&P segment were $11 million and $128 million for the first nine months of 2005 and 2004. Additionally, losses of $3 million from discontinued cash flow hedges are included in segment results for the first nine months of 2004. The discontinued cash flow hedge amounts were reclassified from accumulated other comprehensive loss as it was no longer probable that the original forecasted transactions would occur. There were no reclassifications during the first nine months of 2005.

Excluded from the E&P segment results were losses of $306 million and $210 million for the first nine months of 2005 and 2004 on long-term gas contracts in the United Kingdom that are accounted for as derivative instruments.

RM&T Segment

We do not attempt to qualify commodity derivative instruments used in our RM&T operations for hedge accounting. As a result, we recognize all changes in the fair value of derivatives used in our RM&T operations in income, although most of these derivatives have an underlying physical commodity transaction. Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying physical commodity transactions. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying physical commodity transactions. Derivative gains or losses included in RM&T segment income for the first nine months of 2005 and 2004 are summarized in the following table:

	Nine Months Ended September 30,
(In millions)	2005			2004
Strategy:
Mitigate price risk	$	(119	)	$	(88	)
Protect carrying values of excess inventories	(233		)	(111		)
Protect margin on fixed price sales	23			10
Protect crack spread values	(81		)	(81		)
Trading activities	(76		)	14
Total net derivative losses	$	(486	)	$	(256	)

IG Segment

We have used derivative instruments to convert the fixed price of a long-term gas sales contract to market prices. The underlying physical contract is for a specified annual quantity of gas and matures in 2008. Similarly, we use derivative instruments to convert shorter term (typically less than a year) fixed price contracts to market prices in our ongoing natural gas marketing and transportation activity; to hedge purchased gas injected into storage for subsequent resale; and to lock in margins for gas purchased and subsequently resold. IG segment income included derivative losses of $9 million and derivative gains of $14 million for the first nine months of 2005 and 2004.

Other Commodity Related Risks

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

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

Interest Rate Risk

We are impacted by interest rate fluctuations which affect the fair value of certain financial instruments. A sensitivity analysis of the projected incremental effect of a hypothetical 10 percent decrease in interest rates as of September 30, 2005 is provided in the following table:

(In millions)	Fair Value (b)			Incremental Increase in Fair Value (c)
Financial assets (liabilities)(a):
Interest rate swap agreements	$	(28	)	$	13
Long-term debt(d)(e)	$	(4,556	)	$	(156	)

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

(c) For long-term debt, this assumes a 10 percent decrease in the weighted average yield to maturity of Marathon’s long-term debt at September 30, 2005. For interest rate swap agreements, this assumes a 10 percent decrease in the effective swap rate at September 30, 2005.

(d) See below for sensitivity analysis.

(e) Includes amounts due within one year and the effects of interest rate swaps.

At September 30, 2005, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to interest rate fluctuations. This sensitivity is illustrated by the $156 million increase in the fair value of long-term debt assuming a hypothetical 10 percent decrease in interest rates. However, our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio would unfavorably affect our results and cash flows only if we would elect to repurchase or otherwise retire all or a portion of our fixed-rate debt portfolio at prices above carrying value.

We manage our exposure to interest rate movements by utilizing financial derivative instruments. The primary objective of this program is to reduce our overall cost of borrowing by managing the fixed and floating interest rate mix of the debt portfolio. We have entered into several interest rate swap agreements, designated as fair value hedges, which effectively resulted in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates. The following table summarizes, by individual debt instrument, the interest rate swap activity as of September 30, 2005:

Floating Rate to be Paid	Fixed Rate to be Received		Notional Amount		Swap Maturity	Fair Value
Six Month LIBOR +4.226%	6.650	%	$	300 million	2006	$	(2	)million
Six Month LIBOR +1.935%	5.375	%	$	450 million	2007	$	(8	)million
Six Month LIBOR +3.285%	6.850	%	$	400 million	2008	$	(10	)million
Six Month LIBOR +2.142%	6.125	%	$	200 million	2012	$	(8	)million

Foreign Currency Exchange Rate Risk

We manage our exposure to foreign currency exchange rates by utilizing forward and option contracts, generally with terms of 365 days or less. The primary objective of this program is to reduce our exposure to movements in the foreign currency markets by locking in foreign currency rates. At September 30, 2005, the following currency derivatives were outstanding. All contracts currently qualify for hedge accounting unless noted.

Financial Instruments	Period	Notional Amount		All-in-Rate(a)		Fair Value(b)
Foreign Currency Rate Swaps:
Euro	October 2005 – December 2005	$	28 million	1.312	(c)	$	(2	)million
Norwegian kroner	October 2005 – December 2005	$	70 million	6.363	(d)	$	(2	)million
Foreign Currency Rate Options:
Euro	January 2006 – June 2006	$	88 million	1.295	(c)(e)	$	1	million
Norwegian kroner	January 2006 – February 2006	$	62 million	6.150	(d)(e)	$	—	million

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

(b) Fair value was based on market prices.

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

(e) Represents the strike price at which the foreign currency can be purchased.

The aggregate effect on foreign exchange forward and option contracts of a hypothetical 10 percent change to quarter-end forward exchange rates would be approximately $10 million.

Credit Risk

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

Safe Harbor

These quantitative and qualitative disclosures about market risk include forward-looking statements with respect to management’s opinion about risks associated with the use of derivative instruments. These statements are based on certain assumptions with respect to market prices and industry supply of and demand for crude oil, natural gas, refined products and other feedstocks. If these assumptions prove to be inaccurate, future outcomes with respect to our hedging programs may differ materially from those discussed in the forward-looking statements.

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of Marathon’s management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective. During the quarter ended September 30, 2005, there were no changes in our internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We review and modify our financial and operational controls on an ongoing basis to ensure that those controls are adequate to address changes in our business as it evolves. We believe that our existing financial and operational controls and procedures are adequate.

MARATHON OIL CORPORATION

Supplemental Statistics – (Unaudited)

	Third Quarter Ended September 30,						Nine Months Ended September 30,
(Dollars in millions, except as noted)	2005			2004			2005			2004
INCOME FROM OPERATIONS
Exploration and Production
United States	$	397		$	244		$	1,096		$	835
International	230			107			862			418
E&P segment income	627			351			1,958			1,253
Refining, Marketing and Transportation(a)	814			391			1,847			1,017
Integrated Gas(b)	(6		)	18			12			25
Segment income	1,435			760			3,817			2,295

Items not allocated to segments:
Administrative expenses	(108		)	(90		)	(284		)	(238		)
Loss on U.K. long-term gas contracts	(82		)	(129		)	(306		)	(210		)
Gain on ownership change - MPC	—			1			—			2
Gain on sale of minority interests in EGHoldings	23			—			23			—
Income from operations	$	1,268		$	542		$	3,250		$	1,849

CAPITAL EXPENDITURES
Exploration and Production	$	387		$	249		$	1,000		$	601
Refining, Marketing and Transportation	201			146			498			419
Integrated Gas(b)	205			58			513			346
Corporate	1			5			4			11
Total	$	794		$	458		$	2,015		$	1,377

EXPLORATION EXPENSE
United States	$	18		$	15		$	60		$	47
International	46			31			75			61
Total	$	64		$	46		$	135		$	108

OPERATING STATISTICS
Net Liquid Hydrocarbon Sales (mbpd)(c)
United States	70.7			80.7			75.9			86.6

Europe	11.3			31.4			30.4			39.1
West Africa	48.0			29.2			48.3			31.3
Other international	27.0			15.3			25.1			15.8
Total international	86.3			75.9			103.8			86.2
Worldwide	157.0			156.6			179.7			172.8

Net Natural Gas Sales (mmcfd)(c)(d)
United States	561.8			598.0			570.4			646.6

Europe	158.7			225.8			244.4			278.9
West Africa	86.3			77.4			92.7			74.9
Total international	245.0			303.2			337.1			353.8
Worldwide	806.8			901.2			907.5			1,000.4

Total production (mboepd)	291.5			306.8			331.0			339.5

	Third Quarter Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Average Sales Prices (excluding derivative gains and losses)
Liquid Hydrocarbons ($ per bbl)
United States	$	52.38	$	35.56	$	44.24	$	32.23

Europe	61.44		41.37		49.73		35.12
West Africa	50.45		38.82		47.03		33.11
Other international	38.78		24.89		32.98		20.88
Total international	48.24		37.07		44.42		31.78
Worldwide	50.10		36.29		44.34		32.00
Natural Gas ($ per mcf)
United States	$	6.56	$	4.76	$	5.76	$	4.83

Europe	4.69		3.66		4.90		3.92
West Africa	0.25		0.25		0.25		0.25
Total international	3.12		2.79		3.62		3.15
Worldwide	5.52		4.10		4.96		4.23

Average Sales Prices (including derivative gains and losses)
Liquid Hydrocarbons ($ per bbl)
United States	$	52.38	$	28.58	$	44.24	$	28.58

Europe	61.44		35.37		49.73		32.31
West Africa	50.45		38.82		47.03		33.11
Other international	38.78		24.89		32.98		20.84
Total international	48.24		34.59		44.42		30.49
Worldwide	50.10		31.49		44.34		29.53

Natural Gas ($ per mcf)
United States	$	6.37	$	4.65	$	5.68	$	4.77

Europe(e)	4.69		3.66		4.90		3.92
West Africa	0.25		0.25		0.25		0.25
Total international	3.12		2.79		3.62		3.15
Worldwide	5.38		4.02		4.92		4.19

	Third Quarter Ended September 30,				Nine Months Ended September 30,
(Dollars in millions, except as noted)	2005		2004		2005		2004

Refinery Runs (mbpd):
Crude oil refined	979.6		977.1		971.4		926.6
Other charge and blend stocks	215.2		146.3		187.2		161.4
Total	1,194.8		1,123.4		1,158.6		1,088.0

Refined Product Yields (mbpd):
Gasoline	658.1		610.3		623.7		595.2
Distillates	325.4		311.7		314.9		290.0
Propane	22.3		22.6		21.6		21.7
Feedstocks and special products	88.8		88.6		100.8		97.3
Heavy fuel oil	21.0		19.3		24.4		22.1
Asphalt	90.2		85.5		86.6		75.8
Total	1,205.8		1,138.0		1,172.0		1,102.1
Refined Products Sales Volumes (mbpd)(f)	1,466.8		1,436.2		1,438.2		1,394.7
Matching buy/sell volumes included in refined product sales volumes (mbpd)	66.4		83.5		77.8		79.1

Refining and Wholesale Marketing Margin(g)(h)	$	0.1774	$	0.0900	$	0.1369	$	0.0849

Number of SSA Retail Outlets	1,638		1,685
SSA Gasoline and Distillate Sales(i)	825		794		2,392		2,358
SSA Gasoline and Distillate Gross Margin(g)	$	0.1232	$	0.1185	$	0.1170	$	0.1175
SSA Merchandise Sales	$	689	$	632	$	1,894	$	1,754
SSA Merchandise Gross Margin	$	162	$	154	$	468	$	426

(a) RM&T segment income includes Ashland’s 38 percent interest in MPC of $149 million in the third quarter of 2004, and $390 million and $389 million for the first nine months of 2005 and 2004, respectively.

(b) Includes EGHoldings at 100 percent.

(d) Includes gas acquired for injection and subsequent resale of 58.9, and 14.4 mmcfd for the third quarter of 2005 and 2004 and 34.1 and 19.9 mmcfd for the first nine months of 2005 and 2004. 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.

(e) Excludes the effects of the U.K. long-term gas contracts that are accounted for as derivatives.

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

(g) Dollars per gallon.

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

(i) Millions of gallons.

Part II - OTHER INFORMATION

Item 1. Legal Proceedings

Environmental Proceedings

The Ohio Attorney General, on behalf of the Ohio Environmental Protection Agency, has notified SSA of its intention to bring an enforcement action for alleged wastewater violations at three of its locations in Ohio. SSA personnel have been in discussions with Ohio officials in an attempt to resolve this matter.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases of equity securities that are registered by Marathon pursuant to Section 12 of the Exchange Act by Marathon and its affiliated purchaser during the third quarter of 2005:

ISSUER PURCHASES OF EQUITY SECURITIES

					(c)
Period	(a) Total Number of Shares Purchased(1)(2)		(b) Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
07/01/05 – 07/31/05	7,564		$	53.46	N/A	N/A
08/01/05 – 08/31/05	1,765		$	59.75	N/A	N/A
09/01/05 – 09/30/05	23,146	(3)	$	67.97	N/A	N/A
3^rd Quarter 2005	32,475		$	64.14	N/A	N/A

(1) 6,982 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements in the third quarter of 2005.

(2) 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. The number of fractional shares Marathon acquired due to Acquisition exchanges and Ashland share transfers pending at the time of closing of the Acquisition were 5,875, 19, and 8 for the months of July, August and September, respectively.

(3) 19,591 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 during the third quarter of 2005. Shares needed to meet the requirements of the Plan are either purchased in the open market or issued directly by Marathon.

Item 6. Exhibits

(a) EXHIBITS

10.1 Summary of non-employee director compensation effective January 1, 2006 (incorporated by reference to Form 8-K filed October 31, 2005)

10.2 Summary of Gary R. Heminger’s compensation and performance criteria (incorporated by reference to Form 8-K filed July 1, 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

31.1 Certification of President and Chief Executive Officer pursuant to Exchange Act Rules 13a-14 and 15d-14, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2 Certification of Senior Vice President and Chief Financial Officer pursuant to Exchange Act Rules 13a-14 and 15d-14, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2 Certification of Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned chief accounting officer thereunto duly authorized.

	MARATHON OIL CORPORATION


	By:	/s/ A. G. Adkins
		A. G. Adkins
	Vice President –Accounting

November 4, 2005