Edgar Filing: MARATHON OIL CORP

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the Quarterly Period Ended September 30, 2007

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 x No o

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

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

Yes o No x

There were 710,279,884 shares of Marathon Oil Corporation common stock outstanding as of October 31, 2007.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended September 30, 2007

INDEX

PART I - FINANCIAL INFORMATION		3

Item 1.	Financial Statements:	3

	Consolidated Statements of Income (Unaudited)	3

	Consolidated Balance Sheets (Unaudited)	4

	Consolidated Statements of Cash Flows (Unaudited)	5

	Selected Notes to Consolidated Financial Statements (Unaudited)	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29

Item 4.	Controls and Procedures	33

	Supplemental Statistics (Unaudited)	34

PART II - OTHER INFORMATION		36

Item 1.	Legal Proceedings	36

Item 1A.	Risk Factors	36

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37

Item 6.	Exhibits	38

	Signatures	39

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 method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon exerts significant influence by virtue of its ownership interest).

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)*	2007			2006			2007			2006
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	16,345		$	15,837		$	45,096		$	44,699
Revenues from matching buy/sell transactions	2			237			125			5,249
Sales to related parties	415			418			1,146			1,141
Income from equity method investments	170			109			394			298
Net gain on disposal of assets	2			12			20			28
Other income	20			21			62			48
Total revenues and other income	16,954			16,634			46,843			51,463
Costs and expenses:
Cost of revenues (excludes items below)	12,994			11,260			34,291			32,647
Purchases related to matching buy/sell transactions	2			222			147			5,205
Purchases from related parties	59			61			160			159
Consumer excise taxes	1,352			1,297			3,856			3,739
Depreciation, depletion and amortization	409			361			1,198			1,130
Selling, general and administrative expenses	336			300			950			895
Other taxes	95			92			286			280
Exploration expenses	88			97			264			234
Total costs and expenses	15,335			13,690			41,152			44,289

Income from operations	1,619			2,944			5,691			7,174
Net interest and other financing costs (income)	(19		)	(7		)	(58		)	7
Gain on foreign currency derivative instruments	(120		)	—			(120		)	—
Loss on early extinguishment of debt	11			—			14			—
Minority interests in loss of Equatorial Guinea LNG Holdings Limited	—			(2		)	(3		)	(7		)

Income from continuing operations before income taxes	1,747			2,953			5,858			7,174

Provision for income taxes	726			1,330			2,578			3,296
Income from continuing operations	1,021			1,623			3,280			3,878

Discontinued operations	—			—			8			277

Net income	$	1,021		$	1,623		$	3,288		$	4,155

Per Share Data

Basic:
Income from continuing operations	$	1.50		$	2.28		$	4.80		$	5.38
Discontinued operations	—			—			$	0.01		$	0.38
Net income	$	1.50		$	2.28		$	4.81		$	5.76

Diluted:
Income from continuing operations	$	1.49		$	2.26		$	4.76		$	5.33
Discontinued operations	—			—			$	0.01		$	0.38
Net income	$	1.49		$	2.26		$	4.77		$	5.71

Dividends paid	$	0.24		$	0.20		$	0.68		$	0.56

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

	September 30,			December 31,
*(Dollars in millions, except per share data)*	2007			2006
Assets
Current assets:
Cash and cash equivalents	$	3,269		$	2,585
Receivables, less allowance for doubtful accounts of $3 and $3	5,297			4,114
Receivables from United States Steel	35			32
Receivables from related parties	91			63
Inventories	4,604			3,173
Other current assets	167			129
Total current assets	13,463			10,096
Equity method investments	2,650			1,539
Receivables from United States Steel	485			498
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $14,602 and $13,573	16,655			16,653
Goodwill	1,391			1,398
Intangible assets, less accumulated amortization of $80 and $75	175			180
Other noncurrent assets	1,140			467
Total assets	$	35,959		$	30,831
Liabilities
Current liabilities:
Accounts payable	$	6,682		$	5,586
Payable to United States Steel	—			13
Payables to related parties	33			264
Payroll and benefits payable	364			409
Accrued taxes	625			598
Deferred income taxes	625			631
Accrued interest	69			89
Long-term debt due within one year	423			471
Total current liabilities	8,821			8,061
Long-term debt	5,678			3,061
Deferred income taxes	1,898			1,897
Defined benefit postretirement plan obligations	1,375			1,245
Asset retirement obligations	1,098			1,044
Payable to United States Steel	7			7
Deferred credits and other liabilities	400			391
Total liabilities	19,277			15,706
Minority interests in Equatorial Guinea LNG Holdings Limited	—			518
Commitments and contingencies

Stockholders’ Equity

Common stock issued — 735,703,116 shares (par value $1 per share, 1,100,000,000 shares authorized)	736			736
Common stock held in treasury, at cost — 54,575,462, and 40,161,340 shares	(2,378		)	(1,638		)
Additional paid-in capital	4,793			4,784
Retained earnings	13,916			11,093
Accumulated other comprehensive loss	(385		)	(368		)
Total stockholders’ equity	16,682			14,607
Total liabilities and stockholders’ equity	$	35,959		$	30,831

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)*	2007			2006
*Increase (decrease) in cash and cash equivalents*
Operating activities:
Net income	$	3,288		$	4,155
Adjustments to reconcile net income to net cash provided from operating activities:
Loss on early extinguishment of debt	14			—
Income from discontinued operations	(8		)	(277		)
Deferred income taxes	12			186
Minority interests in loss of Equatorial Guinea LNG Holdings Limited	(3		)	(7		)
Depreciation, depletion and amortization	1,198			1,130
Pension and other postretirement benefits, net	68			(103		)
Exploratory dry well costs and unproved property impairments	109			119
Net gain on disposal of assets	(20		)	(28		)
Equity method investments, net	(123		)	(210		)
Changes in the fair value of long-term U.K. natural gas contracts	111			(182		)
Changes in:
Current receivables	(1,190		)	(444		)
Inventories	(1,444		)	(999		)
Current accounts payable and accrued expenses	988			334
All other, net	(49		)	2
Net cash provided from continuing operations	2,951			3,676
Net cash provided from discontinued operations	—			69
Net cash provided from operating activities	2,951			3,745
Investing activities:
Capital expenditures	(2,725		)	(2,405		)
Acquisitions	—			(543		)
Disposal of assets	51			79
Disposal of discontinued operations	—			832
Trusteed funds - withdrawals	163			—
Investments - loans and advances	(88		)	(4		)
Investments - repayments of loans and return of capital	35			219
Deconsolidation of Equatorial Guinea LNG Holdings Limited	(37		)	—
Investing activities of discontinued operations	—			(45		)
All other, net	(8		)	15
Net cash used in investing activities	(2,609		)	(1,852		)
Financing activities:
Borrowings	2,071			—
Debt issuance costs	(19		)	—
Debt repayments	(541		)	(304		)
Issuance of common stock	23			41
Purchases of common stock	(800		)	(1,146		)
Excess tax benefits from stock-based compensation arrangements	25			26
Dividends paid	(465		)	(407		)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited	39			64
Net cash provided by (used in) financing activities	333			(1,726		)
Effect of exchange rate changes on cash	9			13
Net increase in cash and cash equivalents	684			180
Cash and cash equivalents at beginning of period	2,585			2,617
Cash and cash equivalents at end of period	$	3,269		$	2,797

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 reported. 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 2007 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” or the “Company”) 2006 Annual Report on Form 10-K.

2. New Accounting Standards

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

In July 2006, the FASB issued FASB Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109.” FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes.” FIN No. 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, transition and disclosure. Marathon adopted FIN No. 48 effective January 1, 2007, and adoption did not have a significant effect on its consolidated results of operations, financial position or cash flows. See Note 9 for other disclosures required by FIN No. 48.

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

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

3. Deconsolidation of Equatorial Guinea LNG Holdings Limited

Equatorial Guinea LNG Holdings Limited (“EGHoldings”), in which Marathon holds a 60 percent interest, was formed for the purpose of constructing and operating a liquefied natural gas (“LNG”) production facility. During facility construction, EGHoldings was a variable interest entity (“VIE”) that was consolidated by Marathon because Marathon was its primary beneficiary. Once the LNG production facility commenced its primary operations and began to generate revenue in May 2007, EGHoldings was no longer a VIE. Effective May 1, 2007, Marathon no longer consolidates EGHoldings, despite the fact that the Company holds majority ownership, because the minority shareholders have rights limiting Marathon’s ability to exercise control over the entity. Marathon’s investment is accounted for prospectively using the equity method of accounting, is carried at the Company’s share of net assets plus loans and advances, which totaled $1.023 billion as of September 30, 2007, and is included in equity method investments in the consolidated balance sheet as of that date.

4. Common Stock Split

On April 25, 2007, Marathon’s stockholders approved an increase in the number of authorized shares of common stock from 550 million to 1.1 billion shares, and the Company’s Board of Directors subsequently declared a two-for-one split of the Company’s common stock. The stock split was effected in the form of a stock dividend distributed on June 18, 2007, to stockholders of record at the close of business on May 23, 2007. Stockholders received one additional share of Marathon Oil Corporation common stock for each share of common stock held as of the close of business on the record date. In addition, shares of common stock issued or issuable for stock-based awards under Marathon’s incentive compensation plans were proportionately increased in accordance with the terms of the plans. Common stock and per share (except par value) information for all periods presented has been restated in the consolidated financial statements and notes to reflect the stock split.

5. Discontinued Operations

On June 2, 2006, Marathon sold its Russian oil exploration and production businesses in the Khanty-Mansiysk region of western Siberia. A gain on the sale of $243 million ($342 million before income taxes) was reported in discontinued operations in the second quarter of 2006. During the second quarter of 2007, adjustments to the sales price were substantially completed and an additional gain on the sale of $8 million ($13 million before income taxes) was recognized.

The activities of the Russian businesses have been reported as discontinued operations in the consolidated statements of income and cash flows for 2006. Revenues and pretax income from discontinued operations were $173 million and $45 million in the first nine months of 2006.

6. Income per Common Share

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

	Third Quarter Ended September 30,
	2007				2006
*(In millions, except per share data)*	Basic		Diluted		Basic		Diluted
Income from continuing operations	$	1,021	$	1,021	$	1,623	$	1,623
Discontinued operations	—		—		—		—
Net income	$	1,021	$	1,021	$	1,623	$	1,623
Weighted average common shares outstanding	680		680		713		713
Effect of dilutive securities	—		5		—		6
Weighted average common shares, including dilutive effect	680		685		713		719
Per share:
Income from continuing operations	$	1.50	$	1.49	$	2.28	$	2.26
Discontinued operations	$		$	—	$		$	—
Net income	$	1.50	$	1.49	$	2.28	$	2.26

	Nine Months Ended September 30,
	2007				2006
*(In millions, except per share data)*	Basic		Diluted		Basic		Diluted
Income from continuing operations	$	3,280	$	3,280	$	3,878	$	3,878
Discontinued operations	8		8		277		277
Net income	$	3,288	$	3,288	$	4,155	$	4,155

Weighted average common shares outstanding	684		684		721		721
Effect of dilutive securities	—		5		—		7
Weighted average common shares, including dilutive effect	684		689		721		728

Per share:
Income from continuing operations	$	4.80	$	4.76	$	5.38	$	5.33
Discontinued operations	$	0.01	$	0.01	$	0.38	$	0.38
Net income	$	4.81	$	4.77	$	5.76	$	5.71

The per share calculations above exclude 3.0 million stock options for the third quarter and first nine months of 2007 and 2.2 million stock options for the third quarter and first nine months of 2006, as they were antidilutive.

7. Segment Information

As of September 30, 2007, Marathon’s operations consisted of three reportable operating segments:

1) Exploration and Production (“E&P”) — explores for, produces and markets crude oil and natural gas on a worldwide basis;

2) Refining, Marketing and Transportation (“RM&T”) — refines, markets and transports crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and

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

As discussed in Note 5 above, the Russian businesses sold in June 2006 were accounted for as discontinued operations. Segment information for the first nine months of 2006 excludes the operating results for these Russian operations.

*(In millions)*	E&P			RM&T			IG		Total
Third Quarter Ended September 30, 2007
Revenues:
Customer	$	2,318		$	14,088		$	64	$	16,470
Intersegment(a)	116			115			—		231
Related parties	13			402			—		415
Segment revenues	2,447			14,605			64		17,116
Elimination of intersegment revenues	(116		)	(115		)	—		(231		)
Loss on long-term U.K. natural gas contracts	(123		)	—			—		(123		)
Total revenues	$	2,208		$	14,490		$	64	$	16,762
Segment income	$	479		$	482		$	52	$	1,013
Income from equity method investments	60			44			66		170
Depreciation, depletion and amortization(b)	254			146			1		401
Income tax provision(b)	544			262			8		814
Capital expenditures(c)	582			430			2		1,014

*(In millions)*	E&P			RM&T			IG			Total
Third Quarter Ended September 30, 2006
Revenues:
Customer	$	2,062		$	13,861		$	30		$	15,953
Intersegment(a)	200			1			—			201
Related parties	3			415			—			418
Segment revenues	2,265			14,277			30			16,572
Elimination of intersegment revenues	(200		)	(1		)	—			(201		)
Gain on long-term U.K. natural gas contracts	121			—			—			121
Total revenues	$	2,186		$	14,276		$	30		$	16,492
Segment income	$	572		$	1,026		$	(2	)	$	1,596
Income from equity method investments	57			48			4			109
Depreciation, depletion and amortization(b)	209			142			3			354
Minority interests in loss of subsidiary	—			—			(2		)	(2		)
Income tax provision(b)	644			656			7			1,307
Capital expenditures(c)	795			223			72			1,090

*(In millions)*	E&P			RM&T			IG			Total
Nine Months Ended September 30, 2007
Revenues:
Customer	$	6,041		$	39,103		$	188		$	45,332
Intersegment(a)	372			199			—			571
Related parties	24			1,122			—			1,146
Segment revenues	6,437			40,424			188			47,049
Elimination of intersegment revenues	(372		)	(199		)	—			(571		)
Loss on long-term U.K. natural gas contracts	(111		)	—			—			(111		)
Total revenues	$	5,954		$	40,225		$	188		$	46,367
Segment income	$	1,264		$	2,073		$	83		$	3,420
Income from equity method investments	165			116			113			394
Depreciation, depletion and amortization(b)	733			436			5			1,174
Minority interests in loss of subsidiary	—			—			(3		)	(3		)
Income tax provision(b)	1,438			1,181			20			2,639
Capital expenditures(c)	1,623			981			93			2,697

*(In millions)*	E&P			RM&T			IG			Total
Nine Months Ended September 30, 2006
Revenues:
Customer	$	6,495		$	43,141		$	130		$	49,766
Intersegment(a)	577			16			—			593
Related parties	9			1,132			—			1,141
Segment revenues	7,081			44,289			130			51,500
Elimination of intersegment revenues	(577		)	(16		)	—			(593		)
Gain on long-term U.K. natural gas contracts	182			—			—			182
Total revenues	$	6,686		$	44,273		$	130		$	51,089
Segment income	$	1,696		$	2,262		$	23		$	3,981
Income from equity method investments	163			106			29			298
Depreciation, depletion and amortization(b)	686			412			7			1,105
Minority interests in loss of subsidiary	—			—			(7		)	(7		)
Income tax provision(b)	1,840			1,424			11			3,275
Capital expenditures(c)	1,616			527			236			2,379

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

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

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

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

	Third Quarter Ended						Nine Months Ended
	September 30,						September 30,
*(In millions)*	2007			2006			2007			2006
Segment income	$	1,013		$	1,596		$	3,420		$	3,981
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	3			(52		)	(149		)	(217		)
Gain (loss) on long-term U.K. natural gas contracts	(62		)	58			(56		)	93
Gain on foreign currency derivative instruments(a)	74			—			74			—
Loss on early extinguishment of debt	(7		)	—			(9		)	—
U.K. tax legislation	—			21			—			21
Discontinued operations	—			—			8			277
Net income	$	1,021		$	1,623		$	3,288		$	4,155

(a)Represents unrealized gains in the third quarter of 2007 on foreign currency derivative instruments entered to limit Marathon’s exposure to changes in the Canadian dollar exchange rate related to the cash portion of the purchase price for Western Oil Sands Inc. See Note 19.

8. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Third Quarter Ended September 30,
	Pension Benefits						Other Benefits
*(In millions)*	2007			2006			2007			2006
Service cost	$	35		$	33		$	6		$	6
Interest cost	36			33			11			10
Expected return on plan assets	(38		)	(30		)	—			—
Amortization:
— prior service cost (credit)	3			2			(2		)	(3		)
— actuarial loss	9			9			2			3
Multi-employer and other plans	—			—			1			—
Net periodic benefit cost	$	45		$	47		$	18		$	16

	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
*(In millions)*	2007			2006			2007			2006
Service cost	$	105		$	99		$	17		$	18
Interest cost	107			96			33			31
Expected return on plan assets	(115		)	(85		)	—			—
Amortization:
— prior service cost (credit)	10			4			(7		)	(9		)
— actuarial loss	27			33			6			7
Multi-employer and other plans	1			1			2			2
Net periodic benefit cost	$	135		$	148		$	51		$	49

During the first nine months of 2007, Marathon made contributions of $80 million to its funded pension plans, including $50 million related to international plans. Marathon expects to make additional contributions of approximately $5 million to its funded pension plans over the remainder of 2007. Contributions made from the general assets of Marathon to cover current benefit payments related to unfunded pension and other postretirement benefit plans were $12 million and $26 million during the first nine months of 2007.

9. Income Taxes

The provision for income taxes for interim periods is based on management’s best estimate of the effective income tax rate expected to be applicable for the current year plus any adjustments arising from a change in the estimated amount of taxes related to prior periods. The following is an analysis of the effective income tax rates for continuing operations for the periods presented:

	Third Quarter Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Statutory U.S. income tax rate	35.0	%	35.0	%	35.0	%	35.0	%
Effects of foreign operations, including foreign tax credits	6.9		9.2		8.5		9.9
State and local income taxes, net of federal income tax effects	1.5		2.9		1.9		2.3
Other tax effects	(1.8	)	(2.1	)	(1.4	)	(1.3	)
Effective income tax rate for continuing operations	41.6	%	45.0	%	44.0	%	45.9	%

As of January 1, 2007, total unrecognized tax benefits were $48 million. If these amounts were recognized, $30 million would affect Marathon’s effective income tax rate. There are no uncertain income tax positions as of January 1, 2007 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly increase or decrease during 2007.

Marathon is continuously undergoing examination of its U.S. federal income tax returns by the Internal Revenue Service. Such audits have been completed through the 2003 tax year. The audit of the 2004 and 2005 U.S. federal income tax returns commenced in May 2006 and is ongoing. Marathon believes it has made adequate provision for federal income taxes and interest which may become payable for years not yet settled. Further, Marathon is routinely involved in U.S. state and local income tax audits and foreign jurisdiction tax audits. As of September 30, 2007, Marathon’s income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States(a)		1999 - 2006
Equatorial Guinea		2004 - 2006
Libya		2006
United Kingdom		2005 - 2006

(a) Includes federal, state and local jurisdictions.

In connection with the adoption of FIN No. 48, Marathon changed the presentation of interest and penalties related to income taxes in the consolidated statement of income. Effective January 1, 2007, such interest and penalties are prospectively recorded as part of the provision for income taxes. Prior to January 1, 2007, Marathon recorded such interest as part of net interest and other financing costs and such penalties as selling, general and administrative expenses. As of January 1, 2007, $17 million of interest and penalties was accrued related to income taxes.

10. Comprehensive Income

The following sets forth Marathon’s comprehensive income for the periods indicated:

	Third Quarter Ended September 30,					Nine Months Ended September 30,
*(In millions)*	2007		2006			2007			2006
Net income	$	1,021	$	1,623		$	3,288		$	4,155
Other comprehensive income, net of taxes:
Minimum pension liability adjustments	—		23			—			38
Defined benefit postretirement plans(a)	7		—			(29		)	—
Other	10		(3		)	12			1
Comprehensive income	$	1,038	$	1,643		$	3,271		$	4,194

(a) During the first nine months of 2007, changes were made to the estimates used to measure certain assumptions necessary for determining the funded status of Marathon’s defined benefit postretirement plans as of December 31, 2006.

11. Inventories

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

*(In millions)*	September 30, 2007		December 31, 2006
Liquid hydrocarbons and natural gas	$	2,153	$	1,136
Refined products and merchandise	2,210		1,812
Supplies and sundry items	241		225
Total, at cost	$	4,604	$	3,173

12. Property, Plant and Equipment

Exploratory well costs capitalized greater than one year after completion of drilling as of September 30, 2007 were $146 million, including $26 million added to this category in the third quarter of 2007 for the Stones prospect in the Gulf of Mexico, where drilling is scheduled to recommence in late 2007, and $24 million added to this category in the second quarter of 2007 for the Gudrun appraisal well offshore Norway, where Marathon and its partners are evaluating development scenarios with development concept selection expected in 2008.

13. Long-term Debt

On September 27, 2007, Marathon issued $750 million aggregate principal amount of senior notes bearing interest at 6.000 percent with a maturity date of October 1, 2017, and $750 million aggregate principal amount of senior notes bearing interest at 6.600 percent with a maturity date of October 1, 2037. Interest on the senior notes is payable semi-annually beginning April 1, 2008.

On June 26, 2007, the Parish of St. John the Baptist, where Marathon’s Garyville, Louisiana, refinery is located, issued $1.0 billion of 5.125 percent Fixed Rate Revenue Bonds (Marathon Oil Corporation Project) Series 2007A associated with the Garyville refinery expansion with a maturity date of June 1, 2037. Marathon is solely obligated to service the principal and interest payments associated with the bonds. The proceeds from the bonds were trusteed to be disbursed to Marathon upon its request for reimbursement of expenditures related to the Garyville refinery expansion. Through September 30, 2007, such reimbursements have totaled $163 million. The $1.0 billion obligation is reflected as long-term debt and the $848 million of trusteed funds, including interest income earned to date, is reflected as other noncurrent assets in the consolidated balance sheet as of September 30, 2007.

On June 15, 2007, Marathon borrowed $578 million under a loan agreement from Eksportfinans ASA, the Norwegian export credit agency, based upon the amount of qualifying purchases of goods and services by Marathon from Norwegian contractors. The original loan agreement that was executed in 2006 was amended in June 2007 to provide for an increase in borrowing capacity from $525 million to $578 million. The term of the loan is 8.5 years with semi-annual principal and interest payments beginning December 15, 2007, and the loan bears a fixed interest rate of 4.550 percent. The loan also requires additional credit security support in the form of letters of credit or guarantees.

Effective May 7, 2007, Marathon entered into an amendment to its $2.0 billion revolving credit agreement, extending the termination date from May 2011 to May 2012. At September 30, 2007, there were no borrowings against this facility. On October 4, 2007, Marathon entered into an amendment to increase the size of this revolving credit agreement to $3.0 billion.

14. Stock-Based Compensation Plans

The following is a summary of stock option award activity for the first nine months of 2007:

	Number of Shares		Weighted Average Exercise Price
Outstanding at December 31, 2006	10,990,990		$	24.72
Granted	3,045,800		$	61.05
Exercised	(1,436,112	)	$	21.33
Canceled	(192,666	)	$	37.07
Outstanding at September 30, 2007(a)	12,408,012		$	33.81

(a) Of the stock option awards outstanding as of September 30, 2007, 3,007,200, 8,776,892 and 623,920 were outstanding under the 2007 Incentive Compensation Plan, the 2003 Incentive Compensation Plan and the 1990 Stock Plan, including 814,782 stock options with tandem stock appreciation rights.

15. Leases

As of September 30, 2007, Marathon’s future minimum commitments for operating lease obligations having remaining noncancelable lease terms in excess of one year were as follows:

*(In millions)*
2007	$	57
2008	216
2009	169
2010	122
2011	84
Later years	674
Sublease rentals	(26		)
Total minimum lease payments	$	1,296

As of December 31, 2006, total minimum lease commitments for operating leases were $851 million. The majority of the increase during the first nine months of 2007 relates to a long-term lease of barges.

16. Commitments and Contingencies

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. 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. Certain of the Company’s commitments are discussed below.

Guarantees — During the third quarter of 2007, Marathon entered an agreement, which terminates December 31, 2009, with its partners in LOOP LLC (“LOOP”) under which each partner will contribute cash in lieu of LOOP procuring separate insurance for certain catastrophic events. If such an event occurs, each partner is to contribute cash in proportion to its ownership interest. Marathon’s maximum potential undiscounted payments under this agreement are $101 million.

Contract commitments — At September 30, 2007 and December 31, 2006, Marathon’s contract commitments to acquire property, plant and equipment totaled $2.459 billion and $1.703 billion. During the first nine months of 2007, the majority of additional contract commitments were related to the expansion of the Company’s Garyville, Louisiana, refinery.

17. Share Repurchase Program

In January 2006, Marathon’s Board of Directors authorized the repurchase of up to $2 billion of common stock. The share repurchase program was extended by $500 million in January 2007, by an additional $500 million in May 2007, and by $2 billion in July 2007, for a total authorized program of $5 billion. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. The Company will use cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon the Company’s financial condition or changes in market conditions and is subject to termination prior to completion. The repurchase program does not include specific price targets or timetables. As of September 30, 2007, the Company had acquired 57 million common shares at a cost of $2.497 billion under the program, including 16 million common shares acquired during the first nine months of 2007 at a cost of $800 million.

18. Supplemental Cash Flow Information

	Nine Months Ended September 30,
*(In millions)*	2007			2006
Net cash provided from operating activities included:
Interest paid (net of amounts capitalized)	$	66		$	109
Income taxes paid to taxing authorities	2,711			3,209

Noncash effect of deconsolidation of EGHoldings:
Decrease in non-cash assets	$	1,759		$	—
Equity method investment recorded	942			—
Decrease in liabilities	310			—
Elimination of minority interests	544			—

Noncash investing and financing activities:
Bond obligation assumed for trusteed funds	$	1,000		$	—

Commercial paper and revolving credit arrangements, net:
Borrowings	$	1,920		$	1,321
Repayments	(1,920		)	(1,321		)

19. Subsequent Event

On October 18, 2007, Marathon completed the acquisition of all the outstanding shares of Western Oil Sands Inc. (“Western”) for cash and securities of approximately $5.8 billion. Western shareholders received cash of 3.808 billion Canadian dollars and 34.3 million shares of Marathon common stock or securities exchangeable for Marathon common stock. Western’s outstanding debt was approximately $1.1 billion at closing. The acquisition will be accounted for under the purchase method of accounting and, as such, Marathon’s results of operations will include Western’s results from October 18, 2007. Western’s oil sands mining operations will be reported as a separate segment and its exploration and production operations will be included in the E&P segment beginning in the fourth quarter of 2007.

20. Accounting Standards Not Yet Adopted

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

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

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

Marathon Oil Corporation is engaged in worldwide exploration, production and marketing of crude oil and natural gas; oil sands mining in Canada; domestic refining, marketing and transportation of crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and worldwide marketing and transportation of products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, and development of other projects to link stranded natural gas resources with key demand areas. Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Consolidated Financial Statements and Selected Notes to Consolidated Financial Statements, the Supplemental Statistics and our 2006 Annual Report on Form 10-K.

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2006 Annual Report on Form 10-K and in Part II of this Quarterly Report on Form 10-Q.

Marathon holds a 60 percent interest in Equatorial Guinea LNG Holdings Limited (“EGHoldings”). The remaining interests are held by Sociedad Nacional de Gas de Guinea Equatorial (“SONAGAS”) (25 percent interest), Mitsui & Co., Ltd. (8.5 percent interest) and a subsidiary of Marubeni Corporation (6.5 percent interest). As discussed in Note 3 to the accompanying consolidated financial statements, effective May 1, 2007, we no longer consolidate EGHoldings. Our investment is accounted for prospectively using the equity method of accounting. Amounts presented for the Integrated Gas segment for periods prior to May 1, 2007 include amounts related to the minority interests, unless specifically noted as being after minority interests.

Overview and Outlook

Operational and Corporate Highlights

During the first nine months of 2007 and through the date of this Report, we:

• Announced the results of the Droshky discovery and two appraisal sidetrack wells in the Gulf of Mexico;

• Announced seven exploration discoveries in deepwater Angola;

• Were the high bidder on 27 blocks in the Gulf of Mexico in the U.S. Minerals Management Service lease sale;

• Signed an agreement to carry out a study of the Dnieper-Donets Basin located in north central Ukraine;

• Continued to progress the Neptune development in deepwater Gulf of Mexico and the Alvheim/Vilje project offshore Norway;

• Acquired Western Oil Sands Inc. (“Western”);

• Commenced construction of the Garyville, Louisiana, refinery expansion;

• Approved a projected $1.9 billion heavy oil upgrading and expansion project at the Detroit, Michigan, refinery;

• Continued construction of the joint venture ethanol facility in Greenville, Ohio, and acquired a 35 percent interest in an entity that owns and operates an ethanol facility in Clymers, Indiana;

• Commenced production at the Equatorial Guinea LNG production facility;

• Repurchased 16 million common shares, bringing total repurchases to date to 57 million common shares at a cost of $2.497 billion;

• Increased our quarterly dividend per share by 20 percent; and

• Completed a two-for-one split of our common stock.

Exploration and Production (“E&P”)

Net liquid hydrocarbon and natural gas sales during the third quarter and first nine months of 2007 averaged 371 and 350 thousand barrels of oil equivalent per day (“mboepd”).

During the first nine months of 2007, we announced the Droshky discovery well and the results of two appraisal sidetrack wells. The discovery is located on Green Canyon Block 244 in the Gulf of Mexico (previously named Troika Deep). The timing of initial production from Droshky will be dependent upon delivery of key equipment (i.e., drilling rig and subsea equipment) and regulatory approvals, but could be as early as 2010. We hold a 100 percent working interest in the Droshky discovery.

During the first nine months of 2007, we also announced seven exploration successes in deepwater Angola. The Caril, Manjericao, Cominhos, Louro and Colorau discovery wells are located on Block 32, where we hold a 30 percent outside-operated interest, and the Miranda and Cordelia discovery wells are located on Block 31, where we hold a 10 percent outside-operated interest. These discoveries move both deepwater Angola blocks closer toward establishment of commercial developments. We have also participated in two wells that have reached total depth, the results of which will be announced upon approval of the Angola government and our partners.

The Neptune development in the Gulf of Mexico continues to progress and first production remains on schedule for early 2008.

In Norway, the commissioning of the Alvheim floating production, storage and offloading (“FPSO”) vessel continues. All subsea infrastructure is in place, three wells are ready for production and electrical testing is underway. The FPSO is expected to sail from Haugesund, Norway in December 2007 with first production, dependent on weather, now anticipated in the first quarter of 2008. Difficult market conditions for skilled labor combined with additional system integration and code compliance work delayed expected first production. These factors, together with additional drilling activity, have contributed to increased overall costs for the project.

We now expect 2007 production available for sale, excluding any contribution from our Canadian oil sands operations discussed below under Western Acquisition, to be approximately 350 mboepd. This is at the lower end of previous estimates due to operational interruptions at the LNG production facility in Equatorial Guinea discussed below under Integrated Gas and the delays in first production at Alvheim. Sales volumes may vary from production available for sale due to the timing of liquid hydrocarbon liftings and natural gas sales.

In October 2007, we were the high bidder on 27 blocks offered in the federal Outer Continental Shelf Lease Sale No. 205 conducted by the U.S. Minerals Management Service (“MMS”). Representing a total net investment of $222 million, 13 blocks were bid 100 percent by Marathon and the remaining 14 blocks were bid in conjunction with partners. The MMS is expected to rule on the award of these leases in 2007 or early 2008. Our plans call for initial drilling on some of these leases in 2009 or 2010, when a new rig is scheduled for delivery. The contract for the rig has an initial term of two years with an option to extend for an additional two years.

The above discussion includes forward-looking statements with respect to the possibility of developing the Droshky discovery in the Gulf of Mexico and Blocks 31 and 32 offshore Angola, the Neptune and the Alvheim/Vilje development projects, the timing and levels of our worldwide liquid hydrocarbon, natural gas, and condensate production available for sale and anticipated future exploratory drilling activity. Some factors that could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. Except for the Alvheim/Vilje and Neptune developments, the foregoing forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals and permits. The possible developments of Droshky and Blocks 31 and 32 could further be affected by presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. Worldwide production available for sale could also be affected by the occurrence of acquisitions or dispositions of oil and gas properties. 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 (“RM&T”)

Crude oil throughput was one percent and four percent higher in the third quarter and first nine months of 2007 compared to the same periods in 2006 and we expect crude oil throughput for the full year 2007 to exceed the record level we set in 2006. Our total refinery throughput was down slightly in the third quarter of 2007 compared to the same period of 2006 primarily as a result of planned turnarounds underway at the end of the third quarter of 2007 at our

Catlettsburg, Kentucky and St. Paul Park, Minnesota refineries. Total refinery throughput for the first nine months of 2007 was two percent higher than the same period of 2006. Our refining and wholesale marketing gross margin averaged 17.17 cents per gallon and 23.17 cents per gallon in the third quarter and first nine months of 2007 compared to 32.71 cents per gallon and 24.78 cents per gallon in the comparable periods of 2006. The declines in both periods are primarily due to crude oil prices, which increased significantly during the third quarter of 2007 while falling substantially during the third quarter of 2006. For example, the average Light Louisiana Sweet crude oil price increased over $6 per barrel in the third quarter of 2007 compared to a decline of $12 per barrel in the same quarter of 2006. Favorably impacting our refining and wholesale marketing gross margin per gallon for the first nine months of 2007 was the change in accounting for matching buy/sell arrangements effective April 1, 2006, as the sales volumes recognized in the first nine months of 2007 were less than the volumes that would have been recognized under previous accounting practices. Our ethanol blending program increased to 41 thousand barrels per day (“mbpd”) in the third quarter of 2007 from 36 mbpd in the third quarter of 2006. The future expansion or contraction of our ethanol blending program will be driven by the economics of the ethanol supply and government regulations.

Speedway SuperAmerica LLC (“SSA”) increased same store merchandise sales three percent and same store gasoline sales volumes two percent when compared to the third quarter of 2006. SSA’s merchandise gross margin was higher while the gasoline and distillates gross margin per gallon was lower in the third quarter and first nine months of 2007 than in the comparable periods of 2006.

Construction of the Garyville, Louisiana refinery expansion continues on schedule. Site preparation, piling and initial foundation work is progressing to support process unit construction over the next two years.

In October 2007, we approved a projected $1.9 billion heavy oil upgrading and expansion project at our Detroit, Michigan refinery. This project will enable the refinery to process additional heavy, sour crude oils, including Canadian bitumen blends, and will increase its crude oil refining capacity by about 15 percent. The project is subject to obtaining necessary environmental permits and is expected to be completed in late 2010.

Also in October 2007, we acquired a 35 percent interest in an entity which owns and operates a 110-million-gallon-per-year ethanol plant in Clymers, Indiana. The plant began production in May 2007. With this acquisition, we further enhance our strategic ethanol production partnership with The Andersons, Inc. by participating in two facilities, including the Greenville, Ohio plant that is under construction and on target to be operational in the first quarter of 2008.

We have also continued our investment in supply and transportation infrastructure, including the October 2007 agreement to purchase four terminals in Ohio and an ownership interest in a pipeline. The purchase will increase our flexibility in supplying transportation fuels to the Midwest. The transaction is expected to close by the end of the first quarter of 2008, pending completion of various pre-closing activities.

The above discussion includes forward-looking statements with respect to projections of crude oil throughput and ethanol blending that could be affected by planned and unplanned refinery maintenance projects, the levels of refining and wholesale marketing gross margin, other operating considerations and government regulations. The above discussion also contains forward-looking information with respect to the Garyville and Detroit refinery expansion projects and the operational date of an ethanol production facility. Factors that could affect those projects include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, necessary government and third-party approvals, and other risks customarily associated with construction projects. The purchase of four terminals and an interest in a pipeline is subject to customary closing conditions and may be affected by the inability or delay in obtaining necessary regulatory approvals and other operating and economic considerations. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas (“IG”)

The LNG production facility in Equatorial Guinea was completed and delivered its first cargo of LNG in May 2007. As scheduled, the production facility was shutdown in June 2007 for a performance test which confirmed the facility’s capacity of 3.7 million metric tonnes per annum and again in July for commissioning maintenance. The facility returned to production later that month for the remainder of the third quarter and produced LNG at a rate of 93 percent of design capacity for the quarter. Following the detection of a minor leak, the facility was shut down on October 4, 2007. Warranty repairs have commenced and LNG production is expected to resume between mid-November and early December 2007.

Once the LNG production facility commenced its primary operations and began to generate revenue in May 2007, EGHoldings was no longer a variable interest entity. Effective May 1, 2007, we no longer consolidate EGHoldings, despite the fact that we hold majority ownership, because the minority shareholders have rights limiting our ability to

exercise control over the entity. Our investment in EGHoldings is accounted for prospectively using the equity method of accounting.

Together with our project partners, we have completed those portions of the front-end engineering and design for a potential second LNG production facility on Bioko Island, Equatorial Guinea, that are required to support the near-term efforts for this project. We expect an investment decision in 2008.

The above discussion contains forward-looking statements with respect to the resumption of operations at the LNG production facility in Equatorial Guinea and the possible expansion of the LNG production facility. The anticipated operational date of the LNG production facility is based on certain factors, including equipment availability and customs approval. Factors that could potentially affect the possible expansion of the facility and the development of additional LNG capacity through additional projects include partner approvals, access to sufficient natural gas volumes through exploration or commercial negotiations with other resource owners and access to sufficient regasification capacity. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Western Acquisition

On October 18, 2007, we completed the acquisition of all the outstanding shares of Western for cash and securities of approximately $5.8 billion. Western shareholders received cash of 3.808 billion Canadian dollars and 34.3 million shares of Marathon common stock or securities exchangeable for Marathon common stock. Western’s outstanding debt was approximately $1.1 billion at closing. The acquisition will be accounted for under the purchase method of accounting and, as such, Marathon’s results of operations will include Western’s results from October 18, 2007.

Western’s primary asset is a 20 percent outside-operated interest in the Athabasca Oil Sands Project (“AOSP”), which includes the operating Muskeg River Mine and the Scotford Upgrader, located in the province of Alberta, Canada. Western’s current net bitumen production from the Muskeg River Mine is approximately 31 mbpd. The bitumen production from the Muskeg River Mine is taken by pipeline to the Scotford Upgrader, which uses hydro-conversion technology to upgrade the bitumen into a range of high-quality, synthetic crude oils. A key attribute of this proposed acquisition is the ability to link future production from the AOSP developments with heavy oil upgrade projects at our refineries. Western’s oil sands mining operations will be reported as a separate segment beginning in the fourth quarter of 2007.

Western also holds ownership interests in both operated and non-operated in-situ oil leases, including a 60 percent operated interest in a 26,000 gross acre project, a 100 percent operated interest in a 13,000 gross acre project, a 20 percent outside-operated interest in a 75,000 gross acre project and a 33 percent outside-operated interest in a 19,000 gross acre project. The results of these exploration and production operations will be included in the E&P segment.

The above discussion contains forward-looking statements concerning the strategy to link oil sands production with heavy oil upgrade projects at our refineries. This forward-looking information may prove to be inaccurate and actual results may differ materially from those presently anticipated. Factors that could affect the potential heavy oil refining upgrading projects include transportation logistics, availability of materials and labor, inability or delay in obtaining necessary government and third-party approvals, and other risks customarily associated with construction projects.

Capital, Investment and Exploration Budget

We have increased our capital, investment and exploration budget for 2007, excluding major acquisitions, from our original estimate of $4.242 billion to $5.198 billion, which includes budgeted capital expenditures of $4.861 billion. Total E&P spending is projected to be $2.979 billion, an increase of $748 million. This increase is primarily related to an increase in the cost of the Alvheim/Vilje development, the net investment associated with the Gulf of Mexico lease sale discussed above and general inflationary pressures. RM&T spending is expected to increase by $193 million to $1.657 billion, largely due to acceleration of certain aspects of the Garyville refinery expansion, while the projected total cost for the Garyville expansion remains unchanged at $3.2 billion (excluding capitalized interest). Integrated gas spending is expected to be $240 million less than the original estimate of $331 million, reflecting EGHoldings being accounted for under the equity method upon start of production. Also contributing to the overall budget increase is the estimated capital spending of $194 million for oil sands mining activities as a result of the Western acquisition discussed above. Capitalized interest and corporate spending is expected to be $61 million higher than originally anticipated as a result of the delay of the Alvheim/Vilje project.

The forward-looking statements about our capital, investment and exploration budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to

differ materially include prices of and demand for crude oil, natural gas and refined products, actions of competitors, disruptions or interruptions of our production or refining operations due to the shortage of skilled labor and unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.

Corporate

On April 25, 2007, our Board of Directors declared a two-for-one split of our common stock. The stock split was effected in the form of a stock dividend distributed on June 18, 2007, to stockholders of record at the close of business on May 23, 2007. Stockholders received one additional share of our common stock for each share of common stock held as of the close of business on the record date. Common stock and per share (except par value) information for all periods presented has been restated throughout this Quarterly Report on Form 10-Q to reflect the stock split.

Critical Accounting Estimates

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

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

There have been no significant changes to our critical accounting estimates subsequent to December 31, 2006.

Management’s Discussion and Analysis of Results of Operations

Change in Accounting for Matching Buy/Sell Transactions

Matching buy/sell transactions arise from arrangements in which we agree to buy a specified quantity and quality of crude oil or refined product to be delivered to a specified location while simultaneously agreeing to sell a specified quantity and quality of the same commodity at a specified location to the same counterparty. Prior to April 1, 2006, all matching buy/sell transactions were recorded as separate sale and purchase transactions, or on a “gross” basis. Effective for contracts entered into or modified on or after April 1, 2006, the income effects of matching buy/sell transactions are reported in cost of revenues, or on a “net” basis, based on an accounting interpretation which clarified the circumstances under which a matching buy/sell transaction should be viewed as a single transaction involving the exchange of inventory. Transactions under contracts entered into before April 1, 2006 will continue to be reported on a “gross” basis. This accounting change had no effect on net income but the amounts of revenues and cost of revenues recognized after April 1, 2006 are less than the amounts that would have been recognized under previous accounting practices.

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

As a result, this accounting change impacts the comparability of revenues, cost of revenues and the refining and wholesale marketing gross margin per gallon for the first nine months of 2007 and 2006.

Consolidated Results of Operations

Revenues for the third quarters and first nine months of 2007 and 2006 are summarized by segment in the following table:

	Third Quarter Ended						Nine Months Ended
	September 30,						September 30,
*(In millions)*	2007			2006			2007			2006
E&P	$	2,447		$	2,265		$	6,437		$	7,081
RM&T	14,605			14,277			40,424			44,289
IG	64			30			188			130
Segment revenues	17,116			16,572			47,049			51,500
Elimination of intersegment revenues	(231		)	(201		)	(571		)	(593		)
Gain (loss) on long-term U.K. natural gas contracts	(123		)	121			(111		)	182
Total revenues	$	16,762		$	16,492		$	46,367		$	51,089
Items included in both revenues and costs and expenses:
Consumer excise taxes on petroleum products and merchandise	$	1,352		$	1,297		$	3,856		$	3,739
Matching crude oil and refined product buy/sell transactions:
E&P	—			—			—			16
RM&T	2			237			125			5,233
Total buy/sell transactions included in revenues	$	2		$	237		$	125		$	5,249

E&P segment revenues increased $182 million in the third quarter of 2007 from the comparable prior-year period, primarily as a result of increased crude oil and natural gas marketing activities and higher liquid hydrocarbon realizations. Partially offsetting the impact of these increases were declines in liquid hydrocarbon sales volumes and domestic natural gas sales volumes. Decreases in domestic liquid hydrocarbon and natural gas sales volumes primarily reflect normal production declines for our Gulf of Mexico and Permian Basin properties. The lower international liquid hydrocarbon sales volumes were due to 30,000 barrels of oil per day that were produced and sold in the third quarter of 2006 that were owed to our account upon our resumption of operations in Libya. Though it did not have a significant impact on E&P segment revenues, the increase in Equatorial Guinea natural gas sales volumes due to the start-up of the LNG production facility in the second quarter of 2007 contributed to the decline in the average international natural gas realization for the third quarter of 2007.

E&P segment revenues in the first nine months of 2007 decreased $644 million from the comparable prior-year period. Revenue decreases from natural gas marketing activities in the first quarter of 2007 account for a substantial portion of the decline for the nine-month period. The remainder of the decrease was primarily related to lower liquid hydrocarbon and natural gas sales volumes and realizations. Normal production rate declines, particularly for our Gulf of Mexico properties, caused domestic liquid hydrocarbon and natural gas sales volumes to decrease in the first nine months of 2007 compared to the same period of 2006, and the decline in Libya liquid hydrocarbon sales volumes for the third quarter discussed above caused the majority of the decrease in international liquid hydrocarbon sales volumes.

See Supplemental Statistics for information regarding net sales volumes and average realizations by geographic area.

Excluded from E&P segment revenues were losses of $123 million and gains of $121 million for the third quarters of 2007 and 2006, on long-term natural gas contracts in the United Kingdom which are accounted for as derivative instruments. For the first nine months of 2007 and 2006, losses of $111 million and gains of $182 million are excluded from E&P segment revenues. See Item 3. Quantitative and Qualitative Disclosures About Market Risk.

RM&T segment revenues increased $328 million in the third quarter of 2007 and decreased $3.865 billion in the first nine months of 2007 from the comparable prior-year periods. The change in accounting for matching buy/sell transactions effective April 1, 2006 is the primary reason for the revenue decrease in the nine-month period. Excluding matching buy/sell transactions, RM&T segment revenues increased in both periods. The third quarter increase was primarily the result of higher refined product selling prices while the increase for the nine-month period primarily reflected increased refined product selling prices and crude oil sales volumes.

For information on segment income, see Segment Results.

Cost of revenues increased $1.734 billion in the third quarter of 2007 and $1.644 billion in the first nine months of 2007 from the comparable prior-year periods. The increases in both periods are primarily in the RM&T segment and resulted mainly from higher acquisition costs for crude oil in the third quarter of 2007. Contributing to the cost increase were the higher market prices for crude oil, derivatives losses, a narrowing of the difference in the acquisition costs for sweet and sour crude oils, and the effects of refining more sweet crude oil.

Purchases related to matching buy/sell transactions decreased $220 million and $5.058 billion in the third quarter and first nine months of 2007 from the comparable prior-year periods as a result of the change in accounting for matching buy/sell transactions effective April 1, 2006, discussed above.

Exploration expenses were $88 million and $264 million in the third quarter and first nine months of 2007, including expenses related to dry wells of $22 million and $76 million primarily related to exploration activities in Angola. Exploration expenses were $97 million and $234 million in the third quarter and first nine months of 2006, including expenses related to dry wells and other write-offs of $41 million and $99 million. The largest increase in exploration expenses in the nine-month period related to geological and geophysical costs.

Gain on foreign currency derivative instruments in the third quarter of 2007 primarily represents unrealized gains on foreign currency derivative instruments entered to limit our exposure to changes in the Canadian dollar exchange rate related to the cash portion of the purchase price for Western. These derivative instruments were settled in connection with the closing of the Western acquisition and an additional pretax gain of $62 million will be recognized in the fourth quarter of 2007.

Provision for income taxes decreased $604 million and $718 million in the third quarter and first nine months of 2007 from the comparable periods of 2006 as a result of effective tax rate declines and decreases in income from continuing operations before income taxes in both periods. The following is an analysis of the effective income tax rates for continuing operations for the third quarters and first nine months of 2007 and 2006:

	Third Quarter Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Statutory U.S. income tax rate	35.0	%	35.0	%	35.0	%	35.0	%
Effects of foreign operations, including foreign tax credits	6.9		9.2		8.5		9.9
State and local income taxes, net of federal income tax effects	1.5		2.9		1.9		2.3
Other tax effects	(1.8	)	(2.1	)	(1.4	)	(1.3	)
Effective income tax rate for continuing operations	41.6	%	45.0	%	44.0	%	45.9	%

Discontinued operations in 2006 reflects the operations of our Russian oil exploration and production businesses and a $243 million after-tax gain related to the June 2006 disposal of these businesses. During the second quarter of 2007, adjustments to the sales price were substantially completed and an additional after-tax gain on the sale of $8 million was recognized. See Note 5 to the accompanying consolidated financial statements for additional information.

Segment Results

Segment income for the third quarters and first nine months of 2007 and 2006 is summarized in the following table.

	Third Quarter Ended							Nine Months Ended
	September 30,							September 30,
*(In millions)*	2007				2006			2007			2006
E&P
United States	$		147		$	218		$	470		$	706
International	332				354			794			990
E&P segment	479				572			1,264			1,696
RM&T	482				1,026			2,073			2,262
IG	52				(2		)	83			23
Segment income	1,013				1,596			3,420			3,981
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	3				(52		)	(149		)	(217		)
Gain (loss) on long-term U.K. natural gas contracts	(62			)	58			(56		)	93
Gain on foreign currency derivative instruments	74				—			74			—
Loss on early extinguishment of debt	(7			)	—			(9		)	—
U.K. tax legislation	—				21			—			21
Discontinued operations	—				—			8			277
Net income	$	1,021			$	1,623		$	3,288		$	4,155

United States E&P income decreased $71 million, or 33 percent, and $236 million, or 33 percent, in the third quarter and first nine months of 2007 compared to the same periods of 2006. Pretax income decreased $117 million and $393 million in the same periods while the effective income tax rate remained unchanged at 38 percent in the third quarter and decreased from 38 percent to 36 percent in the nine-month period. The lower pretax income in both periods is primarily a result of revenue decreases from lower liquid hydrocarbon and natural gas sales volumes, as discussed above.

International E&P income decreased $22 million, or 6 percent, and $196 million, or 20 percent, in the third quarter and first nine months of 2007 compared to the same periods of 2006. Pretax income decreased $76 million and $441 million in the same periods, while the effective income tax rate decreased from 59 percent to 58 percent in the third quarter and increased from 59 percent to 60 percent in the nine-month period. The lower pretax income in both periods is primarily a result of revenue decreases from lower liquid hydrocarbon sales volumes. In the third quarter of 2007, the impact of the sales volume decline was significantly offset by higher realized liquid hydrocarbon prices and lower exploration expenses.

RM&T segment income decreased by $544 million, or 53 percent, and $189 million, or 8 percent, in the third quarter and first nine months of 2007 compared to the same periods of 2006. Pretax income decreased $938 million and $432 million in the same periods, while the effective income tax rate decreased from 39 percent to 35 percent in the third quarter and from 39 percent to 36 percent in the nine-month period. The decreases in RM&T pretax income in both periods are primarily the result of a lower refining and wholesale marketing gross margin in the third quarter of 2007. The refining and wholesale marketing gross margin averaged 17.17 cents per gallon in the third quarter of 2007 and 23.17 cents per gallon in the first nine months of 2007 compared to 32.71 cents per gallon and 24.78 cents per gallon in the comparable periods of 2006. The most significant cause of this margin decline was that crude oil prices increased significantly during the third quarter of 2007 while crude oil prices fell substantially in the third quarter of 2006. Our cost of crude oil and other feedstocks increased in the third quarter of 2007 compared to the comparable prior-year quarter due to these higher crude prices, a narrowing of the difference in the acquisition costs for sweet and sour crude oils and the effects of refining more sweet crude oil. In addition, the increase in our wholesale sales price realizations was less than the increase in crude oil and other feedstock costs. Our refining and wholesale marketing gross margin also included derivative losses of $360 million in the third quarter of 2007 compared to derivative gains of $384 million in the third quarter of 2006. The change in the impact of derivatives primarily reflects the realized effects of closed derivative positions, but also includes the unrealized effects of marking open derivative positions to market. These derivatives have an underlying physical commodity transaction; however, the income effect related to the derivatives and the income effect related to the underlying physical transactions are not necessarily recognized in segment income in the same period because we do not attempt to qualify these commodity derivatives for hedge accounting.

Crude oil refined averaged 1,042 mbpd and 1,028 mbpd, during the third quarter and first nine months of 2007, 11 mbpd and 39 mbpd higher than the averages for the same periods of 2006.

IG segment income increased $54 million in the third quarter of 2007 and increased $60 million in the first nine months of 2007 compared to the same periods of 2006 due to increased income from our equity method investments in EGHoldings and Atlantic Methanol Production Company LLC (“AMPCO”). The first LNG deliveries from EGHoldings’ LNG production facility in Equatorial Guinea were made in the second quarter of 2007. Income from AMPCO for the third quarter of 2007 increased as the plant was shut down for a portion of the third quarter of 2006. Higher methanol prices in the first quarter of 2007 also contributed to the increase in income from AMPCO for the first nine months of 2007.

Management’s Discussion and Analysis of Cash Flows and Liquidity

Cash Flows

Net cash provided from operating activities totaled $2.951 billion in the first nine months of 2007, compared to $3.745 billion in the first nine months of 2006.

Net cash used in investing activities totaled $2.609 billion in the first nine months of 2007, compared to $1.852 billion in the first nine months of 2006. Capital expenditures were $2.725 billion compared with $2.405 billion for the comparable prior-year period, with the increased spending primarily related to the Garyville refinery expansion in the RM&T segment and the Neptune development in the E&P segment. See Supplemental Statistics for information regarding capital expenditures by segment. Investing activities for the first nine months of 2007 also included $163 million withdrawn from the trusteed proceeds of the revenue bonds associated with our Garyville, Louisiana refinery expansion. As discussed below, the proceeds from these bonds were held in trust at issuance and therefore were not reflected as a borrowing in the accompanying consolidated statement of cash flows for the first nine months of 2007. When the funds are released to us in reimbursement of expenditures associated with the expansion, the cash inflow is presented as part of investing activities. Investing activities for the first nine months of 2006 also included net cash proceeds of $832 million from the sale of our Russian oil exploration and production businesses in June 2006 and cash paid for acquisitions of $543 million, primarily related to the initial $520 million payment associated with our 2005 re-entry into Libya.

Net cash provided by financing activities was $333 million in the first nine months of 2007, compared to $1.726 billion used by financing activities in the first nine months of 2006. Significant uses of cash in financing activities during both periods included stock repurchases, repayments of maturing debt and dividend payments. Financing activities for the first nine months of 2007 included the issuance of $1.5 billion in senior notes and borrowings of $578 million from the Norwegian export credit agency.

Dividends to Stockholders

On October 31, 2007, our Board of Directors declared a dividend of 24 cents per share, payable December 10, 2007, to stockholders of record at the close of business on November 21, 2007.

Derivative Instruments

See Quantitative and Qualitative Disclosures About Market Risk for a 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 credit facilities and access to both the debt and equity capital markets. Our ability to access the debt capital market is supported by our investment grade credit ratings. Our senior unsecured debt is currently rated investment grade by Standard and Poor’s Corporation, Moody’s Investor Services, Inc. and Fitch Ratings, with ratings of BBB+, Baa1 and BBB+. These ratings were affirmed in July 2007 after the Western acquisition was announced. Because of the liquidity and capital resource alternatives available to us, including internally generated cash flow, we believe that our short-term and long-term liquidity is adequate to fund operations, including our capital spending programs, stock repurchase program, repayment of debt maturities and any amounts that may ultimately be paid in connection with contingencies.

We have a committed $3.0 billion revolving credit facility with third-party financial institutions terminating in May 2012. This facility was expanded from $2.0 billion on October 4, 2007. At September 30, 2007, there were no borrowings against this facility and we had no commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

On July 26, 2007, we filed a universal shelf registration statement with the Securities and Exchange Commission, under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

On September 27, 2007, Marathon issued $750 million aggregate principal amount of senior notes bearing interest at 6.0 percent with a maturity date of October 1, 2017, and $750 million aggregate principal amount of senior notes bearing interest at 6.6 percent with a maturity date of October 1, 2037. Interest on the senior notes is payable semi-annually beginning April 1, 2008. The $1.5 billion of proceeds were used to fund a portion of the purchase price for the Western acquisition.

On June 26, 2007, the Parish of St. John the Baptist, where our Garyville, Louisiana, refinery is located, issued $1.0 billion of 5.125 percent Fixed Rate Revenue Bonds (Marathon Oil Corporation Project) Series 2007A associated with the Garyville refinery expansion, with a maturity date of June 1, 2037. We are solely obligated to service the principal and interest payments associated with the bonds. The proceeds from the bonds were held in trust to be disbursed to us upon our request for reimbursement of expenditures related to the Garyville refinery expansion. Through September 30, 2007, such reimbursements have totaled $163 million. The $1.0 billion obligation is reflected as long-term debt and the $848 million of trusteed funds, including interest income earned to date, is reflected as other noncurrent assets in the consolidated balance sheet as of September 30, 2007.

On June 15, 2007, we borrowed $578 million under a loan agreement from Eksportfinans ASA, the Norwegian export credit agency, based upon the amount of qualifying purchases of goods and services by us from Norwegian contractors. The original loan agreement that was executed in 2006 was amended in June 2007 to provide for an increase in borrowing capacity from $525 million to $578 million. The term of the loan is 8.5 years with semi-annual principal and interest payments beginning December 15, 2007, and the loan bears a fixed interest rate of 4.55 percent. The loan also requires additional credit security support in the form of letters of credit or guarantees.

Our consolidated cash-adjusted debt-to-capital ratio (total debt-minus-cash and trusteed funds to total debt-plus-equity-minus-cash and trusteed funds) was 11 percent at September 30, 2007, compared to six percent at year-end 2006 as shown below. This includes $508 million of debt that is serviced by United States Steel Corporation (“United States Steel”).

*(Dollars in millions)*	September 30, 2007			December 31, 2006
Long-term debt due within one year	$	423		$	471
Long-term debt	5,678			3,061
Total debt	$	6,101		$	3,532

Cash	$	3,269		$	2,585
Trusteed funds from revenue bonds (a)	$	848		$	—
Equity	$	16,682		$	14,607

Calculation:
Total debt	$	6,101		$	3,532
Minus cash	3,269			2,585
Minus trusteed funds from revenue bonds	848			—
Total debt minus cash	1,984			947

Total debt	6,101			3,532
Plus equity	16,682			14,607
Minus cash	3,269			2,585
Minus trusteed funds from revenue bonds	848			—
Total debt plus equity minus cash	$	18,666		$	15,554

Cash-adjusted debt-to-capital ratio	11		%	6		%

(a)Following the issuance of the $1.0 billion of revenue bonds by the Parish of St. John the Baptist, the proceeds were trusteed and will be disbursed to us upon our request for reimbursement of expenditures related to the Garyville refinery expansion. The trusteed funds are reflected as other noncurrent assets in the accompanying consolidated balance sheet as of September 30, 2007.

On October 18, 2007, we completed the acquisition of Western as discussed in Overview and Outlook above. As part of this transaction, we paid Western shareholders cash of 3.808 billion Canadian dollars. These payments were funded from existing cash balances, proceeds from the senior notes discussed above and the issuance of commercial paper. At the closing date, Western’s outstanding debt totaled approximately $1.1 billion, primarily composed of (i) senior secured notes with a face value of $450 million and a fair value of $499 million, bearing interest at 8.375 percent with a maturity date of May 1, 2012 and (ii) an 805 million Canadian dollar secured revolving credit facility terminating June 21, 2012 with $514 million outstanding. Both the senior notes and the revolving credit facility are secured by Western’s interest

in the AOSP. At completion of the acquisition, we estimated our cash-adjusted debt-to-capital ratio in the mid-20 percent range.

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. Estimates may differ from actual results. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The cash-adjusted debt-to-capital ratio estimate is preliminary and therefore subject to change. Actual results may differ materially from the estimate.

Share Repurchase Program

Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion. As of September 30, 2007, we had repurchased 57 million common shares at a cost of $2.497 billion. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program’s authorization does not include specific price targets or timetables; however, we intend to complete the authorized purchases by the end of 2009. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales and cash from available borrowings.

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

Contractual Cash Obligations

As of September 30, 2007, our consolidated contractual cash obligations have increased by $4.367 billion from December 31, 2006. Long-term debt increased by $2.552 billion due to the senior notes, revenue bonds and Norwegian borrowings discussed above, net of debt repayments. Commitments under service and materials contracts increased $746 million due to contracts entered for drilling rigs in the continental United States and in the Gulf of Mexico. Contractual commitments to acquire property, plant and equipment increased $756 million, with the majority of additional contractual commitments related to the expansion of the Garyville, Louisiana refinery. There have been no other significant changes to our obligations to make future payments under existing contracts subsequent to December 31, 2006. 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, 2006.

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 our liquidity and capital resources. There have been no significant changes to our off-balance sheet arrangements subsequent to December 31, 2006.

Nonrecourse Indebtedness of Investees

Certain of our investees have incurred indebtedness that we do not support through guarantees or otherwise. If we were obligated to share in this debt on a pro rata ownership basis, our share would have been $381 million as of September 30, 2007. Of this amount, $198 million relates to Pilot Travel Centers LLC (“PTC”). If any of these investees default, we have no obligation to support the debt. Our partner in PTC has guaranteed $75 million of the total PTC debt.

Obligations Associated with the Separation of United States Steel

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. (See the discussion of the Separation in our 2006 Annual Report on Form 10-K.) 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, 2007, we have obligations totaling $546 million that have been assumed by United States Steel. Of this amount, obligations of $520 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet (current portion - $35 million; long-term portion - $485 million). The remaining $26 million was related to off-balance sheet arrangements and contingent liabilities 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 reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil, refined products and feedstocks.

Air

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

The U.S. Environmental Protection Agency (“EPA”) is in the process of implementing regulations to address current National Ambient Air Quality Standards (“NAAQS”) for fine particulate emissions and ozone. In connection with these standards, the EPA will designate certain areas as “nonattainment,” meaning that the air quality in such areas does not meet the NAAQS. To address these nonattainment areas, the EPA proposed a rule in 2004 called the Interstate Air Quality Rule (“IAQR”) that would require significant emissions reductions in numerous states. The final rule, promulgated in 2005, was renamed the Clean Air Interstate Rule (“CAIR”). While the EPA expects that states will meet their CAIR obligations by requiring emissions reductions from electric generating units, states will have the final say on what sources they regulate to meet attainment criteria. Our refinery operations are located in affected states and some of these states may choose to propose more stringent fuels requirements to meet the CAIR. Also, on July 11, 2007, the EPA proposed a revised ozone standard. Once the revised ozone standard is promulgated, the EPA will begin the multi-year process to develop the implementing rules required by the Clean Air Act. We cannot reasonably estimate the final financial impact of the state actions to implement the CAIR until the states have taken further action and we cannot reasonably estimate the final financial impact of the revised ozone standard until the implementing rules are established.

We now plan to spend approximately $350 million from 2006 through 2011 on refinery investments to produce ultra-low sulfur diesel fuel for off-road use, in compliance with previously disclosed EPA regulations that require reduced sulfur levels for diesel fuel. This is a forward looking statement. Some factors (among others) that could potentially affect diesel fuel compliance costs include completion of project detailed engineering, construction and start-up activities.

For information on legal proceedings related to environmental matters, see Part II, Item 1. Legal Proceedings.

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.

Accounting Standards Not Yet Adopted

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

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

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Management Opinion Concerning Derivative Instruments

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

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

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.

Our E&P segment primarily uses commodity derivative instruments selectively to protect against price decreases on portions of our future production when deemed advantageous to do so. We also use derivatives to protect the value of natural gas purchased and injected into storage in support of production operations. We use commodity derivative instruments to mitigate the price risk associated with the purchase and subsequent resale of natural gas on purchased volumes and anticipated sales volumes.

Our RM&T segment uses commodity derivative instruments:

• to mitigate the price risk:

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

• on fixed price contracts for ethanol purchases, and

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

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

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

• to protect against decreases in future crack spreads; and

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

Effective October 18, 2007, as a result of the acquisition of Western previously discussed, our oil sands mining segment uses commodity derivative instruments, such as put and call options, selectively to protect against price decreases on portions of our future production from the AOSP.

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

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

Commodity Price Risk

Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent changes in commodity prices for open commodity derivative instruments as of September 30, 2007 are provided in the following table:

	Incremental Decrease in IFO Assuming a Hypothetical Price Change of(a):
*(In millions)*	10%			25%
Commodity Derivative Instruments:(b)(c)
Crude oil(d)	$	204	(e)	$	509	(e)
Natural gas(d)	53		(e)	132		(e)
Refined products(d)	47		(e)	120		(e)

(a) We remain at risk for possible changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying physical commodity. Effects of these offsets are not reflected in the sensitivity analysis. Amounts reflect hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at September 30, 2007. Included in the natural gas impacts shown above are $58 million and $145 million related to the long-term U.K. natural gas contracts accounted for as derivative instruments for hypothetical price changes of 10 percent and 25 percent. We evaluate our portfolio of derivative commodity instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed continuously and master netting agreements are used when practical. Changes to the portfolio after September 30, 2007, would cause future IFO effects to differ from those presented in the table.

(b) The number of net open contracts for the E&P segment varied throughout the third quarter of 2007, from a low of 367 contracts on August 17, 2007, to a high of 899 contracts on September 30, 2007, and averaged 662 for the quarter. The number of net open contracts for the RM&T segment varied throughout the third quarter of 2007, from a low of 8,387 contracts on July 17, 2007 to a high of 31,872 contracts on September 24, 2007, and averaged 21,672 for the quarter. The derivative commodity instruments used and positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.

(c) The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated. Gains and losses on options are based on changes in intrinsic value only.

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

(e) Price increase.

E&P Segment

Derivative losses of $18 million and gains of $27 million were included in E&P segment income for the first nine months of 2007 and 2006, and were primarily related to derivatives utilized to protect the value of natural gas in storage and margins on natural gas purchases for resale. Excluded from E&P segment income were losses of $111 million and gains of $182 million for the first nine months of 2007 and 2006 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.

At September 30, 2007, we had no open derivative commodity contracts related to our oil and natural gas production, and therefore we remain exposed to market prices of commodities. We continue to evaluate the commodity price risks related to our production and may enter into derivative commodity instruments when it is deemed advantageous. As a particular but not exclusive example, we may elect to use commodity derivative instruments to achieve minimum price levels on some portion of our production to support capital or acquisition funding requirements.

RM&T Segment

We do not attempt to qualify commodity derivative instruments used in our RM&T operations for hedge accounting. As a result, we recognize in net income all changes in the fair value of derivatives used in our RM&T operations. Pretax derivative gains and losses included in RM&T segment income for the third quarters and first nine months of 2007 and 2006 are summarized in the following table:

	Third Quarter Ended September 30,						Nine Months Ended September 30,
*(In millions)*	2007			2006			2007			2006

Strategy:
Mitigate price risk	$	(203	)	$	180		$	(222	)	$	75
Protect carrying values of excess inventories	(161		)	208			(237		)	130
Protect margin on fixed price sales	1			(11		)	4			(1		)
Protect crack spread values	3			7			(17		)	2
Subtotal, non-trading activities	(360		)	384			(472		)	206

Trading activities	(2		)	2			2			—

Total net derivative gains (losses)	$	(362	)	$	386		$	(470	)	$	206

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

Oil Sands Mining Segment

We have not attempted to qualify commodity derivative instruments outstanding upon the acquisition of Western for hedge accounting. As a result, we will recognize in net income all changes in the fair value of those derivatives.

Western purchased put options at strike prices ranging from $50.00 to $55.00 per barrel, averaging $52.42 per barrel for the three-year period beginning January 1, 2007. The premiums for the purchased put options were partially offset through the sale of call options at strike prices ranging from $90.00 to $95.00 per barrel, averaging $92.41 per barrel for the three-year period beginning January 1, 2007, resulting in a net premium liability. Payment of the net premium liability is deferred until the settlement of the option contracts between 2007 and 2009. The counterparties to these put and call options have investment grade credit ratings, thereby partially mitigating the credit risk associated with these financial instruments.

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. For example, natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets, such as the New York Mercantile Exchange (“NYMEX”) contracts for natural gas that 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 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 change in interest rates as of September 30, 2007 is provided in the following table:

*(In millions)*	Fair Value			Incremental Change in Fair Value

Financial assets (liabilities):(a)
Receivable from United States Steel	$	504		$	10
Interest rate swap agreements	(11		)(b)	5		(c)
Long-term debt, including amounts due within one year	(6,085		)(b)	(329		)(c)

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

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

(c) For interest rate swap agreements, this assumes a 10 percent decrease in the September 30, 2007 effective swap rate. For long-term debt, this assumes a 10 percent decrease in the weighted average yield to maturity of our long-term debt at September 30, 2007.

At September 30, 2007, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to interest rate fluctuations. This sensitivity is illustrated by the $329 million increase in the fair value of long-term debt at September 30, 2007, assuming a hypothetical 10 percent decrease in interest rates. However, our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affect our results of operations and cash flows when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value.

We manage our exposure to interest rate movements by utilizing financial derivative instruments. The primary objective of this program is to reduce our overall cost of borrowing by managing the fixed and floating interest rate mix of the debt portfolio. We have entered into several interest rate swap agreements, designated as fair value hedges, which effectively resulted in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates. On June 1, 2007, $450 million notional amount of our interest rate swap agreements expired. There have been no other changes to the positions subsequent to December 31, 2006.

Foreign Currency Exchange Rate Risk

We manage our exposure to foreign currency exchange rates by utilizing forward and option contracts. The primary objective of this program is to reduce our exposure to movements in foreign currency exchange rates by locking in such rates. At September 30, 2007 the following currency derivatives were outstanding. All contracts currently qualify for hedge accounting unless noted.

*(In millions)*	Period	Notional Amount		Forward Rate(a)		Fair Value(b)
Foreign Currency Forwards:
Dollar (Canada)	December 2007	$	51	0.99343	(c)	$	3
Euro	October 2007 - November 2008	$	40	1.42615	(d)	$	4
Kroner (Norway)	October 2007 - October 2009	$	75	5.44450	(c)	$	9

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

(b) Fair value was based on market rates.

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

*(In millions)*	Period	Notional Amount		Weighted Average Exercise Price(a)		Fair Value(b)
Foreign Currency Rate Options:
Dollar (Canada) (c)	November 2007	$	3,379	1.0358	(d)	$	147
Kroner (Norway)	October 2007 - December 2007	$	50	5.9496	(d)	$	5

(a) Rates shown are the weighted average exercise prices for the period.

(b) Fair value was based on market prices.

(c) Subsequent to September 30, 2007, Marathon converted the Canadian dollar options to forwards in the amount of 3.5 billion Canadian dollars which settled on October 17, 2007. An additional gain of $62 million related to these options and forwards will be recognized in the fourth quarter of 2007.

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

The aggregate cash flow effect on foreign currency contracts of a hypothetical 10 percent change to exchange rates at September 30, 2007, would be approximately $12 million.

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 Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our 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, 2007, there were no changes in our internal controls over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal controls over financial reporting.

Marathon reviews and modifies its financial and operational controls on an ongoing basis to ensure that those controls are adequate to address changes in its business as it evolves. Marathon believes that its existing financial and operational controls and procedures are adequate.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Third Quarter						Nine Months
	Ended September 30,						Ended September 30,
*(Dollars in millions, except as noted)*	2007			2006			2007			2006
SEGMENT INCOME
Exploration and Production
United States	$	147		$	218		$	470		$	706
International	332			354			794			990
E&P segment	479			572			1,264			1,696
Refining, Marketing and Transportation	482			1,026			2,073			2,262
Integrated Gas	52			(2		)	83			23
Segment income	1,013			1,596			3,420			3,981
Items not allocated to segments, net of income taxes
Corporate and other unallocated items	3			(52		)	(149		)	(217		)
Gain (loss) on long-term U.K. natural gas contracts	(62		)	58			(56		)	93
Gain on foreign currency derivative instruments	74			—			74			—
Loss on early extinguishment of debt	(7		)	—			(9		)	—
U.K. tax legislation	—			21			—			21
Discontinued operations	—			—			8			277
Net income	$	1,021		$	1,623		$	3,288		$	4,155

CAPITAL EXPENDITURES
Exploration and Production	$	582		$	795		$	1,623		$	1,616
Refining, Marketing and Transportation	430			223			981			527
Integrated Gas(a)	2			72			93			236
Discontinued Operations	—			—			—			45
Corporate	12			7			28			26
Total	$	1,026		$	1,097		$	2,725		$	2,450

EXPLORATION EXPENSES
United States	$	53		$	40		$	137		$	109
International	35			57			127			125
Total	$	88		$	97		$	264		$	234

E&P OPERATING STATISTICS
Net Liquid Hydrocarbon Sales (mbpd)(b)
United States	63			72			66			77
Europe	33			29			33			35
Africa	103			141			100			116
Total International	136			170			133			151
Worldwide Continuing Operations	199			242			199			228
Discontinued Operations	—			—			—			16
Worldwide	199			242			199			244
Net Natural Gas Sales (mmcfd)(b)(c)
United States	464			522			478			536
Europe	195			141			206			237
Africa	372			56			221			65
Total International	567			197			427			302
Worldwide	1,031			719			905			838
Total Worldwide Sales (mboepd)
Continuing operations	371			362			350			368
Discontinued operations	—			—			—			16
Worldwide	371			362			350			384

(a) Through April 2007, includes EGHoldings at 100 percent. Effective May 1, 2007, Marathon no longer consolidates EGHoldings and its investment in EGHoldings is accounted for prospectively using the equity method of accounting; therefore, EGHoldings’ capital expenditures subsequent to April 2007 are not included in Marathon’s capital expenditures.

(b) Amounts reflect sales after royalties, except for Ireland where amounts are before royalties.

(c) Includes natural gas acquired for injection and subsequent resale of 51 mmcfd and 36 mmcfd in the third quarters of 2007 and 2006, and 49 mmcfd and 45 mmcfd for the first nine months of 2007 and 2006.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Third Quarter				Nine Months
	Ended September 30,				Ended September 30,
*(Dollars in millions, except as noted)*	2007		2006		2007		2006
E&P OPERATING STATISTICS (continued)
Average Realizations (d)
Liquid Hydrocarbons (per bbl)
United States	$	63.53	$	60.37	$	55.83	$	56.38
Europe	73.19		66.19		63.80		65.64
Africa	69.48		63.64		60.57		61.71
Total International	70.37		64.07		61.37		62.63
Worldwide Continuing Operations	68.21		62.96		59.54		60.51
Discontinued Operations	—		—		—		38.38
Worldwide	$	68.21	$	62.96	$	59.54	$	59.02

Natural Gas (per mcf)
United States	$	5.14	$	5.62	$	5.74	$	5.89
Europe	6.47		5.65		5.95		6.83
Africa	0.25		0.24		0.25		0.25
Total International	2.38		4.10		3.01		5.41
Worldwide	$	3.63	$	5.21	$	4.45	$	5.72
RM&T OPERATING STATISTICS
Refinery Runs (mbpd)
Crude oil refined	1,042		1,031		1,028		989
Other charge and blend stocks	199		218		211		225
Total	1,241		1,249		1,239		1,214

Refined Product Yields (mbpd)
Gasoline	646		655		649		655
Distillates	358		336		352		316
Propane	24		24		24		23
Feedstocks and special products	111		121		118		118
Heavy fuel oil	27		21		25		23
Asphalt	93		106		87		94
Total	1,259		1,263		1,255		1,229

Refined Products Sales Volumes (mbpd)(e)(f)	1,440		1,434		1,403		1,437
Matching buy/sell volumes included in above(f)	—		2		—		32
Refining and wholesale marketing gross
Margin (per gallon)(g)	$	0.1717	$	0.3271	$	0.2317	$	0.2478

Speedway SuperAmerica
Retail outlets	1,637		1,635		—		—
Gasoline and distillate sales (millions of gallons)	892		867		2,520		2,459
Gasoline and distillate gross margin (per gallon)	$	0.1103	$	0.1410	$	0.1115	$	0.1168
Merchandise sales	$	752	$	729	$	2,110	$	2,029
Merchandise gross margin	$	191	$	178	$	533	$	497
IG OPERATING STATISTICS
Net Sales (metric tonnes per day)
LNG	6,137		1,001		3,117		1,068
Methanol	1,421		613		1,285		938

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

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

(f) As a result of the change in accounting for matching buy/sell arrangements on April 1, 2006, the reported sales volumes will be lower than the volumes determined under the previous accounting practices.

(g) Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation. As a result of the change in accounting for matching buy/sell transactions on April 1, 2006, the resulting per gallon statistic will be higher than the statistic that would have been calculated from amounts determined under previous accounting practices.

Part II — OTHER INFORMATION

Item 1. Legal Proceedings

Product Contamination Litigation

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

Wyoming Proceedings

In response to the Governor of Wyoming’s veto of a state agency adoption of a rule that would allow the State Department of Environmental Quality (“DEQ”) to regulate the quantity of coal bed methane water discharges, an activist group has sued in State Court to overturn the veto. In June 2007, Marathon and another producer filed a motion to intervene. The State DEQ has begun issuing renewal water discharge and other permits with stringent limits based on its agricultural use policy rather than upon any regulation. The permits could require more costly water treatment or injection. Marathon is appealing every permit issued in this way as unlawful.

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

MTBE Litigation

We are a defendant, along with many other companies with refining operations, in over 50 cases in 12 states alleging methyl tertiary-butyl ether (“MTBE”) contamination in groundwater. There have been two recent developments in these matters. The federal Second Circuit Court of Appeals ruled in two of the MTBE cases brought by the states of New Hampshire and California (Marathon was not a party in these cases.) that the cases had been improperly removed to federal court based upon federal officer jurisdiction. The parties are briefing to the court whether other grounds for federal jurisdiction exist. If federal jurisdiction is found to be not proper in these cases, the issue of federal jurisdiction may then be raised in all of the MTBE cases. If removal is found to be improper in any case, it would be returned to state court. Also, the state of New Jersey has recently sued Marathon and the other refiners. This is the only case Marathon is involved with which has a state as a plaintiff and it is the only case where natural resources damages are sought. We continue to defend all of these MTBE cases vigorously.

Other

Marathon resolved the enforcement action brought by the Minnesota Pollution Control Agency (“MPCA”) in 2007 regarding a release of catalyst from the fluid catalytic cracking unit at the St. Paul Park, Minnesota, refinery for a civil penalty of $60,000.

The United States Occupational, Safety, and Health Administration (“OSHA”) has announced a National Emphasis Program (“NEP”) where it plans to inspect most of the domestic oil refinery locations in 2007 and 2008. The inspections will focus on compliance with the OSHA Process Safety Management requirements. OSHA conducted an inspection at our Canton, Ohio, refinery in the second and third quarters of 2007. We expect some resulting enforcement action in the fourth quarter of 2007. The related monetary penalties are not expected to be a significant amount.

Item 1A. Risk Factors

Marathon is subject to various risks and uncertainties in the course of its business. See the discussion of such risks and uncertainties under Item 1A. Risk Factors in Marathon’s 2006 Annual Report on Form 10-K. In addition, the following risk factor should be considered:

There are various risks inherent with our acquisition of Western, including risks related to operations and profitability.

Our acquisition of Western involves various risks. In particular, we may have assumed unknown liabilities in the acquisition and we are subject to various operating risks inherent with producing Canadian oil sands. Also, we are operating in a high-cost environment for oil sands production and may not realize the anticipated financial returns from the acquisition. In addition, future changes in laws and regulations, such as royalty and tax regulations, may adversely affect us. For example, on October 25, 2007, the Government of the Province of Alberta announced a framework (the “Framework”) for a new royalty regime on oil sands production. The Framework contemplates increases to the base or start-up royalty rate (from 1 percent to up to 9 percent) and the net or post-payout royalty rate (from 25 percent to up to 40 percent) on oil sands production. The Framework is expected to take effect in January 2009 and will apply to existing oil sands projects. Although the Framework has not yet been formally enacted, its implementation in the manner presented by the Government of the Province of Alberta could have a negative impact on our Canadian oil sands operations and our anticipated financial returns from the acquisition.

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

ISSUER PURCHASES OF EQUITY SECURITIES

Period	(a) Total Number of Shares Purchased (a)(b)		(b) Average Price Paid per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(d)	(d) Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(d)
07/01/07 - 07/31/07	393,085		$60.06	381,500	$2,497,064,359
08/01/07 - 08/31/07	3,997		$50.32	—	$2,497,064,359
09/01/07 - 09/30/07	37,979	(c)	$54.18	—	$2,497,064,359
Total	435,061		$59.46	381,500

(a) 22,303 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.

(b) Under the terms of the transaction whereby Marathon acquired the minority interest in Marathon Petroleum Company LLC and other businesses from Ashland Inc., Marathon paid Ashland Inc. shareholders cash in lieu of issuing fractional shares of Marathon’s common stock to which such holders would otherwise be entitled. Marathon acquired five shares due to acquisition share exchanges and Ashland Inc. share transfers pending at the closing of the transaction.

(c) 31,253 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon.

(d) In January 2006, Marathon announced a $2 billion share repurchase program which was increased by an additional $500 million in both January and May 2007 and by an additional $2 billion in July 2007, for a total authorized program of $5 billion. As of September 30, 2007, 57 million split-adjusted common shares had been acquired at a cost of $2.497 billion, which includes transaction fees and commissions that are not reported in the table above.

Item 6. Exhibits

2.1		Amended and Restated Arrangement Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd., Western Oil Sands Inc. and WesternZagros Resources Inc., dated as of September 14, 2007 (incorporated by reference to Exhibit 2.7 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).

2.2		Amending Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd., Western Oil Sands Inc. and WesternZagros Resources Inc., dated as of October 15, 2007 (incorporated by reference to Exhibit 2.8 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).

2.3		Plan of Arrangement under Section 193 of the Business Corporations Act (Alberta) (incorporated by reference to Exhibit 2.9 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).

3.1		Restated Certificate of Incorporation of Marathon Oil Corporation (incorporated by reference to Exhibit 3.1 to Marathon Oil Corporation’s Form 8-K, filed on April 25, 2007).

3.2		By-laws of Marathon Oil Corporation (incorporated by reference to Exhibit 3.2 to Marathon Oil Corporation’s Form 8-K, filed on April 25, 2007).

3.3		Certificate of Designations of Special Voting Stock of Marathon Oil Corporation.

4.1		Amendment No. 3 dated as of October 4, 2007 to Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent.

10.1		Exchangeable Share Provisions of 1339971 Alberta Ltd (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).

10.2		Support Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd. and Marathon Canadian Oil Sands Holding Limited, dated as of October 18, 2007

10.3		Voting and Exchange Trust Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd., Marathon Canadian Oil Sands Holding Limited and Valiant Trust Company, dated as of October 18, 2007.

12.1		Computation of Ratio of Earnings to Fixed Charges

31.1		Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

31.2		Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

32.1		Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350

32.2		Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

SIGNATURES

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 thereunto duly authorized.

	MARATHON OIL CORPORATION


	By:	Michael K. Stewart
		Michael K. Stewart
		Vice President, Accounting and Controller

November 7, 2007