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