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 June 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 681,102,025 shares of Marathon Oil Corporation common stock outstanding as of July 31, 2007.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended June 30, 2007

INDEX

PART I - FINANCIAL INFORMATION

	Item 1.	Financial Statements:

		Consolidated Statements of Income (Unaudited)

		Consolidated Balance Sheets (Unaudited)

		Consolidated Statements of Cash Flows (Unaudited)

		Selected Notes to Consolidated Financial Statements (Unaudited)

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

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk

	Item 4.	Controls and Procedures

		Supplemental Statistics (Unaudited)

PART II - OTHER INFORMATION

	Item 1.	Legal Proceedings

	Item 1A.	Risk Factors

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

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

	Item 6.	Exhibits

		Signatures

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)

	Second Quarter Ended						Six Months Ended
	June 30,						June 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)	$	16,260		$	15,962		$	28,751		$	28,862
Revenues from matching buy/sell transactions	65			1,806			123			5,012
Sales to related parties	411			411			731			723
Income from equity method investments	117			97			224			189
Net gains on disposal of assets	7			5			18			16
Other income	27			9			42			27

Total revenues and other income	16,887			18,290			29,889			34,829
Costs and expenses:

Cost of revenues (excludes items below)	11,755			11,628			21,297			21,387
Purchases related to matching buy/sell transactions	84			1,750			145			4,983
Purchases from related parties	54			47			101			98
Consumer excise taxes	1,307			1,277			2,504			2,442
Depreciation, depletion and amortization	396			369			789			769
Selling, general and administrative expenses	327			308			614			595
Other taxes	93			91			191			188
Exploration expenses	115			66			176			137

Total costs and expenses	14,131			15,536			25,817			30,599

Income from operations	2,756			2,754			4,072			4,230

Net interest and other financing costs (income)	(20		)	(9		)	(39		)	14
Loss on early extinguishment of debt	1			—			3			—
Minority interests in loss of Equatorial Guinea
LNG Holdings Limited	(1		)	(2		)	(3		)	(5		)

Income from continuing operations before
income taxes	2,776			2,765			4,111			4,221

Provision for income taxes	1,234			1,281			1,852			1,966

Income from continuing operations	1,542			1,484			2,259			2,255

Discontinued operations	8			264			8			277

Net income	$	1,550		$	1,748		$	2,267		$	2,532

Per Share Data

Basic:
Income from continuing operations	$	2.26		$	2.05		$	3.29		$	3.11
Discontinued operations	$	0.01		$	0.37		$	0.01		$	0.38
Net income	$	2.27		$	2.42		$	3.30		$	3.49

Diluted:
Income from continuing operations	$	2.24		$	2.04		$	3.27		$	3.08
Discontinued operations	$	0.01		$	0.36		$	0.01		$	0.38
Net income	$	2.25		$	2.40		$	3.28		$	3.46

Dividends paid	$	0.24		$	0.20		$	0.44		$	0.36

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

	June 30,			December 31,
(Dollars in millions, except per share data)	2007			2006
Assets
Current assets:
Cash and cash equivalents	$	2,331		$	2,585
Receivables, less allowance for doubtful accounts of $3 and $3	4,744			4,114
Receivables from United States Steel	31			32
Receivables from related parties	92			63
Inventories	4,310			3,173
Other current assets	191			129

Total current assets	11,699			10,096

Equity method investments	2,583			1,539
Receivables from United States Steel	488			498
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $14,213 and $13,573	16,037			16,653
Goodwill	1,393			1,398
Intangible assets, less accumulated amortization of $83 and $75	176			180
Other noncurrent assets	1,229			467

Total assets	$	33,605		$	30,831
Liabilities
Current liabilities:
Accounts payable	$	6,684		$	5,586
Payable to United States Steel	—			13
Payables to related parties	38			264
Payroll and benefits payable	287			409
Accrued taxes	649			598
Deferred income taxes	641			631
Accrued interest	93			89
Long-term debt due within one year	421			471

Total current liabilities	8,813			8,061

Long-term debt	4,237			3,061
Deferred income taxes	1,935			1,897
Defined benefit postretirement plan obligations	1,341			1,245
Asset retirement obligations	1,078			1,044
Payable to United States Steel	6			7
Deferred credits and other liabilities	380			391

Total liabilities	17,790			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 – 54,427,392 and 40,161,340 shares	(2,364		)	(1,638		)
Additional paid-in capital	4,787			4,784
Retained earnings	13,058			11,093
Accumulated other comprehensive loss	(402		)	(368		)

Total stockholders' equity	15,815			14,607

Total liabilities and stockholders' equity	$	33,605		$	30,831

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended
	June 30,
(Dollars in millions)	2007			2006
*Increase (decrease) in cash and cash equivalents*

Operating activities:
Net income	$	2,267		$	2,532

Adjustments to reconcile net income to net cash provided from operating activities:
Loss on early extinguishment of debt	3			—
Income from discontinued operations	(8		)	(277		)
Deferred income taxes	122			134
Minority interests in loss of Equatorial Guinea LNG Holdings Limited	(3		)	(5		)
Depreciation, depletion and amortization	789			769
Pension and other postretirement benefits, net	20			(41		)
Exploratory dry well costs and unproved property impairments	75			69
Net gains on disposal of assets	(18		)	(16		)
Equity method investments, net	(78		)	(134		)
Changes in the fair value of long-term U.K. natural gas contracts	(12		)	(61		)
Changes in:
Current receivables	(639		)	(833		)
Inventories	(1,150		)	(777		)
Current accounts payable and accrued expenses	1,037			916
All other, net	(39		)	(46		)
Net cash provided from continuing operations	2,366			2,230
Net cash provided from discontinued operations	—			69
Net cash provided from operating activities	2,366			2,299

Investing activities:
Capital expenditures	(1,699		)	(1,308		)
Acquisitions	—			(543		)
Disposal of assets	48			49
Disposal of discontinued operations	—			832
Investments - loans and advances	(64		)	(2		)
Investments - repayments of loans and return of capital	34			146
Deconsolidation of Equatorial Guinea LNG Holdings Limited	(37		)	—
Investing activities of discontinued operations	—			(45		)
All other, net	(10		)	14
Net cash used in investing activities	(1,728		)	(857		)

Financing activities:
Borrowings	578			—
Debt issuance costs	(8		)	—
Debt repayments	(469		)	(303		)
Issuance of common stock	18			19
Purchases of common stock	(776		)	(554		)
Excess tax benefits from stock-based compensation arrangements	24			14
Dividends paid	(302		)	(265		)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited	39			41
Net cash used in financing activities	(896		)	(1,048		)

Effect of exchange rate changes on cash	4			15

Net increase (decrease) in cash and cash equivalents	(254		)	409

Cash and cash equivalents at beginning of period	2,585			2,617

Cash and cash equivalents at end of period	$	2,331		$	3,026

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 and is carried at the Company’s share of net assets plus loans and advances, which totaled $961 million as of June 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 share 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 applicable to discontinued operations were $74 million and $173 million for the second quarter and first six months of 2006. Pretax income from discontinued operations was $24 million and $45 million for the second quarter and first six 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.

	Second Quarter Ended June 30,
	2007				2006
(In millions, except per share data)	Basic		Diluted		Basic		Diluted

Income from continuing operations	$	1,542	$	1,542	$	1,484	$	1,484
Discontinued operations	8		8		264		264
Net income	$	1,550	$	1,550	$	1,748	$	1,748

Weighted average common shares outstanding	683		683		722		722
Effect of dilutive securities	—		6		—		6

Weighted average common shares, including dilutive effect	683		689		722		728

Per share:
Income from continuing operations	$	2.26	$	2.24	$	2.05	$	2.04
Discontinued operations	$	0.01	$	0.01	$	0.37	$	0.36
Net income	$	2.27	$	2.25	$	2.42	$	2.40

	Six Months Ended June 30,
	2007				2006
(In millions, except per share data)	Basic		Diluted		Basic		Diluted

Income from continuing operations	$	2,259	$	2,259	$	2,255	$	2,255
Discontinued operations	8		8		277		277
Net income	$	2,267	$	2,267	$	2,532	$	2,532

Weighted average common shares outstanding	686		686		726		726
Effect of dilutive securities	—		5		—		7

Weighted average common shares, including dilutive effect	686		691		726		733

Per share:
Income from continuing operations	$	3.29	$	3.27	$	3.11	$	3.08
Discontinued operations	$	0.01	$	0.01	$	0.38	$	0.38
Net income	$	3.30	$	3.28	$	3.49	$	3.46

The per share calculations above exclude 3.0 million stock options for the second quarter and first six months of 2007 and 3.2 million stock options for the second quarter and first six months of 2006, as they were antidilutive.

7. Segment Information

Marathon’s operations consist 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 second quarter and first six months of 2006 excludes the operating results for these Russian operations.

(In millions)	E&P			RM&T			IG			Total
Second Quarter Ended June 30, 2007
Revenues:
Customer	$	2,018		$	14,248		$	68		$	16,334
Intersegment (a)	116			83			—			199
Related parties	7			404			—			411

Segment revenues	2,141			14,735			68			16,944
Elimination of intersegment revenues	(116		)	(83		)	—			(199		)
Loss on long-term U.K. natural gas contracts	(9		)	—			—			(9		)

Total revenues	$	2,016		$	14,652		$	68		$	16,736

Segment income	$	400		$	1,246		$	12		$	1,658

Income from equity method investments	64			31			22			117

Depreciation, depletion and amortization (b)	237			149			3			389

Minority interests in loss of subsidiary	—			—			(1		)	(1		)

Income tax provision (b)	480			721			4			1,205

Capital expenditures (c)	580			334			34			948

(In millions)	E&P			RM&T			IG			Total
Second Quarter Ended June 30, 2006
Revenues:
Customer	$	2,325		$	15,390		$	70		$	17,785
Intersegment (a)	187			2			—			189
Related parties	3			408			—			411

Segment revenues	2,515			15,800			70			18,385
Elimination of intersegment revenues	(187		)	(2		)	—			(189		)
Loss on long-term U.K. natural gas contracts	(17		)	—			—			(17		)

Total revenues	$	2,311		$	15,798		$	70		$	18,179

Segment income	$	659		$	917		$	17		$	1,593

Income from equity method investments	53			32			12			97

Depreciation, depletion and amortization (b)	221			137			2			360

Minority interests in loss of subsidiary	—			—			(2		)	(2		)

Income tax provision (benefit) (b)	716			564			(1		)	1,279

Capital expenditures (c)	463			200			70			733

(In millions)	E&P			RM&T			IG			Total
Six Months Ended June 30, 2007
Revenues:
Customer	$	3,723		$	25,015		$	124		$	28,862
Intersegment (a)	256			84			—			340
Related parties	11			720			—			731

Segment revenues	3,990			25,819			124			29,933
Elimination of intersegment revenues	(256		)	(84		)	—			(340		)
Gain on long-term U.K. natural gas contracts	12			—			—			12

Total revenues	$	3,746		$	25,735		$	124		$	29,605

Segment income	$	785		$	1,591		$	31		$	2,407

Income from equity method investments	105			72			47			224

Depreciation, depletion and amortization (b)	479			290			4			773

Minority interests in loss of subsidiary	—			—			(3		)	(3		)

Income tax provision (b)	894			919			12			1,825

Capital expenditures (c)	1,041			551			91			1,683

(In millions)	E&P			RM&T			IG			Total
Six Months Ended June 30, 2006
Revenues:
Customer	$	4,433		$	29,280		$	100		$	33,813
Intersegment (a)	377			15			—			392
Related parties	6			717			—			723

Segment revenues	4,816			30,012			100			34,928
Elimination of intersegment revenues	(377		)	(15		)	—			(392		)
Gain on long-term U.K. natural gas contracts	61			—			—			61

Total revenues	$	4,500		$	29,997		$	100		$	34,597

Segment income	$	1,124		$	1,236		$	25		$	2,385

Income from equity method investments	106			58			25			189

Depreciation, depletion and amortization (b)	477			270			4			751
Minority interests in loss of subsidiary	—			—			(5		)	(5		)

Income tax provision (b)	1,196			768			4			1,968

Capital expenditures (c)	821			304			164			1,289

(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:

	Second Quarter Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2007			2006			2007			2006
Segment income	$	1,658		$	1,593		$	2,407		$	2,385
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(111		)	(99		)	(154		)	(165		)
Gain (loss) on long-term U.K. natural gas contracts	(5		)	(10		)	6			35
Discontinued operations	8			264			8			277
Net income	$	1,550		$	1,748		$	2,267		$	2,532

8. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Second Quarter Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2007			2006			2007			2006
Service cost	$	37		$	32		$	6		$	6
Interest cost	37			31			11			11
Expected return on plan assets	(39		)	(29		)	—			—
Amortization:
– prior service cost (credit)	4			1			(3		)	(3		)
– actuarial loss	13			11			2			2
Multi-employer and other plans	1			1			1			2

Net periodic benefit cost	$	53		$	47		$	17		$	18

	Six Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2007			2006			2007			2006
Service cost	$	70		$	66		$	11		$	12
Interest cost	71			63			22			21
Expected return on plan assets	(77		)	(55		)	—			—
Amortization:
– prior service cost (credit)	7			2			(5		)	(6		)
– actuarial loss	18			24			4			4
Multi-employer and other plans	1			1			1			2

Net periodic benefit cost	$	90		$	101		$	33		$	33

During the first six months of 2007, Marathon made contributions of $73 million to its funded pension plans, including $43 million related to international plans. Marathon expects to make additional contributions of approximately $8 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 $8 million and $16 million during the first six 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:

	Second Quarter Ended June 30,				Six Months Ended June 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	8.4		9.9		9.2		10.4
State and local income taxes, net of federal income tax effects	2.2		2.0		2.1		2.0
Other tax effects	(1.1	)	(0.6	)	(1.3	)	(0.8	)
Effective income tax rate for continuing operations	44.5	%	46.3	%	45.0	%	46.6	%

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. 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. 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:

	Second Quarter Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2007			2006		2007			2006
Net income	$	1,550		$	1,748	$	2,267		$	2,532
Other comprehensive income, net of taxes:
Minimum pension liability adjustments	—			5		—			15
Defined benefit postretirement plans (a)	(89		)	—		(53		)	—
Other	(3		)	4		(1		)	4
Comprehensive income	$	1,458		$	1,757	$	2,213		$	2,551

(a) During the first six months of 2007, changes were made to the estimates used to measure certain assumptions necessary in determining the funded status of Marathon's postretirement benefit 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)	June 30, 2007		December 31, 2006
Liquid hydrocarbons and natural gas	$	2,087	$	1,136
Refined products and merchandise	1,990		1,812
Supplies and sundry items	233		225

Total, at cost	$	4,310	$	3,173

12. Property, Plant and Equipment

Exploratory well costs capitalized greater than one year after completion of drilling as of June 30, 2007 were $119 million, including $24 million added to this category during 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 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. Following the issuance, the proceeds were trusteed and will be disbursed to Marathon upon the Company’s request for reimbursement of expenditures related to the Garyville refinery expansion. Marathon is solely obligated to service the principal and interest payments associated with the bonds. The $1.0 billion of trusteed funds are reflected as other noncurrent assets and the $1.0 billion obligation is reflected as long-term debt in the consolidated balance sheet as of June 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 4.55 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 June 30, 2007, there were no borrowings against this facility.

14. Stock-Based Compensation Plans

The following is a summary of stock option award activity:

	Number of Shares		Weighted Average Exercise Price
Outstanding at December 31, 2006 (a)	10,990,990		$	24.72
Granted	3,045,800		$	61.05
Exercised	(1,252,232	)	$	20.72
Canceled	(105,986	)	$	30.19
Outstanding at June 30, 2007 (b)	12,678,572		$	33.79

(a) Restated for the June 18, 2007 two-for-one stock split, which was effected a through a stock dividend.

(b) Of the stock option awards outstanding as of June 30, 2007, 3,045,800, 8,997,502, and 635,270 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 SARs.

15. 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.

Contract commitments – At June 30, 2007 and December 31, 2006, Marathon’s contract commitments to acquire property, plant and equipment totaled $2.505 billion and $1.703 billion. During the first six months of 2007, the majority of additional contract commitments were related to the expansion of the Company’s Garyville, Louisiana, refinery.

16. 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 June 30, 2007, the Company had acquired 57 million common shares at a cost of $2.474 billion under the program, including 15 million common shares acquired during the first six months of 2007 at a cost of $776 million.

17. Supplemental Cash Flow Information

	Six Months Ended June 30,
(In millions)	2007		2006
Noncash investing and financing activities:
Bond obligation assumed for trusteed funds	$	1,000	$	—

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

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

Net cash provided from operating activities included:
Interest paid (net of amounts capitalized)	$	20	$	56
Income taxes paid to taxing authorities	1,630		1,722

18. Subsequent Event

In July 2007, Marathon entered an agreement to purchase Western Oil Sands Inc. (“Western”). Under the terms of the agreement, Western shareholders will receive cash of 3.808 billion Canadian dollars and 34.3 million shares of Marathon common stock and securities exchangeable for Marathon common stock. Marathon will also assume Western’s debt at closing. The agreement requires Western to spin off a wholly-owned subsidiary with interests in the Federal Region of Kurdistan in northern Iraq prior to closing. The transaction is contingent upon Western shareholder approval and applicable regulatory approvals and is anticipated to close in the fourth quarter of 2007.

19. Accounting Standards Not Yet Adopted

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; domestic refining, marketing and transportation of crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and worldwide marketing and transportation of products manufactured from natural gas, such as LNG and methanol, and development of other projects to link stranded natural gas resources with key demand areas. Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with 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.

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 six months of 2007, we:

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

· Announced six exploration discoveries in deepwater Angola;

· 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 in Norway;

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

· Set records for refinery crude and total throughputs for the first six months of the year;

· Continued construction of the 110 million gallon per year joint venture ethanol facility in Greenville, Ohio;

· Commenced production at the Equatorial Guinea LNG production facility and delivered three shipments of LNG;

· Repurchased 15 million common shares, bringing total stock repurchases to date to 57 million shares at a cost of $2.474 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 second quarter and first six months of 2007 averaged 338 and 339 thousand barrels of oil equivalent per day (“mboepd”).

During the first six 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 six months of 2007, we also announced six exploration successes in deepwater Angola. The Caril, Manjericao, Cominhos and Louro 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 had three dry wells in deepwater Angola during the second quarter of 2007 and 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. The mini-tension leg platform hull was installed and topside facilities were set in June 2007. Subsea equipment installation, connection of surface equipment on the platform and facility commissioning are in progress. First production is anticipated by early 2008.

In Norway, the commissioning of the Alvheim floating production, storage and offloading (“FPSO”) vessel continues. Difficult market conditions for skilled labor and additional work to bring the FPSO into compliance with Norwegian codes and regulations and to fully integrate the existing ship systems with the new topside facilities has delayed expected first production to the fourth quarter of 2007. These factors, together with additional drilling activity, have contributed to increased costs for the project.

We now expect 2007 production available for sale to be between 350 and 375 mboepd, excluding the impact of acquisitions and dispositions, due to the delay in first production from the Alvheim/Vilje development. Previously we had expected production available for sale in 2007 to be between 390 and 425 mboepd. Sales volumes may vary from production available for sale due to the timing of liquid hydrocarbon liftings and natural gas sales.

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 and the timing and levels of our worldwide liquid hydrocarbon, natural gas and condensate production available for sale. 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”)

In the second quarter and first six months of 2007, our total refinery throughput was three percent and four percent higher than the same periods of 2006. Crude oil throughput was three percent and five percent higher in these periods and we expect crude oil throughput for the full year 2007 to exceed the record level we set in 2006. Our refining and wholesale marketing gross margin averaged 39.25 cents per gallon in the second quarter of 2007 compared to 29.78 cents per gallon in the second quarter of 2006. This margin improvement was consistent with the relevant market indicators in the Midwest and Gulf Coast markets. The increase in our refining and wholesale marketing gross margin for the first six months of 2007 was also impacted by the change in accounting for matching buy/sell arrangements effective April 1, 2006, as the sales volumes recognized in the first six months of 2007 were less than the volumes that would have been recognized under previous accounting practices. Our ethanol blending program increased to 40 thousand barrels per day (“mbpd”) in the second quarter of 2007 from 35 mbpd in the second 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 one percent when compared to the second quarter of 2006. In addition SSA’s gasoline and distillates gross margin per gallon and merchandise gross margin were stronger in the second quarter and first six months of 2007 than in the comparable periods of 2006.

Construction of the Garyville, Louisiana, refinery commenced on schedule in early March 2007. Construction crews are clearing the site and driving piles that will be used to support the foundation for the equipment that will be constructed at this site over the next two years.

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 margins, other operating considerations and government regulations. The above discussion also contains forward-

looking information with respect to the Garyville expansion project. Factors that could affect that project include crude oil supply, transportation logistics, availability of material and labor, unforeseen hazards such as weather conditions, necessary government and third party approvals, and other risks customarily associated with construction projects. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas (“IG”)

The LNG production facility in Equatorial Guinea was completed and delivered its first cargo of LNG in May 2007. A total of three cargos were delivered during the second quarter of 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. The facility was shut down again in July for commissioning maintenance and has since returned its processing levels to full capacity.

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 a final investment decision in 2008.

The above discussion contains forward-looking statements with respect to the possible expansion of the LNG production facility. 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.

Capital, Investment and Exploration Budget

We have increased our capital, investment and exploration budget for 2007, excluding major acquisitions, from $4.242 billion to $4.683 billion, which includes budgeted capital expenditures of $4.295 billion. Total E&P spending is now projected to be $2.614 billion, an increase of $383 million. This increase is approximately evenly divided between an increase in the cost of the Alvheim/Vilje development and general inflationary pressures. RM&T spending is expected to increase by $202 million to $1.666 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. Integrated gas spending is now expected to be $209 million less than the original estimate of $331 million, reflecting EGHoldings being accounted for under the equity method upon start of production. Capitalized interest and corporate spending is expected to be $65 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.

Proposed Acquisition

In July 2007, we entered an agreement to purchase Western Oil Sands Inc. (“Western”). Under the terms of the agreement, Western shareholders will receive cash of 3.808 billion Canadian dollars and 34.3 million shares of Marathon common stock and securities exchangeable for Marathon common stock. We will also assume Western’s debt at closing. Based on the exchange rate and our stock price on July 27, 2007, the total transaction value would be approximately $6 billion. The agreement requires Western to spin off a wholly-owned subsidiary with interests in the Federal Region of Kurdistan in northern Iraq prior to closing. The transaction is contingent upon Western shareholder approval and applicable regulatory approvals and is anticipated to close in the fourth quarter of 2007.

Western’s primary asset is a 20 percent outside-operated interest in the Athabasca Oil Sands Project, 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 Athabasca Oil Sands Project developments with heavy oil upgrade projects at our refineries.

The above discussion contains forward-looking statements concerning the anticipated acquisition of Western and potential heavy oil refining upgrading projects. This forward-looking information may prove to be inaccurate and actual results may differ materially from those presently anticipated. Factors, but not necessarily all factors, that could adversely affect the anticipated acquisition of Western include the inability or delay in obtaining necessary government and third-party approvals and approval by Western’s shareholders. Factors that could affect the potential heavy oil refining upgrading projects include results of front-end engineering and design work, approval of our Board of Directors, inability or delay in obtaining necessary government and third-party approvals, continued favorable investment climate, and other geological, operating and economic considerations.

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 share 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 six months of 2007 and 2006.

Consolidated Results of Operations

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

	Second Quarter Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2007			2006			2007			2006
E&P	$	2,141		$	2,515		$	3,990		$	4,816
RM&T	14,735			15,800			25,819			30,012
IG	68			70			124			100

Segment revenues	16,944			18,385			29,933			34,928
Elimination of intersegment revenues	(199		)	(189		)	(340		)	(392		)
Gain (loss) on long-term U.K. natural gas contracts	(9		)	(17		)	12			61

Total revenues	$	16,736		$	18,179		$	29,605		$	34,597

Items included in both revenues and costs and expenses:

Consumer excise taxes on petroleum products and merchandise	$	1,307		$	1,277		$	2,504		$	2,442
Matching crude oil and refined product buy/sell transactions:

E&P	—			5			—			16
RM&T	65			1,801			123			4,996

Total buy/sell transactions included in revenues	$	65		$	1,806		$	123		$	5,012

E&P segment revenues decreased $374 million in the second quarter of 2007 from the comparable prior-year period, primarily as a result of lower liquid hydrocarbon sales volumes and realizations, with the most significant sales volume decline related to international operations. International liquid hydrocarbon sales volumes were significantly higher in the second quarter of 2006 due to approximately 40 mbpd of sales in excess of production in that quarter, while sales volumes approximated production in the second quarter of 2007. 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 there contributed to the decline in the average international natural gas realization for the second quarter of 2007.

E&P segment revenues in the first six months of 2007 decreased $826 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 six-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 six months of 2007 compared to the same period of 2006.

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

Excluded from E&P segment revenues were losses of $9 million and $17 million for the second quarters of 2007 and 2006, on long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments. For the first six months of 2007 and 2006, gains of $12 million and $61 million are excluded from E&P segment revenues. See Item 3. Quantitative and Qualitative Disclosures About Market Risk.

RM&T segment revenues decreased $1.065 billion in the second quarter of 2007 and $4.193 billion in the first six months of 2007 from the comparable prior-year periods primarily as a result of the change in accounting for matching buy/sell transactions effective April 1, 2006, discussed above. Excluding matching buy/sell transactions, RM&T segment

revenues increased in both periods, reflecting increased refined product selling prices and crude oil sales volumes, partially offset by lower refined product sales volumes.

For information on segment income, see Segment Results.

Purchases related to matching buy/sell transactions decreased $1.666 billion and $4.838 billion in the second quarter and first six 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 $115 million and $176 million in the second quarter and first six months of 2007, including expenses related to dry wells of $39 million and $55 million primarily related to exploration activities in Angola. Exploration expenses were $66 million and $137 million in the second quarter and first six months of 2006, including expenses related to dry wells of $28 million and $58 million. The largest increase in exploration expenses in these periods related to geological and geophysical costs.

Provision for income taxes decreased $47 million and $114 million in the second quarter and first six months of 2007 from the comparable periods of 2006 as a result of effective tax rate declines in both periods and the $110 million decrease in income from continuing operations before income taxes for the six-month period. The following is an analysis of the effective income tax rates for continuing operations for the second quarters and first six months of 2007 and 2006:

	Second Quarter Ended June 30,				Six Months Ended June 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	8.4		9.9		9.2		10.4
State and local income taxes, net of federal income tax effects	2.2		2.0		2.1		2.0
Other tax effects	(1.1	)	(0.6	)	(1.3	)	(0.8	)
Effective income tax rate for continuing operations	44.5	%	46.3	%	45.0	%	46.6	%

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 second quarters and first six months of 2007 and 2006 is summarized in the following table.

	Second Quarter Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2007			2006			2007			2006
E&P
United States	$	173		$	243		$	323		$	488
International	227			416			462			636

E&P segment	400			659			785			1,124
RM&T	1,246			917			1,591			1,236
IG	12			17			31			25

Segment income	1,658			1,593			2,407			2,385
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(111		)	(99		)	(154		)	(165		)
Gain (loss) on long-term U.K. natural gas contracts	(5		)	(10		)	6			35
Discontinued operations	8			264			8			277

Net income	$	1,550		$	1,748		$	2,267		$	2,532

United States E&P income decreased $70 million, or 29 percent, in the second quarter of 2007 and decreased $165 million, or 34 percent, in the first six months of 2007 compared to the same periods of 2006. Pretax income decreased $126 million and $276 million in the same periods and the effective income tax rate decreased to 34 percent from 37

percent in the second quarter of 2006. The lower pretax income is primarily a result of revenue decreases from lower liquid hydrocarbon and natural gas sales volumes and liquid hydrocarbon realizations, as discussed above.

International E&P income decreased $189 million, or 45 percent, and $174 million, or 27 percent, in the second quarter and first six months of 2007 compared to the same periods of 2006. Pretax income decreased $369 million and $365 million in the same periods, while the effective income tax rate increased from 58 percent to 63 percent in the second quarter of 2007 and from 59 percent to 61 percent in the first six months of 2007 compared to the 2006 periods. The lower pretax income is primarily a result of revenue decreases from lower liquid hydrocarbon sales volumes and lower liquid hydrocarbon and natural gas realizations, as discussed above, and increased exploration expenses, including dry well costs in Angola and geological and geophysical costs.

RM&T segment income increased by $329 million, or 36 percent, and $355 million, or 29 percent, in the second quarter and first six months of 2007 compared to the same periods of 2006. Pretax income increased $486 million and $506 million in the same periods, while the effective income tax rate decreased slightly in both periods. The increases in RM&T pretax income are primarily a result of improvement in the refining and wholesale marketing gross margin, which averaged 39.25 cents per gallon in the second quarter of 2007 and 26.34 cents per gallon in the first six months of 2007, compared to 29.78 cents per gallon and 20.77 cents per gallon in the comparable periods of 2006. This margin improvement was consistent with the relevant market indicators in the Midwest and Gulf Coast markets. Crude oil refined averaged 1,072 mbpd and 1,021 mbpd, during the second quarter and first six months of 2007, 34 mbpd and 53 mbpd higher than the averages for the same periods of 2006.

IG segment income decreased $5 million in the second quarter of 2007 and increased $6 million in the first six months of 2007 compared to the same periods of 2006. Increased income from EGHoldings, as a result of the first LNG deliveries during the second quarter of 2007, was more than offset by a decline in income from domestic integrated gas activities due to a planned turnaround at our LNG production facility in Alaska, increased research and development costs and increased income taxes. Contributing to improved results for the first six months of 2007 was higher income from Atlantic Methanol Production Company LLC in the first quarter of 2007 due to higher realized methanol prices.

Management’s Discussion and Analysis of Cash Flows and Liquidity

Cash Flows

Net cash provided from operating activities totaled $2.366 billion in the first six months of 2007, compared to $2.299 billion in the first six months of 2006.

Net cash used in investing activities totaled $1.728 billion in the first six months of 2007, compared to $857 million in the first six months of 2006. Capital expenditures were $1.699 billion compared with $1.308 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 six 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 re-entry into Libya.

Net cash used in financing activities was $896 million in the first six months of 2007, compared to $1.048 billion in the first six 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 second quarter of 2007 included borrowings of $578 million from the Norwegian export credit agency.

Dividends to Stockholders

On July 25, 2007, our Board of Directors declared a dividend of 24 cents per share, payable September 10, 2007, to stockholders of record at the close of business on August 16, 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+. 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, the proposed acquisition of Western and any amounts that may ultimately be paid in connection with contingencies.

We have a committed $2.0 billion revolving credit facility with third-party financial institutions terminating in May 2012. At June 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 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. Following the issuance, the proceeds were trusteed and will be disbursed to us upon our request for reimbursement of expenditures related to the Garyville refinery expansion. We are solely obligated to service the principal and interest payments associated with the bonds. The $1.0 billion of trusteed funds are reflected as other noncurrent assets and the $1.0 billion obligation is reflected as long-term debt in the consolidated balance sheet as of June 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 cash-adjusted debt-to-capital ratio (total debt-minus-cash and trusteed funds to total debt-plus-equity-minus-cash and trusteed funds) was eight percent at June 30, 2007, compared to six percent at year-end 2006 as shown below. This includes $510 million of debt that is serviced by United States Steel Corporation (“United States Steel”).

(Dollars in millions)	June 30, 2007			December 31, 2006
Long-term debt due within one year	$	421		$	471
Long-term debt	4,237			3,061
Total debt	$	4,658		$	3,532
Cash	$	2,331		$	2,585
Trusteed funds from revenue bonds (a)	$	1,000		$	—
Equity	$	15,815		$	14,607
Calculation:
Total debt	$	4,658		$	3,532
Minus cash	2,331			2,585
Minus trusteed funds from revenue bonds	1,000			—
Total debt minus cash	1,327			947

Total debt	4,658			3,532
Plus equity	15,815			14,607
Minus cash	2,331			2,585
Minus trusteed funds from revenue bonds	1,000			—
Total debt plus equity minus cash	$	17,142		$	15,554
Cash-adjusted debt-to-capital ratio	8		%	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 issuance of the bonds or the Garyville refinery expansion. The trusteed funds are reflected as other noncurrent assets in the accompanying consolidated balance sheet as of June 30, 2007.

In July 2007, we entered an agreement to purchase Western. Under the terms of the agreement, Western shareholders will receive cash of 3.808 billion Canadian dollars and 34.3 million shares of Marathon common stock and securities exchangeable for Marathon common stock. We will also assume Western’s debt at closing. Based on the exchange rate and our stock price on July 27, 2007, the total transaction value would be approximately $6 billion. The agreement requires Western to spin off a wholly-owned subsidiary with interests in the Federal Region of Kurdistan in northern Iraq prior to closing. The transaction is contingent upon Western shareholder approval and applicable regulatory approvals and is anticipated to close in the fourth quarter of 2007. If we complete this proposed acquisition, we expect our cash-adjusted debt-to-capital ratio will be in the mid-20 percent range. We anticipate funding the cash

portion of the acquisition with cash on hand, short-term credit facilities and new long-term borrowings. Following the announcement of the transaction, Standard and Poor’s Corporation, Moody’s Investor Services, Inc. and Fitch Ratings each affirmed our current senior unsecured debt ratings.

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.

Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The above discussion also contains forward-looking statements concerning the anticipated acquisition of Western. This forward-looking information may prove to be inaccurate and actual results may differ materially from those presently anticipated. Factors, but not necessarily all factors, that could adversely affect the anticipated acquisition include the inability or delay in obtaining necessary government and third-party approvals and approval by Western’s shareholders.

Stock Repurchase Program

Our Board of Directors has authorized a common stock repurchase program totaling $5 billion, with $500 million added to the program in May 2007 and $2 billion added to the program in July 2007. As of June 30, 2007, we had repurchased 57 million common shares at a cost of $2.474 billion. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. We will use cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program does not include specific price targets or timetables.

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

Contractual Cash Obligations

As of June 30, 2007, our contractual cash obligations have increased by $2.859 billion from December 31, 2006. Our purchase obligations under crude oil, refinery feedstock, refined product and ethanol contracts, which are primarily short-term, increased $1.226 billion primarily related to refined products. Long-term debt increased by $1.130 billion due to the revenue bond issuance and Norwegian borrowings in the second quarter of 2007 discussed above, net of the repayment of maturing debt. Otherwise, there have been no 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 $339 million as of June 30,

2007. Of this amount, $217 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 June 30, 2007, we have obligations totaling $549 million that have been assumed by United States Steel. Of this amount, obligations of $519 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet (current portion - $31 million; long-term portion - $488 million). The remaining $30 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

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 2010 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.

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.

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.

Environmental Proceedings

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).

Other Proceedings

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. MPCA had originally sought a penalty of $121,800.

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 and may take several weeks or months to conduct. OSHA commenced an inspection at Marathon’s Canton, Ohio, refinery in the second quarter of 2007. Some enforcement actions by OSHA under the NEP against domestic petroleum refiners may result from the inspections but there is no specific enforcement action against Marathon at this time.

There have been no other significant changes to our environmental matters subsequent to December 31, 2006.

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,

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

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

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

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

· to protect against decreases in future crack spreads; and

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

We use financial derivative instruments to manage 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 June 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)	$	—		$	—
Natural gas (d)	40		(e)	100		(e)
Refined products (d)	20		(e)	61		(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 June 30, 2007. Included in the natural gas impacts shown above are $44 million and $111 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 June 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 second quarter of 2007, from a low of 15 contracts on April 30, 2007, to a high of 782 contracts on April 1, 2007, and averaged 322 for the quarter. The number of net open contracts for the RM&T segment varied throughout the second quarter of 2007, from a low of 982 contracts on April 17, 2007 to a high of 21,633 contracts on June 27, 2007, and averaged 11,864 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 $24 million and gains of $24 million were included in E&P segment income for the first six 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 gains of $12 million and $61 million for the first six months of 2007 and 2006 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.

At June 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 second quarters and first six months of 2007 and 2006 are summarized in the following table:

	Second Quarter Ended June 30,						Six Months Ended June 30,
(In millions)	2007			2006			2007			2006

Strategy:
Mitigate price risk	$	(71	)	$	(109	)	$	(19	)	$	(105	)
Protect carrying values of excess inventories	(51		)	(62		)	(76		)	(78		)
Protect margin on fixed price sales	1			6			3			10
Protect crack spread values	(18		)	(2		)	(20		)	(5		)
Subtotal, non-trading activities	(139		)	(167		)	(112		)	(178		)
Trading activities	5			(7		)	4			(2		)
Total net derivative losses	$	(134	)	$	(174	)	$	(108	)	$	(180	)

Derivatives used in non-trading activities have an underlying physical commodity transaction. Since the majority of RM&T segment derivative contracts are for the sale of commodities, derivative losses generally occur when market prices increase and typically are offset by gains on the underlying physical commodity transactions. Conversely, derivative gains generally occur when market prices decrease and are typically offset by losses on the underlying physical commodity transactions. The income effect related to 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.

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 exposure is relatively low for exchange-traded transactions.

Interest Rate Risk

We are impacted by interest rate fluctuations which affect the fair value of certain financial instruments. A sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates as of June 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	$	509		$	11
Interest rate swap agreements	$	(18)	(b)	$	7	(c)
Long-term debt, including amounts due within one year	$	(4,674)	(b)	$	(232)	(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 June 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 June 30, 2007.

At June 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 effects of interest rate fluctuations. This sensitivity is illustrated by the $232 million increase in the fair value of long-term debt at June 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 the foreign currency markets by locking in foreign currency rates. The aggregate effect on foreign currency contracts of a hypothetical 10 percent change to exchange rates at June 30, 2007, would be approximately $6 million. There have been no significant changes to our exposure to foreign exchange rates subsequent to December 31, 2006.

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 June 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)

	Second Quarter Ended June 30,						Six Months Ended June 30,
(Dollars in millions, except as noted)	2007			2006			2007			2006

SEGMENT INCOME
Exploration and Production
United States	$	173		$	243		$	323		$	488
International	227			416			462			636
E&P segment	400			659			785			1,124
Refining, Marketing and Transportation	1,246			917			1,591			1,236
Integrated Gas	12			17			31			25
Segment income	1,658			1,593			2,407			2,385
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(111		)	(99		)	(154		)	(165		)
Gain (loss) on long-term U.K. natural gas contracts	(5		)	(10		)	6			35
Discontinued operations	8			264			8			277
Net income	$	1,550		$	1,748		$	2,267		$	2,532

CAPITAL EXPENDITURES
Exploration and Production	$	580		$	463		$	1,041		$	821
Refining, Marketing and Transportation	334			200			551			304
Integrated Gas(a)	34			70			91			164
Discontinued Operations	—			19			—			45
Corporate	14			2			16			19
Total	$	962		$	754		$	1,699		$	1,353

EXPLORATION EXPENSE
United States	$	47		$	41		$	84		$	69
International	68			25			92			68
Total	$	115		$	66		$	176		$	137

E&P OPERATING STATISTICS
Net Liquid Hydrocarbon Sales (mbpd)(b)
United States	65			79			67			79
Europe	34			47			34			38
Africa	100			133			98			103
Total International	134			180			132			141
Worldwide Continuing Operations	199			259			199			220
Discontinued Operations	—			20			—			25
Worldwide	199			279			199			245
Net Natural Gas Sales (mmcfd)(b)(c)
United States	460			523			485			542
Europe	178			226			213			286
Africa	196			52			143			70
Total International	374			278			356			356
Worldwide	834			801			841			898
Total Worldwide Sales (mboepd)
Continuing operations	338			392			339			370
Discontinued operations	—			20			—			25
Worldwide	338			412			339			395

(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 54 mmcfd and 60 mmcfd in the second quarters of 2007 and 2006, and 47 mmcfd and 50 mmcfd for the first six months of 2007 and 2006.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Second Quarter Ended June 30,				Six Months Ended June 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	$	55.19	$	59.80	$	52.19	$	54.52

Europe	61.34		67.52		59.12		65.43
Africa	60.91		65.14		55.79		60.36
Total International	61.02		65.76		56.63		61.74
Worldwide Continuing Operations	59.11		63.95		55.13		59.14
Discontinued Operations	—		39.80		—		38.38
Worldwide	59.11		62.19		55.13		57.04

Natural Gas (per mcf)
United States	$	6.16	$	5.35	$	6.03	$	6.02

Europe	4.47		6.32		5.71		7.13
Africa	0.25		0.25		0.26		0.25
Total International	2.27		5.19		3.51		5.78
Worldwide	4.41		5.29		4.96		5.93

RM&T OPERATING STATISTICS

Refinery Runs (mbpd)
Crude oil refined	1,072		1,038		1,021		968
Other charge and blend stocks	208		207		217		228
Total	1,280		1,245		1,238		1,196

Refined Product Yields (mbpd)
Gasoline	680		663		651		654
Distillates	377		321		350		306
Propane	26		24		23		22
Feedstocks and special products	96		125		121		116
Heavy fuel oil	27		25		25		24
Asphalt	89		102		83		89
Total	1,295		1,260		1,253		1,211

Refined Products Sales Volumes (mbpd)(e)(f)	1,426		1,461		1,385		1,439
Matching buy/sell volumes included in above(f)	—		11		—		47

Refining and Wholesale Marketing Gross Margin (per gallon)(g)	$	0.3925	$	0.2978	$	0.2634	$	0.2077

Speedway SuperAmerica
Retail outlets	1,637		1,637		—		—
Gasoline and distillate sales (millions of gallons)	828		816		1,628		1,592
Gasoline and distillate gross margin (per gallon)	$	0.1029	$	0.1019	$	0.1121	$	0.1037
Merchandise sales	$	714	$	690	$	1,358	$	1,300
Merchandise gross margin	$	182	$	171	$	342	$	319

IG OPERATING STATISTICS

Net Sales (metric tonnes per day)
LNG	1,997		1,106		1,582		1,102
Methanol	1,107		1,068		1,215		1,103

(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

On April 12, 2007, Marathon Petroleum Company LLC (“MPC”) was notified by the Division of Enforcement of the Commodity Futures Trading Commission (the “Commission”) of its intent to recommend that the Commission name MPC in an enforcement action alleging that on November 26, 2003, MPC attempted to manipulate the price of West Texas Intermediate crude oil. The proposed enforcement action involved allegations that on the day mentioned in the notice MPC offered to sell crude oil in a physical cash market at a price lower than contemporaneous bids. There were no allegations of false reporting. After consideration of all relevant factors, and without admitting or denying the findings in the settlement order dated August 1, 2007, MPC reached a settlement with the Commission. Under the terms of the settlement, MPC shall pay a civil monetary penalty of $1 million.

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. There have been no material changes from the risk factors previously disclosed in that Form 10-K.

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)
04/01/07 – 04/30/07	7,878		$	102.11		—		$	344,248,401
05/01/07 – 05/31/07	1,153,604		$	113.11		1,151,600		$	713,969,951
06/01/07 – 06/30/07	3,590,365	(c)	$	54.55	(e)	3,574,100	(e)	$	519,971,746
Total	4,751,847		$	68.85		4,725,700

(a) 12,608 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements. This number also includes 1,365 shares that were due for tax withholding requirements for restricted stock that vested between the two-for-one stock split record date, May 23, 2007, and payment date, June 18, 2007. Pursuant to the terms of Marathon’s incentive compensation plans, the number of shares of restricted stock awards shall be proportionately adjusted in the event of a declaration of a stock split dividend payable in shares of common stock.

(b) Under the terms of the transaction whereby Marathon acquired the minority interest in MPC 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 four shares due to acquisition share exchanges and Ashland Inc. share transfers pending at the closing of the transaction.

(c) 13,535 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. Stock 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 June 30, 2007, 57 million, split-adjusted common shares had been acquired at a cost of $2.474 billion, which includes transaction fees and commissions that are not reported in the table above.

(e) After the June 18, 2007 two-for-one stock split, which was effected a through a stock dividend, Marathon was entitled to receive for purchases and pending settlements that occurred between the stock split record and payment date, an additional share for each share purchased or pending settlement. Included in the number of shares purchased in June 2007 is 1,583,500 shares which are related to share purchases and pending settlements that occurred under our stock repurchase program between the stock split record date, May 23, 2007, and payment date, June 18, 2007.

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

The annual meeting of stockholders was held on April 25, 2007. In connection with the meeting, proxies were solicited pursuant to the Securities Exchange Act of 1934. The following are the voting results on proposals considered and voted upon at the meeting, all of which were described in Marathon’s 2007 Proxy Statement.

1. Votes regarding the persons elected to serve as directors for a term expiring in 2008 were as follows:

NOMINEE	VOTES FOR	VOTES AGAINST	VOTES ABSTAINED

Charles F. Bolden, Jr.	297,351,905	3,877,422	2,575,678
Charles R. Lee	294,675,878	6,286,947	2,666,266
Dennis H. Reilley	299,264,451	1,957,952	2,582,842
John W. Snow	299,028,506	2,159,965	2,617,011
Thomas J. Usher	295,862,865	5,275,301	2,666,838

Continuing as directors for a term expiring in 2008 are Shirley Ann Jackson, Philip Lader, Seth E. Schofield and Douglas C. Yearley. Continuing as directors for a term expiring in 2009 are Clarence P. Cazalot, Jr., David A. Daberko, and William L. Davis.

2. PricewaterhouseCoopers LLP was ratified as the independent auditors for 2007. The voting results were as follows:

VOTES FOR	VOTES AGAINST	VOTES ABSTAINED

297,119,354	4,271,727	2,413,118

3. The 2007 Incentive Compensation Plan (“Plan”) proposed by the Board of Directors was approved. The Plan provides the means by which Marathon grants annual incentive compensation, as well as long-term incentive compensation, to employees of Marathon and its subsidiaries eligible for awards under the Plan, and to its non-employee directors. The voting results were as follows:

VOTES FOR	VOTES AGAINST	VOTES ABSTAINED

267,145,602	33,675,485	2,981,978

4. The Board of Directors proposal to amend the Restated Certificate of Incorporation and By-laws to eliminate the supermajority vote provision was approved. The voting results were as follows:

VOTES FOR	VOTES AGAINST	VOTES ABSTAINED

297,659,552	3,192,729	2,951,338

5. The Board of Directors proposal to amend the Restated Certificate of Incorporation to increase the number of authorized shares of common stock was approved. The voting results were as follows:

VOTES FOR	VOTES AGAINST	VOTES ABSTAINED

253,653,518	47,492,705	2,652,206

Item 6. Exhibits

4.1	Amendment No. 2 dated as of May 7, 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	Arrangement Agreement, dated as of July 30, 2007, among Marathon Oil Corporation, 1339971 Alberta Ltd., Western Oil Sands Inc. and WesternZagros Resources Inc. (incorporated by reference to Exhibit 10.1 to Marathon Oil Corporation ‘f Form 8-K, filed on August 3, 2007.
10.2	Form of Non-Qualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007
10.3	Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007
10.4	Form of Performance Unit Award Agreement (2007-2009 Performance Cycle) for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 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

August 7, 2007