UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
~~[X]~~x		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934

	For the Quarterly Period Ended ~~March 31,~~September 30, 2007
	OR
~~[ ]~~OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	~~For the transition period from~~ to

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)

~~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 ÖxNo 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

~~Large accelerated filer~~ x Accelerated filer o Non-accelerated filer oÖ

~~Accelerated filer~~

~~Non-accelerated filer~~

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

Yes oNo Öx

There were ~~342,978,266~~710,279,884 shares of Marathon Oil Corporation common stock outstanding as of ~~April 30,~~October 31, 2007.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended ~~March 31,~~September 30, 2007

					INDEX		~~Page~~

~~PART I – FINANCIAL INFORMATION~~

	~~Item 1.~~	~~Financial Statements:~~

PART I - FINANCIAL INFORMATION				3

~~Consolidated Statements of Income (Unaudited)~~Item 1.	Financial Statements:			3

	Consolidated Statements of Income (Unaudited)			3

	Consolidated Balance Sheets (Unaudited)			4

			Consolidated Statements of Cash Flows (Unaudited)				5

			Selected Notes to Consolidated Financial Statements (Unaudited)				6

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk			29

Item 4.	Controls and Procedures			33

	~~Item 2.~~Supplemental Statistics (Unaudited)		~~Management’s Discussion and Analysis of~~ ~~Financial Condition and Results of Operations~~			12

	~~Item 3.~~	~~Quantitative and Qualitative Disclosures About Market Risk~~		21

	~~Item 4.~~	~~Controls and Procedures~~		24

		~~Supplemental Statistics~~		2534

PART II –- OTHER INFORMATION

	~~Item 1.~~	~~Legal Proceedings~~		2736

	Item ~~1A.~~1.	~~Risk Factors~~Legal Proceedings		27	36

Item 1A.	Risk Factors			36

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		27	37

Item 6.	Exhibits			38

	~~Item 4.~~Signatures		~~Submission of Matters to a Vote of Security Holders~~			28

	~~Item 6.~~	~~Exhibits~~		29

		~~Signatures~~		3039

Unless the context otherwise indicates, references in this ~~Quarterly Report on~~ 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, typically between 20 and 50 percent)~~interest).

Part I –- Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)

First Quarter Ended March 31,

(Dollars in millions, except per share data)

2007

2006

Revenues and other income:

Sales and other operating revenues (including consumer excise taxes)

$
12,491

$
12,900

Revenues from matching buy/sell transactions

58

3,206

Sales to related parties

320

312

Income from equity method investments

107

92

Net gains on disposal of assets

11

11

Other income

15

18

Total revenues and other income

13,002

16,539

Costs and expenses:

Cost of revenues (excludes items below)

9,542

9,759

Purchases related to matching buy/sell transactions

61

3,233

Purchases from related parties

47

51

Consumer excise taxes

1,197

1,165

Depreciation, depletion and amortization

393

400

Selling, general and administrative expenses

287

287

Other taxes

98

97

Exploration expenses

61

71

Total costs and expenses

11,686

15,063

Income from operations

1,316

1,476

Net interest and other financing costs (income)

(19
)
23

Loss on early extinguishment of debt

2

–

Minority interests in loss of Equatorial Guinea LNG Holdings Limited

(2
)
(3
)
Income from continuing operations before income taxes

1,335

1,456

Provision for income taxes

618

685

Income from continuing operations

717

771

Discontinued operations

–

13

Net income

$
717

$
784

Per Share Data

Basic:

Income from continuing operations

$
2.08

$
2.11

Discontinued operations

–

$
0.04

Net income

$
2.08

$
2.15

Diluted:

Income from continuing operations

$
2.07

$
2.09

Discontinued operations

–

$
0.04

Net income

$
2.07

$
2.13

Dividends paid

$
0.40

$
0.33

	Third Quarter Ended September 30,						Nine Months Ended September 30,
*(Dollars in millions, except per share data)*	2007			2006			2007			2006
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	16,345		$	15,837		$	45,096		$	44,699
Revenues from matching buy/sell transactions	2			237			125			5,249
Sales to related parties	415			418			1,146			1,141
Income from equity method investments	170			109			394			298
Net gain on disposal of assets	2			12			20			28
Other income	20			21			62			48
Total revenues and other income	16,954			16,634			46,843			51,463
Costs and expenses:
Cost of revenues (excludes items below)	12,994			11,260			34,291			32,647
Purchases related to matching buy/sell transactions	2			222			147			5,205
Purchases from related parties	59			61			160			159
Consumer excise taxes	1,352			1,297			3,856			3,739
Depreciation, depletion and amortization	409			361			1,198			1,130
Selling, general and administrative expenses	336			300			950			895
Other taxes	95			92			286			280
Exploration expenses	88			97			264			234
Total costs and expenses	15,335			13,690			41,152			44,289

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

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

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

Discontinued operations	—			—			8			277

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

Per Share Data

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

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

Dividends paid	$	0.24		$	0.20		$	0.68		$	0.56

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

March 31,

December 31,

(Dollars in millions, except per share data)

2007

2006

Assets

Current assets:

Cash and cash equivalents

$
2,347

$
2,585

Receivables, less allowance for doubtful accounts of $3 and $3

4,143

4,114

Receivables from United States Steel

30

32

Receivables from related parties

64

63

Inventories

3,536

3,173

Other current assets

217

129

Total current assets

10,337

10,096

Investments and long-term receivables, less allowance for doubtful accounts of $9 and $9

1,954

1,887

Receivables from United States Steel

495

498

Property, plant and equipment, less accumulated depreciation, depletion and amortization of $13,873 and $13,573

16,963

16,653

Goodwill

1,396

1,398

Intangible assets, less accumulated amortization of $79 and $75

179

180

Other noncurrent assets

72

119

Total assets

$
31,396

$
30,831

Liabilities

Current liabilities:

Accounts payable

$
6,063

$
5,586

Payable to United States Steel

–

13

Payables to related parties

294

264

Payroll and benefits payable

335

409

Accrued taxes

587

598

Deferred income taxes

643

631

Accrued interest

54

89

Long-term debt due within one year

873

471

Total current liabilities

8,849

8,061

Long-term debt

2,654

3,061

Deferred income taxes

1,893

1,897

Defined benefit postretirement plan obligations

1,201

1,245

Asset retirement obligations

1,059

1,044

Payable to United States Steel

7

7

Deferred credits and other liabilities

395

391

Total liabilities

16,058

15,706

Minority interests in Equatorial Guinea LNG Holdings Limited

546

518

Commitments and contingencies

Stockholders’ Equity

Common stock issued – 367,851,558 shares (par value $1 per share, 550,000,000 shares authorized)

368

368

Common stock held in treasury, at cost – 24,897,453 and 20,080,670 shares

(2,073
)
(1,638
)
Additional paid-in capital

5,148

5,152

Retained earnings

11,671

11,093

Accumulated other comprehensive loss

(322
)
(368
)
Total stockholders' equity

14,792

14,607

Total liabilities and stockholders' equity

$
31,396

$
30,831

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

Stockholders’ Equity

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

The accompanyingnotes are an integral part of these consolidated financial statements.

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended September 30,
*(Dollars in millions)*	2007			2006
*Increase (decrease) in cash and cash equivalents*
Operating activities:
Net income	$	3,288		$	4,155
Adjustments to reconcile net income to net cash provided from operating activities:
Loss on early extinguishment of debt	14			—
Income from discontinued operations	(8		)	(277		)
Deferred income taxes	12			186
Minority interests in loss of Equatorial Guinea LNG Holdings Limited	(3		)	(7		)
Depreciation, depletion and amortization	1,198			1,130
Pension and other postretirement benefits, net	68			(103		)
Exploratory dry well costs and unproved property impairments	109			119
Net gain on disposal of assets	(20		)	(28		)
Equity method investments, net	(123		)	(210		)
Changes in the fair value of long-term U.K. natural gas contracts	111			(182		)
Changes in:
Current receivables	(1,190		)	(444		)
Inventories	(1,444		)	(999		)
Current accounts payable and accrued expenses	988			334
All other, net	(49		)	2
Net cash provided from continuing operations	2,951			3,676
Net cash provided from discontinued operations	—			69
Net cash provided from operating activities	2,951			3,745
Investing activities:
Capital expenditures	(2,725		)	(2,405		)
Acquisitions	—			(543		)
Disposal of assets	51			79
Disposal of discontinued operations	—			832
Trusteed funds - withdrawals	163			—
Investments - loans and advances	(88		)	(4		)
Investments - repayments of loans and return of capital	35			219
Deconsolidation of Equatorial Guinea LNG Holdings Limited	(37		)	—
Investing activities of discontinued operations	—			(45		)
All other, net	(8		)	15
Net cash used in investing activities	(2,609		)	(1,852		)
Financing activities:
Borrowings	2,071			—
Debt issuance costs	(19		)	—
Debt repayments	(541		)	(304		)
Issuance of common stock	23			41
Purchases of common stock	(800		)	(1,146		)
Excess tax benefits from stock-based compensation arrangements	25			26
Dividends paid	(465		)	(407		)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited	39			64
Net cash provided by (used in) financing activities	333			(1,726		)
Effect of exchange rate changes on cash	9			13
Net increase in cash and cash equivalents	684			180
Cash and cash equivalents at beginning of period	2,585			2,617
Cash and cash equivalents at end of period	$	3,269		$	2,797

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

~~MARATHON OIL CORPORATION~~
~~Consolidated Statements of Cash Flows (Unaudited)~~

First Quarter Ended March 31,

(Dollars in millions)

2007

2006

Increase (decrease) in cash and cash equivalents

Operating activities:

Net income

$
717

$
784

Adjustments to reconcile net income to net cash provided from operating activities:

Loss on early extinguishment of debt

2

–

Income from discontinued operations

–

(13
)
Deferred income taxes

26

42

Minority interests in loss of Equatorial Guinea LNG Holdings Limited

(2
)
(3
)
Depreciation, depletion and amortization

393

400

Pension and other postretirement benefits, net

5

(92
)
Exploratory dry well costs and unproved property impairments

26

34

Net gains on disposal of assets

(11
)
(11
)
Equity method investments, net

(20
)
(59
)
Changes in the fair value of long-term U.K. natural gas contracts

(21
)
(78
)
Changes in:

Current receivables

(27
)
(172
)
Inventories

(364
)
(365
)
Current accounts payable and accrued expenses

351

(190
)
All other, net

(49
)
(73
)
Net cash provided from continuing operations

1,026

204

Net cash provided from discontinued operations

–

36

Net cash provided from operating activities

1,026

240

Investing activities:

Capital expenditures

(737
)
(572
)
Acquisitions

–

(527
)
Disposal of assets

32

38

Investments – loans and advances

(20
)
–

– repayments of loans and return of capital

15

87

Investing activities of discontinued operations

–

(26
)
All other, net

(1
)
13

Net cash used in investing activities

(711
)
(987
)
Financing activities:

Debt repayments

(10
)
(302
)
Issuance of common stock

5

8

Purchases of common stock

(452
)
(229
)
Excess tax benefits from stock-based compensation arrangements

13

10

Dividends paid

(138
)
(121
)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited

27

30

Net cash used in financing activities

(555
)
(604
)
Effect of exchange rate changes on cash

2

3

Net decrease in cash and cash equivalents

(238
)
(1,348
)
Cash and cash equivalents at beginning of period

2,585

2,617

Cash and cash equivalents at end of period

$
2,347

$
1,269

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

MARATHO~~MARATHON~~N 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 79 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 ~~provides~~provided that beneficial interests in securitized financial assets are not subject to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and eliminates the restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. Effective January 1, 2007, Marathon adopted the provisions of SFAS No. 155 prospectively for all financial instruments acquired or issued on or after January 1, 2007. Adoption of this statement did not have a significant effect on Marathon’s consolidated results of operations, financial position or cash flows.

3. Deconsolidation of Equatorial Guinea LNG Holdings Limited

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

4. Common Stock Split

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

5. Discontinued Operations

On June 2, 2006, Marathon sold its Russian oil exploration and production businesses in the Khanty-Mansiysk region of western Siberia. A gain on the sale of $243 million ($342 million before income taxes) was reported in discontinued operations in the second quarter of 2006. ~~The final adjustment~~During the second quarter of 2007, adjustments to the sales price ~~is expected to be made in 2007~~were substantially completed and ~~could affect~~an additional gain on the ~~reported gain.~~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 ~~the first quarter of~~ 2006. Revenues ~~applicable to discontinued operations were $98 million~~ and pretax income from discontinued operations ~~was $21~~were $173 million ~~for~~and $45 million in the first ~~quarter~~nine months of 2006.

4.6. 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.

First Quarter Ended March 31,

2007

2006

(In millions, except per share data)

Basic

Diluted

Basic

Diluted

Income from continuing operations

$
717

$
717

$
771

$
771

Discontinued operations

–

–

13

13

Net income

$
717

$
717

$
784

$
784

Weighted average common shares outstanding

344

344

365

365

Effect of dilutive securities

–

3

–

3

Weighted average common shares, including dilutive effect

344

347

365

368

Per share:

Income from continuing operations

$
2.08

$
2.07

$
2.11

$
2.09

Discontinued operations

$
–

$
–

$
0.04

$
0.04

Net income per share

$
2.08

$
2.07

$
2.15

$
2.13

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

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

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

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

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

5.7. Segment Information

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

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

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

3) Integrated Gas (“IG”) –— markets and transports products manufactured from natural gas, such as ~~liquefied natural gas (“LNG”)~~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 35 above, the Russian businesses sold in June 2006 were accounted for as discontinued operations. Segment information for the first ~~quarter~~nine months of 2006 excludes the ~~amounts~~operating results for these Russian operations.

(In millions)

E&P

RM&T

IG

Total

First Quarter Ended March 31, 2007

Revenues:

Customer

$
1,705

$
10,767

$
56

$
12,528

Intersegment (a)

140

1

–

141

Related parties

4

316

–

320

Segment revenues

1,849

11,084

56

12,989

Elimination of intersegment revenues

(140
)
(1
)
–

(141
)
Gain on long-term U.K. natural gas contracts

21

–

–

21

Total revenues

$
1,730

$
11,083

$
56

$
12,869

Segment income

$
385

$
345

$
19

$
749

Income from equity method investments

41

41

25

107

Depreciation, depletion and amortization (b)

242

141

1

384

Minority interests in loss of subsidiary

–

–

(2
)
(2
)
Provision for income taxes (b)

414

198

8

620

Capital expenditures (c)

461

217

57

735

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

(In millions)

E&P

RM&T

IG

Total

First Quarter Ended March 31, 2006

Revenues:

Customer

$
2,108

$
13,890

$
30

$
16,028

Intersegment (a)

190

13

–

203

Related parties

3

309

–

312

Segment revenues

2,301

14,212

30

16,543

Elimination of intersegment revenues

(190
)
(13
)
–

(203
)
Gain on long-term U.K. natural gas contracts

78

–

–

78

Total revenues

$
2,189

$
14,199

$
30

$
16,418

Segment income

$
465

$
319

$
8

$
792

Income from equity method investments

53

26

13

92

Depreciation, depletion and amortization (b)

256

133

2

391

Minority interests in loss of subsidiary

–

–

(3
)
(3
)
Provision for income taxes (b)

480

204

5

689

Capital expenditures (c)

358

104

94

556

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

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

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

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

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

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

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

First Quarter Ended March 31,

(In millions)

2007

2006

Segment income

$
749

$
792

Items not allocated to segments, net of income taxes:

Corporate and other unallocated items

(43
)
(66
)
Gain on long-term U.K. natural gas contracts

11

45

Discontinued operations

–

13

Net income

$
717

$
784

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

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

6.8. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

First Quarter Ended March 31,

Pension Benefits

Other Benefits

(In millions)

2007

2006

2007

2006

Service cost

$
33

$
34

$
5

$
6

Interest cost

34

32

11

10

Expected return on plan assets

(38
)
(26
)
–

–

Amortization:

– prior service cost (credit)

3

1

(2
)
(3
)
– actuarial loss

5

13

2

2

Net periodic benefit cost

$
37

$
54

$
16

$
15

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

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

During the first ~~quarter~~nine months of 2007, Marathon made contributions of ~~$40~~$80 million to its ~~international~~ funded pension plans, including $50 million related to international plans. Marathon expects to make additional contributions of approximately ~~$10~~$5 million to its funded pension plans over the remainder of 2007. Contributions made from the general assets of Marathon to cover current benefit payments related to unfunded pension and other postretirement benefit plans were $2$12 million and $7$26 million during the first ~~quarter~~nine months of 2007.

7.9. Income Taxes

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

					Third Quarter Ended				Nine Months Ended
	First Quarter Ended March 31,				September 30,				September 30,
	2007		2006		2007		2006		2007		2006
Statutory U.S. income tax rate	35	%	35	%	35.0	%	35.0	%	35.0	%	35.0	%
Effects of foreign operations, including foreign tax credits	11		11		6.9		9.2		8.5		9.9
State and local income taxes, net of federal income tax effects	2		2		1.5		2.9		1.9		2.3
Other tax effects	(2	)	(1	)	(1.8	)	(2.1	)	(1.4	)	(1.3	)
Effective income tax rate for continuing operations	46	%	47	%	41.6	%	45.0	%	44.0	%	45.9	%

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

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

United ~~States~~ ~~(a)~~States(a)		1999 –- 2006
Equatorial Guinea	~~1997 –~~	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.

8.10. Comprehensive Income

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

First Quarter Ended March 31,

(In millions)

2007

2006

Net income

$
717

$
784

Other comprehensive income, net of taxes:

Minimum pension liability adjustments

–

10

Defined benefit postretirement plans

36

–

Other

2

–

Comprehensive income

$
755

$
794

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

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

9.11. Inventories ~~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.

March 31,

December 31,

(In millions)

2007

2006

Liquid hydrocarbons and natural gas

$
1,567

$
1,136

Refined products and merchandise

1,746

1,812

Supplies and sundry items

223

225

Total, at cost

$
3,536

$
3,173

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

~~10.~~12. Property, Plant and Equipment

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

13. Long-term Debt

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

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

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

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

14. Stock-Based Compensation Plans

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

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

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

15. Leases

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

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

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

16. Commitments and Contingencies

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

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

Contract commitments – — At ~~March 31,~~September 30, 2007 and December 31, 2006, Marathon’s contract commitments to acquire property, plant and equipment totaled ~~$2.242~~$2.459 billion and $1.703 billion. During the first ~~quarter~~nine months of 2007, the majority of additional contract commitments were related to the expansion of the Company’s Garyville, Louisiana, refinery.

~~11.~~ ~~Stock~~17. Share Repurchase Program

OnIn January ~~29,~~ 2006, Marathon’s Board of Directors authorized the repurchase of up to $2 billion of common stock. ~~On January 28, 2007, the~~The share repurchase program was extended by $500 million in January 2007, by an additional $500 ~~million.~~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 ~~March 31,~~September 30, 2007, the Company had acquired ~~25.8~~57 million common shares at a cost of ~~$2.150~~$2.497 billion under the program, including 516 million common shares acquired during the first ~~quarter~~nine months of 2007 at a cost of ~~$452~~$800 million.

~~12.~~18. Supplemental Cash Flow Information

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

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

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

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

First Quarter Ended March 31,

(In millions)

2007

2006

Net cash provided from operating activities included:

Interest paid (net of amounts capitalized)

$
52

$
74

Income taxes paid to taxing authorities

489

596

Commercial paper and revolving credit arrangements, net:

Borrowings

$
–

$
197

Repayments

–

(197
)

~~13.~~19. Subsequent Event

On ~~April 25,~~October 18, 2007, Marathon completed the acquisition of all the outstanding shares of Western Oil Sands Inc. (“Western”) for cash and securities of approximately $5.8 billion. Western shareholders received cash of 3.808 billion Canadian dollars and 34.3 million shares of Marathon common stock or securities exchangeable for Marathon common stock. Western’s outstanding debt was approximately $1.1 billion at closing. The acquisition will be accounted for under the purchase method of accounting and, as such, Marathon’s ~~stockholders approved an increase~~results of operations will include Western’s results from October 18, 2007. Western’s oil sands mining operations will be reported as a separate segment and its exploration and production operations will be included in the 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 will be effectedE&P segment beginning in the ~~form~~fourth quarter of ~~a stock dividend to be distributed on June 18, 2007, to stockholders of record at the close of business on May 23,~~ 2007. ~~Stockholders will receive 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.~~

Common share and per share information has not been restated in the accompanying consolidated financial statements and notes to reflect the stock split. This information will be restated in Marathon’s consolidated financial statements to reflect the stock split once the shares are distributed. The following proforma information reflects the impact of the stock split on income per share for the first quarters of 2007 and 2006.

First Quarter Ended March 31,

2007

2006

(In millions, except per share data)

Basic

Diluted

Basic

Diluted

Income from continuing operations

$
717

$
717

$
771

$
771

Discontinued operations

–

–

13

13

Net income

$
717

$
717

$
784

$
784

Weighted average common shares outstanding

689

689

730

730

Effect of dilutive securities

–

5

–

7

Weighted average common shares, including dilutive effect

689

694

730

737

Per Share:

Income from continuing operations

$
1.04

$
1.03

$
1.05

$
1.04

Discontinued operations

$
–

$
–

$
0.02

$
0.02

Net income per share

$
1.04

$
1.03

$
1.07

$
1.06

~~14.~~20. Accounting Standards Not Yet Adopted

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

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

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

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

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

Marathon holds a 60 percent interest in Equatorial Guinea LNG Holdings Limited (“EGHoldings”). The remaining interests are held by Sociedad Nacional de Gas de Guinea Equatorial (“SONAGAS”) (25 percent interest), Mitsui & Co., Ltd. (8.5 percent interest) and a subsidiary of Marubeni Corporation (6.5 percent interest). ~~Unless~~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, amounts for the Integrated Gas segment include amounts related to these minority~~ interests.

Overview and Outlook

Operational and Corporate Highlights

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

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

•Announced seven exploration discoveries in deepwater Angola;

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

·• ~~Progressed~~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 ~~with first production expected by early 2008;~~

· ~~Continued commissioning of~~and the Alvheim/Vilje project inoffshore Norway;

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

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

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

•Continued construction of the ~~110 million gallon per year~~ joint venture ethanol facility in Greenville, ~~Ohio;~~Ohio, and acquired a 35 percent interest in an entity that owns and operates an ethanol facility in Clymers, Indiana;

·• ~~Continued commissioning activities on~~Commenced production at the Equatorial Guinea LNG production ~~facility, with first shipment~~facility;

•Repurchased 16 million common shares, bringing total repurchases to date to 57 million common shares at a cost of ~~LNG expected in the second quarter~~$2.497 billion;

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

•Completed a two-for-one split of ~~2007.~~our common stock.

Exploration and Production (“E&P”)

Net liquid hydrocarbon and natural gas sales during the third quarter and first ~~quarter~~nine months of 2007 averaged ~~339~~371 and 350 thousand barrels of oil equivalent per day (“mboepd”). ~~Sales volumes may vary from production available for sale primarily due to the timing of liquid hydrocarbon liftings and natural gas sales from certain of our international operations.~~

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

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

The ~~Droshky discovery well (previously named Troika Deep)~~Neptune development in the Gulf of Mexico ~~is located~~continues to progress and first production remains on Green Canyon Block 244. One successful appraisal sidetrack well has been drilled and a second lateral appraisal sidetrack well is being drilled, which will complete our appraisal process. This potential development would be through the Troika Unit infrastructure, which is located approximately two miles from the well. We hold a 100 percent interest in the Droshky well and a 50 percent outside-operated interest in the Troika Unit.schedule for early 2008.

Also in Angola, we have participated in five wells on Blocks 31 and 32, the results of which have not been announced. We will announce details related to those wells upon approval of the Angola government.

In Norway, the ~~Alvheim/Vilje development project has entered~~commissioning of the ~~commissioning stage, during which additional work has been identified as necessary to bring the~~Alvheim floating production, storage and offloading ~~vessel~~ (“FPSO”) ~~into~~vessel continues. All subsea infrastructure is in place, three wells are ready for production and electrical testing is underway. The FPSO is expected to sail from Haugesund, Norway in December 2007 with first production, dependent on weather, now anticipated in the first quarter of 2008. Difficult market conditions for skilled labor combined with additional system integration and code compliance ~~with Norwegian codes and regulations and to fully integrate the existing ship systems with the new topside facilities. This additional~~ work ~~along~~delayed expected first production. These factors, together with ~~intense market demand for labor in Norway and~~ additional drilling activity, ~~has~~have contributed to increased overall costs for the project. ~~First production is~~

We now ~~expected in the third quarter of 2007 and a peak net rate of approximately 75 mboepd is expected in 2008.~~

~~Our~~expect 2007 production available for sale, ~~is still expected~~excluding any contribution from our Canadian oil sands operations discussed below under Western Acquisition, to ~~average between 390 and 425 mboepd, excluding the impact of acquisitions and dispositions.~~be approximately 350 mboepd. This ~~wide range considered the possibilities of delays in major project delivery dates; however, it~~ is ~~likely that actual production available for sale for the year will be~~ at the lower end of ~~this range as~~previous estimates due to operational interruptions at the LNG production facility in Equatorial Guinea discussed below under Integrated Gas and the delays in first production at Alvheim. Sales volumes may vary from production available for sale due to the timing of liquid hydrocarbon liftings and natural gas sales.

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

The above discussion includes forward-looking statements with respect to the ~~Alvheim/Vilje and Neptune development projects, the~~ possibility of developing the Droshky discovery in the Gulf of Mexico and Blocks 31 and 32 offshore Angola, the Neptune and the Alvheim/Vilje development projects, the timing and levels of our worldwide liquid hydrocarbon, natural gas, and condensate production available for ~~sale.~~sale and anticipated future exploratory drilling activity. Some factors that could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. Except for the Alvheim/Vilje ~~development,~~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 onof 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 first quarter of 2007, our total refinery~~

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

Catlettsburg, Kentucky and St. Paul Park, Minnesota refineries. Total refinery throughput for the first nine months of 2007 was two percent higher than the same period of 2006. Our refining and wholesale marketing gross margin averaged 17.17 cents per gallon and 23.17 cents per gallon in the third quarter and first nine months of 2007 compared to 32.71 cents per gallon and 24.78 cents per gallon in the comparable periods of 2006. The declines in both periods are primarily due to crude oil prices, which increased significantly during the third quarter of 2007 while falling substantially during the third quarter of 2006. For example, the average Light Louisiana Sweet crude oil price increased over $6 per barrel in the third quarter of 2007 compared to a decline of $12 per barrel in the same quarter of 2006. Favorably impacting our refining and wholesale marketing gross margin per gallon ~~was higher in~~for the first ~~quarter~~nine months of 2007 ~~than the comparable period of 2006, however, the increase~~ was ~~primarily the result of~~ the change in accounting for matching buy/sell arrangements effective April 1, 2006, as the sales volumes recognized ~~during~~in the first ~~quarter~~nine months of 2007 were less than the volumes that would have been recognized under previous accounting practices. Our ~~refining and wholesale marketing gross margin averaged 12.46 cents per gallon in the first quarter of 2007 versus 11.37 cents per gallon in the first quarter of 2006. Our~~ ethanol blending program increased to 3741 thousand barrels per day (“mbpd”) in the ~~first~~third quarter of 2007 from 3036 mbpd in the ~~first~~third quarter of 2006. The future expansion or contraction of our ethanol blending program will be driven by the economics of the ethanol supply and ~~changes in~~ government regulations.

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

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

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

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

~~Construction~~

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

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

Integrated Gas (“IG”)

~~Our significant integrated gas activities during the first quarter of 2007 related to the~~

The LNG production facility in Equatorial ~~Guinea. Commissioning~~Guinea was completed and delivered its first cargo of LNG in May 2007. As scheduled, the production facility was shutdown in June 2007 for a performance test which confirmed the facility’s capacity of 3.7 million metric tonnes per annum and again in July for commissioning maintenance. The facility returned to production later that month for the remainder of the third quarter and produced LNG at a rate of 93 percent of design capacity for the quarter. Following the detection of a minor leak, the facility ~~continues~~was shut down on October 4, 2007. Warranty repairs have commenced and ~~the first shipments of~~ LNG ~~are~~production is expected ~~in the second quarter of~~to resume between mid-November and early December 2007. ~~We own a 60 percent interest in EGHoldings.~~

Once the LNG production facility ~~commences~~commenced its ~~principal~~primary operations and ~~begins~~began to generate revenue in May 2007, EGHoldings ~~will~~was no longer be a variable interest ~~entity (“VIE”). We consolidate EGHoldings because it is a VIE and~~entity. Effective May 1, 2007, we ~~are its primary beneficiary. When it ceases to be a VIE we will~~ 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. ~~When~~Our investment in EGHoldings ~~ceases to be a VIE, which~~ is ~~expected in the second quarter of 2007, we will account~~accounted for ~~our interest~~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~~an investment decision in 2008.

The above discussion contains forward-looking statements with respect to the ~~timing~~resumption of ~~production associated with~~operations at the LNG production facility in Equatorial Guinea and the possible expansion ~~thereof. Factors that could affect~~of the LNG production facility. The anticipated operational date of the LNG production facility ~~include unforeseen problems arising from commissioning of the facilities, unforeseen hazards such as weather conditions~~is based on certain factors, including equipment availability and ~~other operating considerations such as shipping the LNG. In addition to these factors, other factors~~customs approval. Factors that could potentially affect the possible expansion of the ~~current LNG production~~ facility and the development of additional LNG capacity through additional projects include partner approvals, access to sufficient natural gas volumes through exploration or commercial negotiations with other resource owners and access to sufficient regasification capacity. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Western Acquisition

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

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

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

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

Capital, Investment and Exploration Budget

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

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

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

Corporate

On April 25, 2007, our Board of Directors declared a two-for-one split of our common stock. The stock split ~~will be~~was effected in the form of a stock dividend ~~to be~~ distributed on June 18, 2007, to stockholders of record at the close of business on May 23, 2007. Stockholders ~~will receive~~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. ~~See Note 13~~Common stock and per share (except par value) information for all periods presented has been restated throughout this Quarterly Report on Form 10-Q to ~~the accompanying condensed consolidated financial statements for proforma information reflecting the impact of~~reflect the stock ~~split on income per share for the first quarters of 2007 and 2006.~~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.

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

Consolidated Results of Operations

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

First Quarter Ended March 31,

(In millions)

2007

2006

E&P

$
1,849

$
2,301

RM&T

11,084

14,212

IG

56

30

Segment revenues

12,989

16,543

Elimination of intersegment revenues

(141
)
(203
)
Gain on long-term U.K. natural gas contracts

21

78

Total revenues

$
12,869

$
16,418

Items included in both revenues and costs and expenses:

Consumer excise taxes on petroleum products and merchandise

$
1,197

$
1,165

Matching crude oil and refined product buy/sell transactions settled in cash:

E&P

–

11

RM&T

58

3,195

Total buy/sell transactions included in revenues

$
58

$
3,206

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

E&P segment revenues ~~decreased $452~~increased $182 million in the ~~first~~third quarter of 2007 from the comparable prior-year ~~period. See Supplemental Statistics for information regarding net sales volumes~~period, primarily as a result of increased crude oil and ~~average realizations by geographic area. Decreased~~ natural gas marketing activities and higher liquid hydrocarbon realizations. Partially offsetting the impact of these increases were declines in liquid hydrocarbon sales volumes and domestic natural gas sales volumes. Decreases in domestic liquid hydrocarbon and natural gas sales volumes primarily reflect normal production declines for our Gulf of Mexico and Permian Basin properties. The lower international liquid hydrocarbon sales volumes were due to 30,000 barrels of oil per day that were produced and sold in the third quarter of 2006 that were owed to our account upon our resumption of operations in Libya. Though it did not have a significant impact on E&P segment revenues, the increase in Equatorial Guinea natural gas sales volumes due to the start-up of the LNG production facility in the second quarter of 2007 contributed to the decline in the average international natural gas realization for the third quarter of 2007.

E&P segment revenues in the first nine months of 2007 decreased $644 million from the comparable prior-year period. Revenue decreases from natural gas marketing activities in the first quarter of 2007 account for ~~the majority~~a substantial portion of the ~~revenue decline. In addition, normal~~decline for the nine-month period. The remainder of the decrease was primarily related to lower liquid hydrocarbon and natural gas sales volumes and realizations. Normal production rate declines, particularly for our Gulf of Mexico properties, caused domestic liquid hydrocarbon and natural gas sales volumes to decrease in the first ~~quarter~~nine months of 2007 compared to the ~~first quarter of 2006. Our average realizations on domestic natural gas decreased 11 percent compared to the first quarter~~same period of 2006, ~~while those on domestic liquid hydrocarbons were flat. Partially offsetting~~and the decline in ~~domestic revenue was an increase in revenues from our international operations. Liquid hydrocarbon sales volumes in~~ Libya ~~were higher in the first quarter of 2007 than in the comparable prior-year period due to the timing of liftings. The impact of increased~~ liquid hydrocarbon sales volumes ~~was partially offset by lower~~for the third quarter discussed above caused the majority of the decrease in international liquid hydrocarbon sales volumes.

See Supplemental Statistics for information regarding net sales volumes and average realizations ~~for both liquid hydrocarbons and natural gas and a 22 percent decline in natural gas sales volumes, primarily in Europe.~~by geographic area.

Excluded from E&P segment revenues were losses of $123 million and gains of ~~$21 million and $78~~$121 million for the ~~first~~third quarters of 2007 and 2006, ~~related to~~on long-term natural gas ~~sales~~ contracts in the United Kingdom ~~that~~which are accounted for as derivative instruments. For the first nine months of 2007 and 2006, losses of $111 million and gains of $182 million are excluded from E&P segment revenues. See Item 3. Quantitative and Qualitative Disclosures About Market Risk.

RM&T segment revenues increased $328 million in the third quarter of 2007 and decreased ~~$3.128~~$3.865 billion in the first ~~quarter~~nine months of 2007 from the comparable prior-year ~~period primarily as a result of the~~periods. The change in accounting for matching buy/sell transactions effective April 1, 2006 ~~discussed above.~~is the primary reason for the revenue decrease in the nine-month period. Excluding matching buy/sell transactions, RM&T segment revenues ~~did not change significantly but~~increased in both periods. The third quarter increase was primarily the result of higher refined product selling prices while the increase for the nine-month period primarily reflected ~~increases in~~increased refined product selling prices and crude oil sales ~~volumes, merchandise revenue and excise taxes, which were almost entirely offset by decreases in the prices realized for refined products.~~volumes.

For information on segment income, see Segment Results.

Cost of revenues ~~for~~ increased $1.734 billion in the ~~first~~third quarter of 2007 ~~decreased $217 million~~and $1.644 billion in the first nine months of 2007 from the comparable prior-year ~~period,~~periods. The increases in both periods are primarily asin the RM&T segment and resulted mainly from higher acquisition costs for crude oil in the third quarter of 2007. Contributing to the cost increase were the higher market prices for crude oil, derivatives losses, a ~~result~~narrowing of the ~~decreased natural gas marketing activities discussed above.~~difference in the acquisition costs for sweet and sour crude oils, and the effects of refining more sweet crude oil.

Purchases related to matching buy/sell transactions decreased ~~$3.172~~$220 million and $5.058 billion in the third quarter and first ~~quarter~~nine months of 2007 from the comparable prior-year ~~period~~periods as a result of the change in accounting for matching buy/sell transactions effective April 1, 2006, discussed above.

~~Net interest~~Exploration expenses were $88 million and $264 million in the third quarter and first nine months of 2007, including expenses related to dry wells of $22 million and $76 million primarily related to exploration activities in Angola. Exploration expenses were $97 million and $234 million in the third quarter and first nine months of 2006, including expenses related to dry wells and other ~~financing costs (income)~~ ~~reflected a net $19~~write-offs of $41 million ~~of income for the first quarter of 2007, a favorable change of $42 million from the net $23 million expense~~and $99 million. The largest increase in exploration expenses in the ~~comparable prior-year period. The favorable changes included greater capitalized interest, increased interest income due~~nine-month period related to ~~higher average cash balances~~geological and geophysical costs.

Gain on foreign currency ~~exchange gains.~~

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

Provision for income taxesdecreased ~~$67~~$604 million and $718 million in the third quarter and first nine months of 2007 from the comparable ~~prior-year period primarily due to the $121 million decrease~~periods of 2006 as a result of effective tax rate declines and decreases in income from continuing operations before income ~~taxes.~~taxes in both periods. The following is an analysis of the effective income tax rates for continuing operations for the third quarters and first ~~quarters~~nine months of 2007 and 2006:

First Quarter Ended March 31,

2007

2006

Statutory U.S. income tax rate

35
%

35
%

Effects of foreign operations, including foreign tax credits

11

11

State and local income taxes, net of federal income tax effects

2

2

Other tax effects

(2
)

(1
)

Effective income tax rate for continuing operations

46
%

47
%

Third Quarter Ended

Nine Months Ended

September 30,

September 30,

2007

2006

2007

2006

Statutory U.S. income tax rate

35.0
%
35.0
%
35.0
%
35.0
%
Effects of foreign operations, including foreign tax credits

6.9

9.2

8.5

9.9

State and local income taxes, net of federal income tax effects

1.5

2.9

1.9

2.3

Other tax effects

(1.8
)
(2.1
)
(1.4
)
(1.3
)
Effective income tax rate for continuing operations

41.6
%
45.0
%
44.0
%
45.9
%

Discontinued operations in ~~the first quarter of~~ 2006 reflects the operations of our ~~former~~ Russian oil exploration and production businesses ~~which~~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 ~~sold in June 2006.~~substantially completed and an additional after-tax gain on the sale of $8 million was recognized. See Note 35 to the accompanying consolidated financial statements for additional information.
22

Segment Results
Segment incomefor the third quarters and first ~~quarters~~nine months of 2007 and 2006 is summarized in the following table.

First Quarter Ended March 31,

(In millions)

2007

2006

E&P:

United States

$
150

$
245

International

235

220

E&P segment

385

465

RM&T

345

319

IG

19

8

Segment income

749

792

Items not allocated to segments, net of income taxes:

Corporate and other unallocated items

(43
)
(66
)
Gain on long-term U.K. natural gas contracts

11

45

Discontinued operations

–

13

Net income

$
717

$
784

Third Quarter Ended

Nine Months Ended

September 30,

September 30,

(In millions)

2007

2006

2007

2006

E&P

United States

$
147

$
218

$
470

$
706

International

332

354

794

990

E&P segment

479

572

1,264

1,696

RM&T

482

1,026

2,073

2,262

IG

52

(2
)
83

23

Segment income

1,013

1,596

3,420

3,981

Items not allocated to segments, net of income taxes:

Corporate and other unallocated items

3

(52
)
(149
)
(217
)
Gain (loss) on long-term U.K. natural gas contracts

(62
)
58

(56
)
93

Gain on foreign currency derivative instruments

74

—

74

—

Loss on early extinguishment of debt

(7
)
—

(9
)
—

U.K. tax legislation

—

21

—

21

Discontinued operations

—

—

8

277

Net income

$
1,021

$
1,623

$
3,288

$
4,155

United States E&P income decreased $71 million, or 33 percent, and $236 million, or 33 percent, in the third quarter and first ~~quarter~~nine months of 2007 ~~decreased $95 million, or 39 percent,~~ compared to the ~~first quarter~~same periods of 2006. Pretax income decreased ~~$150~~$117 million and $393 million in the same periods while the effective income tax rate ~~increased slightly~~remained unchanged at 38 percent in the third quarter and decreased from 3738 percent to ~~38 percent.~~36 percent in the nine-month period. The ~~decrease in~~lower pretax income ~~was~~in both periods is primarily ~~the~~a result of revenue decreases from lower liquid hydrocarbon and natural gas sales volumes, ~~and realized natural gas prices~~ as discussed above.
International E&P income decreased $22 million, or 6 percent, and $196 million, or 20 percent, in the third quarter and first ~~quarter~~nine months of 2007 ~~increased $15~~compared to the same periods of 2006. Pretax income decreased $76 million ~~or 7 percent, from~~and $441 million in the ~~first quarter of 2006, primarily due to~~same periods, while the effective income tax rate ~~decline~~decreased from 6059 percent to 58 ~~percent. International~~percent in the third quarter and increased from 59 percent to 60 percent in the nine-month period. The lower pretax income ~~was flat as~~in both periods is primarily a ~~decrease in exploration expenses and an increase in revenues~~result of revenue decreases from ~~higher~~lower liquid hydrocarbon sales ~~volumes, primarily in Libya and Equatorial Guinea, were mostly~~volumes. In the third quarter of 2007, the impact of the sales volume decline was significantly offset by ~~declines in natural gas sales volumes~~higher realized liquid hydrocarbon prices and ~~in realized prices for liquid hydrocarbons and natural gas.~~lower exploration expenses.
RM&T segment income ~~in the first quarter of 2007 increased $26~~decreased by $544 million, or 53 percent, and $189 million, or 8 percent, ~~from~~in the third quarter and first ~~quarter~~nine months of 2007 compared to the same periods of 2006. Pretax income ~~increased $20~~decreased $938 million and $432 million in the same periods, while the effective income tax rate ~~declined~~decreased from 39 percent to 35 percent in the third quarter and from 39 percent to 36 ~~percent.~~percent in the nine-month period. The ~~increase~~decreases in RM&T pretax income isin both periods are primarily athe result of ~~increases in SSA’s gasoline~~a lower refining and ~~distillates~~wholesale marketing gross margin in the third quarter of 2007. The refining and ~~merchandise gross margin. The SSA gasoline and distillates~~wholesale marketing gross margin averaged ~~12.17~~17.17 cents per gallon in the third quarter of 2007 and 23.17 cents per gallon in the first nine months of 2007 compared to 32.71 cents per gallon and 24.78 cents per gallon in the comparable periods of 2006. The most significant cause of this margin decline was that crude oil prices increased significantly during the third quarter of 2007 while crude oil prices fell substantially in the third quarter of 2006. Our cost of crude oil and other feedstocks increased in the third quarter of 2007 compared to ~~10.55 cents per gallon~~the comparable prior-year quarter due to these higher crude prices, a narrowing of the difference in the ~~first~~acquisition costs for sweet and sour crude oils and the effects of refining more sweet crude oil. In addition, the increase in our wholesale sales price realizations was less than the increase in crude oil and other feedstock costs. Our refining and wholesale marketing gross margin also included derivative losses of $360 million in the third quarter of ~~2006, while~~2007 compared to derivative gains of $384 million in the ~~merchandise gross margin grew~~third quarter of 2006. The change in the impact of derivatives primarily reflects the realized effects of closed derivative positions, but also includes the unrealized effects of marking open derivative positions to ~~$160~~market. These derivatives have an underlying physical commodity transaction; however, the income effect related to the derivatives and the income effect related to the underlying physical transactions are not necessarily recognized in segment income in the same period because we do not attempt to qualify these commodity derivatives for hedge accounting.
23

Crude oil refined averaged 1,042 mbpd and 1,028 mbpd, during the third quarter and first nine months of 2007, 11 mbpd and 39 mbpd higher than the averages for the same periods of 2006.
IG segment income increased $54 million in the third quarter of 2007 and increased $60 million in the first ~~quarter~~nine months of 2007 ~~from $148 million in~~compared to the ~~first quarter of 2006.~~
~~IG segment income~~ ~~in the first quarter of 2007 increased $11 million, or 137 percent, from the first quarter~~same periods of 2006 ~~primarily as a result of~~due to increased income from our equity method investments in EGHoldings and Atlantic Methanol Production Company LLC (“AMPCO”). ~~Average~~The first LNG deliveries from EGHoldings’ LNG production facility in Equatorial Guinea were made in the second quarter of 2007. Income from AMPCO for the third quarter of 2007 increased as the plant was shut down for a portion of the third quarter of 2006. Higher methanol prices ~~realized by AMPCO were 48 percent higher~~ in the first quarter of 2007 ~~than they were~~also contributed to the increase in income from AMPCO for the ~~comparable quarter~~first nine months of ~~2006.~~2007.

Management’s Discussion and Analysis of Cash Flows and Liquidity
Cash Flows
Net cash provided from operating activities totaled ~~$1.026~~$2.951 billion in the first ~~quarter~~nine months of 2007, compared to ~~$240 million~~$3.745 billion in the first ~~quarter~~nine months of 2006. ~~The $786 million increase reflects the impact of various working capital changes during the quarters.~~
Net cash used in investing activitiestotaled ~~$711 million~~$2.609 billion in the first ~~quarter~~nine months of 2007, compared to ~~$987 million~~$1.852 billion in the first ~~quarter~~nine months of 2006. Capital expenditures were ~~$737 million~~$2.725 billion compared ~~to $572 million~~with $2.405 billion for the comparable prior-year period, with the increased spending primarily related ~~primarily~~ to ~~the Neptune development project in the E&P segment and~~ the Garyville refinery expansion in the RM&T segment and the Neptune development in the E&P segment. ~~For~~See Supplemental Statistics for information regarding capital expenditures by ~~segment, refer~~segment. Investing activities for the first nine months of 2007 also included $163 million withdrawn from the trusteed proceeds of the revenue bonds associated with our Garyville, Louisiana refinery expansion. As discussed below, the proceeds from these bonds were held in trust at issuance and therefore were not reflected as a borrowing in the accompanying consolidated statement of cash flows for the first nine months of 2007. When the funds are released to ~~Supplemental Statistics. Cash~~us in reimbursement of expenditures associated with the expansion, the cash inflow is presented as part of investing activities. Investing activities for the first nine months of 2006 also included net cash proceeds of $832 million from the sale of our Russian oil exploration and production businesses in June 2006 and cash paid for acquisitions ~~in the first quarter~~ of ~~2006 were $527~~$543 million, primarily related to the initial $520 million payment associated with our 2005 re-entry into Libya.
Net cash ~~used in~~provided by financing activities was ~~$555~~$333 million in the first ~~quarter~~nine months of 2007, compared to ~~$604 million~~$1.726 billion used by financing activities in the first ~~quarter~~nine months of 2006. Significant uses of cash in financing activities during both periods included stock repurchases, repayments of maturing debt and dividend payments. ~~In 2006, we also repaid our $300~~Financing activities for the first nine months of 2007 included the issuance of $1.5 billion in senior notes and borrowings of $578 million ~~6.65% notes that matured during that quarter.~~from the Norwegian export credit agency.
Dividends to Stockholders
On ~~April 25,~~October 31, 2007, our Board of Directors declared a dividend of 4824 cents per share, ~~on our common stock,~~ payable ~~June 11,~~December 10, 2007, to stockholders of record at the close of business on ~~May 16,~~November 21, 2007.
Derivative Instruments
See ~~Item 3.~~ Quantitative and Qualitative Disclosures About Market Risk for a discussion of derivative instruments and associated market risk.
Liquidity and Capital Resources
Our main sources of liquidity and capital resources are internally generated cash flow from operations, committed credit facilities and access to both the debt and equity capital markets. Our ability to access the debt capital market is supported by our investment grade credit ratings. Our senior unsecured debt is currently rated investment grade by Standard and Poor’s Corporation, Moody’s Investor Services, Inc. and Fitch Ratings, with ratings of BBB+, Baa1 and BBB+. These ratings were affirmed in July 2007 after the Western acquisition was announced. Because of the liquidity and capital resource alternatives available to us, including internally generated cash flow, we believe that our short-term and long-term liquidity is adequate to fund operations, including our capital spending programs, stock repurchase program, repayment of debt maturities and any amounts that may ultimately be paid in connection with contingencies.
We have a committed ~~$2.0~~$3.0 billion revolving credit facility with third-party financial institutions terminating in May ~~2011. We are in the process of working with the third-party financial institutions to extend the term of the revolving credit~~2012. This facility ~~by one year to May 2012. We expect an amendment reflecting such one year extension will be executed during the second quarter of 2007~~was expanded from $2.0 billion on October 4, 2007. At ~~March 31,~~September 30, 2007, there were no borrowings against this facility and we had no commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.
24

On July 26, 2007, we filed a universal shelf registration statement with the Securities and Exchange Commission, under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.
On September 27, 2007, Marathon issued $750 million aggregate principal amount of senior notes bearing interest at 6.0 percent with a maturity date of October 1, 2017, and $750 million aggregate principal amount of senior notes bearing interest at 6.6 percent with a maturity date of October 1, 2037. Interest on the senior notes is payable semi-annually beginning April 1, 2008. The ~~Gulf Opportunity Zone Act~~$1.5 billion of ~~2005 established certain incentives~~proceeds were used to ~~support~~fund a portion of the ~~rebuilding~~purchase price for the Western acquisition.
On June 26, 2007, the Parish of ~~local and regional economies in Louisiana, Mississippi and Alabama that were impacted by the hurricanes of 2005. Included in the impacted area is~~ St. John the Baptist, ~~Parish,~~ where our Garyville, Louisiana, refinery is ~~located. The Louisiana State Bond Commission has approved the parish’s application to issue up to $1~~located, issued $1.0 billion of ~~bonds~~5.125 percent Fixed Rate Revenue Bonds (Marathon Oil Corporation Project) Series 2007A associated with the Garyville refinery ~~expansion. Upon obtaining final approvals, we expect~~expansion, with a maturity date of June 1, 2037. We are solely obligated to service the ~~parish to issue~~principal and interest payments associated with the bonds. The proceeds from the bonds ~~by the end of the third quarter of 2007. Following the issuance, the proceeds will~~were held in trust to be ~~trusteed and~~ disbursed to us upon our request for reimbursement of expenditures related to the Garyville refinery expansion. ~~We will be solely obligated~~Through September 30, 2007, such reimbursements have totaled $163 million.The $1.0 billion obligation is reflected as long-term debt and the $848 million of trusteed funds, including interest income earned to ~~service~~date, is reflected as other noncurrent assets in the ~~principal and interest payments associated with the bonds.~~consolidated balance sheet as of September 30, 2007.
~~During 2006~~
On June 15, 2007, we ~~entered into~~borrowed $578 million under a loan agreement ~~which allows borrowings of up to $525 million~~ from Eksportfinans ASA, the Norwegian export credit agency, based upon the amount of qualifying purchases of goods and services ~~that we make~~by us from Norwegian ~~suppliers.~~contractors. The original loan agreement allows us to select either a fixed or LIBOR-based floating interest rate at the time of the initial drawdown and a five-year or eight and one half-year repayment term. The agreement allows an initial drawdownthat was executed in 2006 was amended in June 2007 ~~and we intend~~ to ~~draw the entire~~provide for an increase in borrowing capacity from $525 million ~~available at that date.~~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.
As of March 31, 2007, there was $1.7 billion aggregate amount of common stock, preferred stock and other equity securities, debt securities, trust preferred securities or other securities, including securities convertible into or exchangeable for other equity or debt securities, available to be issued under our $2.7 billion universal shelf registration statement filed in 2002.

Our consolidated cash-adjusted debt-to-capital ratio (total debt-minus-cash and trusteed funds to total ~~debt-plus-equity-minus-cash)~~debt-plus-equity-minus-cash and trusteed funds) was ~~seven~~11 percent at ~~March 31,~~September 30, 2007, compared to six percent at year-end 2006 as shown below. This includes ~~$517~~$508 million of debt that is serviced by United States Steel Corporation (“United States Steel”).

March 31,

December 31,

(Dollars in millions)

2007

2006

Long-term debt due within one year

$
873

$
471

Long-term debt

2,654

3,061

Total debt

$
3,527

$
3,532

Cash

$
2,347

$
2,585

Equity

$
14,792

$
14,607

Calculation:

Total debt

$
3,527

$
3,532

Minus cash

2,347

2,585

Total debt minus cash

1,180

947

Total debt

3,527

3,532

Plus equity

14,792

14,607

Minus cash

2,347

2,585

Total debt plus equity minus cash

$
15,972

$
15,554

Cash-adjusted debt-to-capital ratio

7%

6%

(Dollars in millions)

September 30,
2007

December 31,
2006

Long-term debt due within one year

$
423

$
471

Long-term debt

5,678

3,061

Total debt

$
6,101

$
3,532

Cash

$
3,269

$
2,585

Trusteed funds from revenue bonds (a)

$
848

$
—

Equity

$
16,682

$
14,607

Calculation:

Total debt

$
6,101

$
3,532

Minus cash

3,269

2,585

Minus trusteed funds from revenue bonds

848

—

Total debt minus cash

1,984

947

Total debt

6,101

3,532

Plus equity

16,682

14,607

Minus cash

3,269

2,585

Minus trusteed funds from revenue bonds

848

—

Total debt plus equity minus cash

$
18,666

$
15,554

Cash-adjusted debt-to-capital ratio

11
%
6
%
(a)Following the issuance of the $1.0 billion of revenue bonds by the Parish of St. John the Baptist, the proceeds were trusteed and will be disbursed to us upon our request for reimbursement of expenditures related to the Garyville refinery expansion. The trusteed funds are reflected as other noncurrent assets in the accompanying consolidated balance sheet as of September 30, 2007.
On October 18, 2007, we completed the acquisition of Western as discussed in Overview and Outlook above. As part of this transaction, we paid Western shareholders cash of 3.808 billion Canadian dollars. These payments were funded from existing cash balances, proceeds from the senior notes discussed above and the issuance of commercial paper. At the closing date, Western’s outstanding debt totaled approximately $1.1 billion, primarily composed of (i) senior secured notes with a face value of $450 million and a fair value of $499 million, bearing interest at 8.375 percent with a maturity date of May 1, 2012 and (ii) an 805 million Canadian dollar secured revolving credit facility terminating June 21, 2012 with $514 million outstanding. Both the senior notes and the revolving credit facility are secured by Western’s interest
25
in the AOSP. At completion of the acquisition, we estimated our cash-adjusted debt-to-capital ratio in the mid-20 percent range.
Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Estimates may differ from actual results. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The ~~availability of~~cash-adjusted debt-to-capital ratio estimate is preliminary and therefore subject to change. Actual results may differ materially from the ~~Gulf Opportunity Zone bonds could further be affected by the inability to obtain or delay in obtaining the necessary government approvals.~~estimate.
~~Stock~~Share Repurchase Program
~~Our~~
        Since January 2006, our Board of Directors has authorized a common share repurchase program totaling ~~$2.5~~$5 billion. As of ~~March 31,~~September 30, 2007, we had repurchased ~~25.8~~57 million common shares at a cost of ~~$2.150~~$2.497 billion. ~~We anticipate completing the remaining purchases during the first half of 2007.~~ 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 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’s authorization does not include specific price targets or timetables; however, we intend to complete the authorized purchases by the end of 2009. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales and cash from available borrowings.
The forward-looking statements about our common ~~stock~~share repurchase program are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially are changes in prices of and demand for crude oil, natural gas and refined products, actions of competitors, disruptions or interruptions of our production or refining operations due to unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, ~~thereto,~~ and other operating and economic considerations.
Contractual Cash Obligations
As of ~~March 31,~~September 30, 2007, our ~~purchase~~consolidated contractual cash obligations ~~under crude oil, refinery feedstock, refined product and ethanol contracts~~have increased ~~approximately $1.401~~by $4.367 billion from December 31, ~~2006, primarily as a result~~2006.    Long-term debt increased by $2.552 billion due to the senior notes, revenue bonds and Norwegian borrowings discussed above, net of ~~higher refined product volumes. Otherwise, there~~debt repayments. Commitments under service and materials contracts increased $746 million due to contracts entered for drilling rigs in the continental United States and in the Gulf of Mexico. Contractual commitments to acquire property, plant and equipment increased $756 million, with the majority of additional contractual commitments related to the expansion of the Garyville, Louisiana refinery. There have been no other significant changes to our obligations to make future payments under existing contracts subsequent to December 31, 2006. The portion of our obligations to make future payments under existing contracts that have been assumed by United States Steel has not changed significantly subsequent to December 31, 2006.
Off-Balance Sheet Arrangements
Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital ~~resources;~~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 ~~$340~~$381 million as of ~~March 31,~~September 30, 2007. Of this amount, ~~$218~~$198 million relates to Pilot Travel Centers LLC (“PTC”). If any of these investees default, we have no obligation to support the debt. Our partner in PTC has guaranteed $75 million of the total PTC debt.
26
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 ~~March 31,~~September 30, 2007, we have obligations totaling ~~$556~~$546 million that have been assumed by United States Steel. Of this amount, obligations of ~~$525~~$520 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet (current portion - ~~$30~~$35 million; long-term portion - ~~$495~~$485 million). The remaining ~~$31~~$26 million was related to off-balance sheet arrangements and contingent liabilities of United States Steel.
Environmental Matters
We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil, refined products and feedstocks.
Air
We previously estimated that we would spend approximately $400 million over a four-year period beginning in 2008 to comply with Mobile Source Air Toxics II regulations relating to benzene. We have not finalized our strategy or cost estimates to comply with these recently promulgated requirements, but the cost estimates will increase and may be approximately $1 billion over a three-year period beginning in 2008. The cost estimates have increased due to better definition of the projects needed to meet the requirements of the finalized regulations and updated construction cost estimates. The costs estimates are subject to change as front-end engineering and design is completed in 2008.
The U.S. Environmental Protection Agency (“EPA”) is in the process of implementing regulations to address current National Ambient Air Quality Standards (“NAAQS”) for fine particulate emissions and ozone. In connection with these standards, the EPA will designate certain areas as “nonattainment,” meaning that the air quality in such areas does not meet the NAAQS. To address these nonattainment areas, the EPA proposed a ~~defendant, along~~rule in 2004 called the Interstate Air Quality Rule (“IAQR”) that would require significant emissions reductions in numerous states. The final rule, promulgated in 2005, was renamed the Clean Air Interstate Rule (“CAIR”). While the EPA expects that states will meet their CAIR obligations by requiring emissions reductions from electric generating units, states will have the final say on what sources they regulate to meet attainment criteria. Our refinery operations are located in affected states and some of these states may choose to propose more stringent fuels requirements to meet the CAIR. Also, on July 11, 2007, the EPA proposed a revised ozone standard. Once the revised ozone standard is promulgated, the EPA will begin the multi-year process to develop the implementing rules required by the Clean Air Act. We cannot reasonably estimate the final financial impact of the state actions to implement the CAIR until the states have taken further action and we cannot reasonably estimate the final financial impact of the revised ozone standard until the implementing rules are established.
We now plan to spend approximately $350 million from 2006 through 2011 on refinery investments to produce ultra-low sulfur diesel fuel for off-road use, in compliance with ~~many other companies with refining operations, in over 50 cases in 12 states alleging methyl-tertiary butyl ether (“MTBE”) contamination in groundwater. We continue~~previously disclosed EPA regulations that require reduced sulfur levels for diesel fuel. This is a forward looking statement. Some factors (among others) that could potentially affect diesel fuel compliance costs include completion of project detailed engineering, construction and start-up activities.
For information on legal proceedings related to ~~defend these cases vigorously.~~
~~There have been no other significant changes to our~~ environmental matters, ~~subsequent to December 31, 2006.~~see Part II, Item 1. Legal Proceedings.
27
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.~~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.
20
28
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 ~~manage~~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 ~~has~~ 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:
o•                  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,
o•                  on fixed price contracts for ethanol purchases, and
o•                  ~~associated with anticipated natural gas purchases for refinery use, and~~
oassociated with freight on crude oil, feedstocks and refined product deliveries;
·•      to protect the value of excess refined product, crude oil and liquefied petroleum gas inventories;
·•      to protect margins associated with future fixed price sales of refined products to non-retail customers;
·•      to protect against decreases in future crack spreads; and
·•      to take advantage of trading opportunities identified in the commodity markets.
        Effective October 18, 2007, as a result of the acquisition of Western previously discussed, our oil sands mining segment uses commodity derivative instruments, such as put and call options, selectively to protect against price decreases on portions of our future production from the AOSP.
We use financial derivative instruments to manage certain interest rate exposures and foreign currency exchange rate exposures on certain foreign currency denominated capital expenditures, operating expenses and tax payments.
We believe that our use of derivative instruments, along with risk assessment procedures and internal controls, does not expose us to material risk. However, the use of derivative instruments could materially affect our results of operations in particular quarterly or annual periods. We believe that the use of these instruments will not have a material adverse effect on our ~~consolidated~~ financial position or liquidity.
29
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 ~~commodity~~ instruments as of ~~March 31,~~September 30, 2007 isare 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)

34
(e)

84
(e)

Refined products (d)

27
(e)

70
(e)

Incremental Decrease in IFO Assuming a Hypothetical Price Change of(a):

(In millions)

10%

25%

Commodity Derivative Instruments:(b)(c)

Crude oil(d)

$
204
(e)

$
509
(e)

Natural gas(d)

53
(e)

132
(e)

Refined products(d)

47
(e)

120
(e)

(a)We remain at risk for possible changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying physical commodity. Effects of these offsets are not reflected in the sensitivity analysis. Amounts reflect hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at ~~March 31,~~September 30, 2007. Included in the natural gas impacts shown above are ~~$38~~$58 million and ~~$95~~$145 million related to the long-term U.K. natural gas contracts accounted for as derivative instruments for hypothetical price changes of 10 percent and 25 percent. We evaluate our portfolio of derivative commodity instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed continuously and master netting agreements are used when practical. Changes to the portfolio after ~~March 31,~~September 30, 2007, would cause future IFO effects to differ from those presented in ~~this~~the table.
(b)The number of net open contracts for the E&P segment varied throughout the ~~first~~third quarter of 2007, from a low of ~~746~~367 contracts on ~~March 31,~~August 17, 2007, to a high of ~~1,475~~899 contracts on ~~March 15,~~September 30, 2007, and averaged ~~1,285~~662 for the quarter. The number of net open contracts for the RM&T segment varied throughout the ~~first~~third quarter of 2007, from a low of 228,387 contracts on ~~February 7,~~July 17, 2007 to a high of ~~7,742~~31,872 contracts on ~~January 17,~~September 24, 2007, and averaged ~~2,612~~21,672 for the quarter. The derivative commodity instruments used and positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.
(c)The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated. Gains and losses on options are based on changes in intrinsic value only.
(d)The direction of the price change used in calculating the sensitivity amount for each commodity reflects that which would result in the largest incremental decrease in IFO when applied to the commodity derivative instruments used to hedge that commodity.
(e)Price increase.
E&P Segment
Derivative losses of ~~$30~~$18 million and gains of ~~$15~~$27 million were included in E&P segment income for the first ~~quarters~~nine months of 2007 and 2006, and were primarily related to derivatives ~~utilize~~utilized to protect the value of natural gas in storage and ~~in transit.~~margins on natural gas purchases for resale. Excluded from E&P segment income were losses of $111 million and gains of ~~$21 million and $78~~$182 million for the first ~~quarters~~nine months of 2007 and 2006 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.
At ~~March 31,~~September 30, 2007, we had no open derivative commodity contracts related to our oil and natural gas production, and therefore ~~remained~~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 ~~derivative~~ 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.
30

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

First Quarter Ended March 31,

(In millions)

2007

2006

Strategy:

Mitigate price risk

$
52

$
4

Protect carrying values of excess inventories

(25
)
(16
)
Protect margin on fixed price sales

2

4

Protect crack spread values

(2
)
(3
)
Subtotal, non-trading activities

27

(11
)
Trading activities

(1
)
5

Total net derivative gains (losses)

$
26

$
(6
)

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

(In millions)

2007

2006

2007

2006

Strategy:

Mitigate price risk

$
(203
)
$
180

$
(222
)
$
75

Protect carrying values of excess inventories

(161
)
208

(237
)
130

Protect margin on fixed price sales

1

(11
)
4

(1
)
Protect crack spread values

3

7

(17
)
2

Subtotal, non-trading activities

(360
)
384

(472
)
206

Trading activities

(2
)
2

2

—

Total net derivative gains (losses)

$
(362
)
$
386

$
(470
)
$
206

Derivatives used in non-trading activities have an underlying physical commodity transaction. Since the majority of RM&T segment derivative contracts are for the sale of commodities, derivative losses generally occur when market prices increase and typically are offset over time by gains on the underlying physical commodity transactions. Conversely, derivative gains generally occur when market prices decrease and are typically offset over time by losses on the underlying physical commodity transactions. The income effect related to the derivatives and the income effect related to the underlying physical transactions may not necessarily be recognized in net income in the same period because we do not attempt to qualify these commodity derivatives for hedge accounting.
Oil Sands Mining Segment
We have not attempted to qualify commodity derivative instruments outstanding upon the acquisition of Western for hedge accounting. As a result, we will recognize in net income all changes in the fair value of those derivatives.
Western purchased put options at strike prices ranging from $50.00 to $55.00 per barrel, averaging $52.42 per barrel for the three-year period beginning January 1, 2007. The premiums for the purchased put options were partially offset through the sale of call options at strike prices ranging from $90.00 to $95.00 per barrel, averaging $92.41 per barrel for the three-year period beginning January 1, 2007, resulting in a net premium liability. Payment of the net premium liability is deferred until the settlement of the option contracts between 2007 and 2009. The counterparties to these put and call options have investment grade credit ratings, thereby partially mitigating the credit risk associated with these financial instruments.
Other Commodity Related Risks
We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. For example, natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets, such as the New York Mercantile Exchange (“NYMEX”) contracts for natural gas that are priced at Louisiana’s Henry Hub, while the underlying quantities of natural gas may be produced and sold in the western United States at prices that do not move in strict correlation with NYMEX prices. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased exposure to basis risk. These regional price differences could yield favorable or unfavorable results. Over-the-counter transactions are being used to manage exposure to a portion of basis risk.
We are impacted by liquidity risk, caused by timing delays in liquidating contract positions due to a potential inability to identify a counterparty willing to accept an offsetting position. Due to the large number of active participants, liquidity risk ~~exposure~~ is relatively low for exchange-traded transactions.
31

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 ~~March 31,~~September 30, 2007 is provided in the following table:
(In millions)

Fair Value

Incremental Change in
Fair Value
Financial assets (liabilities):(a)

Receivable from United States Steel

$
525

$
11

Interest rate swap agreements

$
(17
) (b)

$
8
(c)
Long-term debt, including amounts due within one year

$
(3,710
) (b)

$
(128
) (c)
(In millions)

Fair Value

Incremental Change in
Fair Value

Financial assets (liabilities):(a)

Receivable from United States Steel

$
504

$
10

Interest rate swap agreements

(11
)(b)
5
(c)
Long-term debt, including amounts due within one year

(6,085
)(b)
(329
)(c)
(a)Fair values of cash and cash equivalents, receivables, notes payable, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
(b)Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
(c)For interest rate swap agreements, this assumes a 10 percent decrease in the ~~March 31,~~September 30, 2007 effective swap rate. For long-term debt, this assumes a 10 percent decrease in the weighted average yield to maturity of our long-term debt at ~~March 31,~~September 30, 2007.

At ~~March 31,~~September 30, 2007, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to ~~effects of~~ interest rate fluctuations. This sensitivity is illustrated by the ~~$128~~$329 million increase in the fair value of long-term debt at ~~March 31,~~September 30, 2007, assuming a hypothetical 10 percent decrease in interest rates. However, our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affect our results of operations and cash flows when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value.
We manage our exposure to interest rate movements by utilizing financial derivative instruments. The primary objective of this program is to reduce our overall cost of borrowing by managing the fixed and floating interest rate mix of the debt portfolio. We have entered into several interest rate swap agreements, designated as fair value hedges, which effectively resulted in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates. On June 1, 2007, $450 million notional amount of our interest rate swap agreements expired. There have been no other changes to the positions subsequent to December 31, 2006.
Foreign Currency Exchange Rate Risk
We manage our exposure to foreign currency exchange rates by utilizing forward and option contracts. The primary objective of this program is to reduce our exposure to movements in ~~the~~ foreign currency ~~markets~~exchange rates by locking in such rates. At September 30, 2007 the following currency derivatives were outstanding. All contracts currently qualify for hedge accounting unless noted.
(In millions)

Period

Notional
Amount

Forward
Rate(a)

Fair
Value(b)

Foreign Currency Forwards:

Dollar (Canada)

December 2007

$
51

0.99343
(c)
$
3

Euro

October 2007 - November 2008

$
40

1.42615
(d)
$
4

Kroner (Norway)

October 2007 - October 2009

$
75

5.44450
(c)
$
9

(a)Rates shown are weighted average forward rates for the period.
(b)Fair value was based on market rates.
(c)Foreign currency to U.S. dollar.
(d)U.S. dollar to foreign currency.
32

(In millions)

Period

Notional
Amount

Weighted
Average
Exercise Price(a)

Fair
Value(b)

Foreign Currency Rate Options:

Dollar (Canada) (c)

November 2007

$
3,379

1.0358
(d)
$
147

Kroner (Norway)

October 2007 - December 2007

$
50

5.9496
(d)
$
5

(a)Rates shown are the weighted average exercise prices for the period.
(b)Fair value was based on market prices.
(c)Subsequent to September 30, 2007, Marathon converted the Canadian dollar options to forwards in the amount of 3.5 billion Canadian dollars which settled on October 17, 2007. An additional gain of $62 million related to these options and forwards will be recognized in the fourth quarter of 2007.
(d)Foreign currency ~~rates.~~ to U.S. dollar.
The aggregate cash flow effect on foreign currency contracts of a hypothetical 10 percent change to exchange rates at ~~March 31,~~September 30, 2007, would be approximately ~~$11~~$12 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 ~~March 31,~~September 30, 2007, there were no changes in our internal controls over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal controls over financial reporting.
Marathon reviews and modifies its financial and operational controls on an ongoing basis to ensure that those controls are adequate to address changes in its business as it evolves. Marathon believes that its existing financial and operational controls and procedures are adequate.
24
33

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)

First Quarter Ended March 31,

(Dollars in millions, except as noted)

2007

2006

SEGMENT INCOME

Exploration and Production

United States

$
150

$
245

International

235

220

E&P segment

385

465

Refining, Marketing and Transportation

345

319

Integrated Gas

19

8

Segment income

749

792

Items not allocated to segments, net of income taxes:

Corporate and other unallocated items

(43
)
(66
)
Gain on long-term U.K. natural gas contracts

11

45

Discontinued operations

–

13

Net income

$
717

$
784

CAPITAL EXPENDITURES

Exploration and Production

$
461

$
358

Refining, Marketing and Transportation

217

104

Integrated Gas (a)

57

94

Discontinued Operations

–

26

Corporate

2

17

Total

$
737

$
599

EXPLORATION EXPENSE

United States

$
37

$
28

International

24

43

Total

$
61

$
71

E&P OPERATING STATISTICS

Net Liquid Hydrocarbon Sales (mbpd) (b)

United States

69

80

Europe

32

30

Africa

97

72

Total International

129

102

Worldwide Continuing Operations

198

182

Discontinued Operations

–

29

Worldwide

198

211

Net Natural Gas Sales (mmcfd) (b)(c)

United States

512

561

Europe

247

347

Africa

90

88

Total International

337

435

Worldwide

849

996

Total Worldwide Sales (mboepd)

Continuing operations

339

348

Discontinued operations

–

29

Worldwide

339

377

Third Quarter

Nine Months

Ended September 30,

Ended September 30,

(Dollars in millions, except as noted)

2007

2006

2007

2006

SEGMENT INCOME

Exploration and Production

United States

$
147

$
218

$
470

$
706

International

332

354

794

990

E&P segment

479

572

1,264

1,696

Refining, Marketing and Transportation

482

1,026

2,073

2,262

Integrated Gas

52

(2
)
83

23

Segment income

1,013

1,596

3,420

3,981

Items not allocated to segments, net of income taxes

Corporate and other unallocated items

3

(52
)
(149
)
(217
)
Gain (loss) on long-term U.K. natural gas contracts

(62
)
58

(56
)
93

Gain on foreign currency derivative instruments

74

—

74

—

Loss on early extinguishment of debt

(7
)
—

(9
)
—

U.K. tax legislation

—

21

—

21

Discontinued operations

—

—

8

277

Net income

$
1,021

$
1,623

$
3,288

$
4,155

CAPITAL EXPENDITURES

Exploration and Production

$
582

$
795

$
1,623

$
1,616

Refining, Marketing and Transportation

430

223

981

527

Integrated Gas(a)

2

72

93

236

Discontinued Operations

—

—

—

45

Corporate

12

7

28

26

Total

$
1,026

$
1,097

$
2,725

$
2,450

EXPLORATION EXPENSES

United States

$
53

$
40

$
137

$
109

International

35

57

127

125

Total

$
88

$
97

$
264

$
234

E&P OPERATING STATISTICS

Net Liquid Hydrocarbon Sales (mbpd)(b)

United States

63

72

66

77

Europe

33

29

33

35

Africa

103

141

100

116

Total International

136

170

133

151

Worldwide Continuing Operations

199

242

199

228

Discontinued Operations

—

—

—

16

Worldwide

199

242

199

244

Net Natural Gas Sales (mmcfd)(b)(c)

United States

464

522

478

536

Europe

195

141

206

237

Africa

372

56

221

65

Total International

567

197

427

302

Worldwide

1,031

719

905

838

Total Worldwide Sales (mboepd)

Continuing operations

371

362

350

368

Discontinued operations

—

—

—

16

Worldwide

371

362

350

384

(a)          ~~Includes Equatorial Guinea LNG Holdings Limited~~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 ~~represent net~~reflect sales after royalties, except for Ireland where amounts are before royalties.
(c)          Includes natural gas acquired for injection and subsequent resale of 4051 mmcfd and 4136 mmcfd in the third quarters of 2007 and 2006, and 49 mmcfd and 45 mmcfd for the first ~~quarters~~nine months of 2007 and 2006.
34

MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)

First Quarter Ended March 31,

(Dollars in millions, except as noted)

2007

2006

E&P OPERATING STATISTICS (continued)

Average Realizations (d)

Liquid Hydrocarbons (per bbl)

United States

$
49.32

$
49.30

Europe

56.72

62.14

Africa

50.44

51.35

Total International

52.01

54.54

Worldwide Continuing Operations

51.07

52.23

Discontinued Operations

–

37.39

Worldwide

$
51.07

$
50.16

Natural Gas (per mcf)

United States

$
5.91

$
6.66

Europe

6.62

7.66

Africa

0.26

0.25

Total International

4.91

6.16

Worldwide

$
5.51

$
6.44

RM&T OPERATING STATISTICS

Refinery Runs (mbpd)

Crude oil refined

968

898

Other charge and blend stocks

227

249

Total

1,195

1,147

Refined Product Yields (mbpd)

Gasoline

621

645

Distillates

322

290

Propane

20

20

Feedstocks and special products

147

108

Heavy fuel oil

22

24

Asphalt

78

75

Total

1,210

1,162

Refined Product Sales Volumes (mbpd) (e)(f)

1,343

1,417

Matching buy/sell volumes included in above (f)

–

83

Refining and Wholesale Marketing Gross Margin (per gallon) (g)

$
0.1246

$
0.1137

Speedway SuperAmerica

Retail outlets

1,632

1,635

Gasoline and distillates sales (millions of gallons)

800

776

Gasoline and distillates gross margin (per gallon)

$
0.1217

$
0.1055

Merchandise sales

$
644

$
610

Merchandise gross margin

$
160

$
148

Third Quarter

Nine Months

Ended September 30,

Ended September 30,

(Dollars in millions, except as noted)

2007

2006

2007

2006

E&P OPERATING STATISTICS (continued)

Average Realizations (d)

Liquid Hydrocarbons (per bbl)

United States

$
63.53

$
60.37

$
55.83

$
56.38

Europe

73.19

66.19

63.80

65.64

Africa

69.48

63.64

60.57

61.71

Total International

70.37

64.07

61.37

62.63

Worldwide Continuing Operations

68.21

62.96

59.54

60.51

Discontinued Operations

—

—

—

38.38

Worldwide

$
68.21

$
62.96

$
59.54

$
59.02

Natural Gas (per mcf)

United States

$
5.14

$
5.62

$
5.74

$
5.89

Europe

6.47

5.65

5.95

6.83

Africa

0.25

0.24

0.25

0.25

Total International

2.38

4.10

3.01

5.41

Worldwide

$
3.63

$
5.21

$
4.45

$
5.72

RM&T OPERATING STATISTICS

Refinery Runs (mbpd)

Crude oil refined

1,042

1,031

1,028

989

Other charge and blend stocks

199

218

211

225

Total

1,241

1,249

1,239

1,214

Refined Product Yields (mbpd)

Gasoline

646

655

649

655

Distillates

358

336

352

316

Propane

24

24

24

23

Feedstocks and special products

111

121

118

118

Heavy fuel oil

27

21

25

23

Asphalt

93

106

87

94

Total

1,259

1,263

1,255

1,229

Refined Products Sales Volumes (mbpd)(e)(f)

1,440

1,434

1,403

1,437

Matching buy/sell volumes included in above(f)

—

2

—

32

Refining and wholesale marketing gross

Margin (per gallon)(g)

$
0.1717

$
0.3271

$
0.2317

$
0.2478

Speedway SuperAmerica

Retail outlets

1,637

1,635

—

—

Gasoline and distillate sales (millions of gallons)

892

867

2,520

2,459

Gasoline and distillate gross margin (per gallon)

$
0.1103

$
0.1410

$
0.1115

$
0.1168

Merchandise sales

$
752

$
729

$
2,110

$
2,029

Merchandise gross margin

$
191

$
178

$
533

$
497

IG OPERATING STATISTICS

Net Sales (metric tonnes per day)

LNG

6,137

1,001

3,117

1,068

Methanol

1,421

613

1,285

938

(d)Excludes gains and losses on traditional derivative instruments and the unrealized effects of long-term U.K. natural gas contracts that are accounted for as derivatives.
(e)Total average daily volumes of all refined product sales to wholesale, branded and retail (SSA) customers.
(f)As a result of the change in accounting for matching buy/sell arrangements on April 1, 2006, the reported sales volumes will be lower than the volumes determined under the previous accounting practices.
(g)Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation. As a result of the change in accounting for matching buy/sell ~~arrangements~~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.
35

Part II –— OTHER INFORMATION
Item 1. Legal Proceedings
~~On April 12, 2007,~~Product Contamination Litigation
A lawsuit was filed in the United States District Court for the Southern District of West Virginia and alleges that Marathon’s Catlettsburg refinery sold defective gasoline to wholesalers and retailers, causing permanent damage to storage tanks, dispensers and related equipment, resulting in lost profits, business disruption and personal and real property damages. Class action certification was granted in August 2007. In 2002, Marathon ~~Petroleum Company LLC (MPC) was notified by~~conducted extensive cleaning operations at affected facilities and denies that any permanent damages resulted from the ~~Division of Enforcement~~incident. Marathon previously settled with many of the ~~Commodity Futures Trading Commission of its intent to recommend that the Commission name MPC~~potential class members in an enforcement action alleging that on November 26, 2003, MPC attempted to manipulate the price of West Texas Intermediate crude oil. It is Marathon’s understanding that the proposed enforcement action involves 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 bidsthis case and ~~further, that there are no allegations of false reporting. Marathon~~ intends to vigorously defend this action.
Wyoming Proceedings
In response to the ~~proposed~~Governor of Wyoming’s veto of a state agency adoption of a rule that would allow the State Department of Environmental Quality (“DEQ”) to regulate the quantity of coal bed methane water discharges, an activist group has sued in State Court to overturn the veto. In June 2007, Marathon and another producer filed a motion to intervene. The State DEQ has begun issuing renewal water discharge and other permits with stringent limits based on its agricultural use policy rather than upon any regulation. The permits could require more costly water treatment or injection. Marathon is appealing every permit issued in this way as unlawful.
In the Environmental Defense Fund (“EDF”) v. Bureau of Land Management (“BLM”) case before the Federal District Court of Wyoming, the EDF alleged that in 2002, the BLM did not sufficiently evaluate the air impacts associated with coal bed natural gas production in the Powder River Basin, as well as other oil and gas operations in Wyoming. Marathon and other producers had intervened. In June 2007, the Federal District Court for the District of Wyoming dismissed the EDF case (without prejudice as to refiling).
MTBE Litigation
We are a defendant, along with many other companies with refining operations, in over 50 cases in 12 states alleging methyl tertiary-butyl ether (“MTBE”) contamination in groundwater. There have been two recent developments in these matters. The federal Second Circuit Court of Appeals ruled in two of the MTBE cases brought by the states of New Hampshire and California (Marathon was not a party in these cases.) that the cases had been improperly removed to federal court based upon federal officer jurisdiction. The parties are briefing to the court whether other grounds for federal jurisdiction exist. If federal jurisdiction is found to be not proper in these cases, the issue of federal jurisdiction may then be raised in all of the MTBE cases. If removal is found to be improper in any case, it would be returned to state court. Also, the state of New Jersey has recently sued Marathon and the other refiners. This is the only case Marathon is involved with which has a state as a plaintiff and it is the only case where natural resources damages are sought. We continue to defend all of these MTBE cases vigorously.
Other
Marathon resolved the enforcement ~~action.~~action brought by the Minnesota Pollution Control Agency (“MPCA”) in 2007 regarding a release of catalyst from the fluid catalytic cracking unit at the St. Paul Park, Minnesota, refinery for a civil penalty of $60,000.
The United States Occupational, Safety, and Health Administration (“OSHA”) has announced a National Emphasis Program (“NEP”) where it plans to inspect most of the domestic oil refinery locations in 2007 and 2008. The inspections will focus on compliance with the OSHA Process Safety Management requirements. OSHA conducted an inspection at our Canton, Ohio, refinery in the second and third quarters of 2007. We expect some resulting enforcement action in the fourth quarter of 2007. The related monetary penalties are not expected to be a significant amount.
Item 1A. Risk Factors
Marathon is subject to various risks and uncertainties in the course of its business. See the discussion of such risks and uncertainties under Item 1A. Risk Factors in Marathon’s 2006 Annual Report on Form 10-K. In addition, the following risk factor should be considered:
There are various risks inherent with our acquisition of Western, including risks related to operations and profitability.
Our acquisition of Western involves various risks. In particular, we may have ~~been no material changes~~assumed unknown liabilities in the acquisition and we are subject to various operating risks inherent with producing Canadian oil sands. Also, we are operating in a high-cost environment for oil sands production and may not realize the anticipated financial returns from the ~~risk factors previously disclosed~~acquisition. In addition, future changes in ~~that Form 10-K.~~laws and regulations, such as royalty and tax regulations, may adversely affect us. For example, on October 25, 2007, the Government of the Province of Alberta announced a framework (the “Framework”) for a new royalty regime on oil sands production. The Framework contemplates increases to the base or start-up royalty rate (from 1 percent to up to 9 percent) and the net or post-payout royalty rate (from 25 percent to up to 40 percent) on oil sands production. The Framework is expected to take effect in January 2009 and will apply to existing oil sands projects. Although the Framework has not yet been formally enacted, its implementation in the manner presented by the Government of the Province of Alberta could have a negative impact on our Canadian oil sands operations and our anticipated financial returns from the acquisition.
36

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
ISSUER PURCHASES OF EQUITY SECURITIES

(a)

(b)

(c)

(d)

Period

Total Number of
Shares Purchased (a)

Average Price Paid
per Share

Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs (c)

Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans or
Programs (c)

01/01/07 – 01/31/07

2,161,493

$ 87.29

2,005,921

$ 621,467,418

02/01/07 – 02/28/07

1,819,700

$ 90.51

1,816,692

$ 457,038,920

03/01/07 – 03/31/07

1,253,439
(b)
$ 92.30

1,222,600

$ 344,248,401

Total

5,234,632

$ 89.61

5,045,213

Period

(a)
Total Number of
Shares Purchased (a)(b)

(b)
Average Price Paid
per Share

(c)
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(d)

(d)
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(d)

07/01/07 - 07/31/07

393,085

$60.06

381,500

$2,497,064,359

08/01/07 - 08/31/07

3,997

$50.32

—

$2,497,064,359

09/01/07 - 09/30/07

37,979
(c)
$54.18

—

$2,497,064,359

Total

435,061

$59.46

381,500

(a)~~173,896~~22,303 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.
(b)~~15,523~~Under the terms of the transaction whereby Marathon acquired the minority interest in Marathon Petroleum Company LLC and other businesses from Ashland Inc., Marathon paid Ashland Inc. shareholders cash in lieu of issuing fractional shares of Marathon’s common stock to which such holders would otherwise be entitled. Marathon acquired five shares due to acquisition share exchanges and Ashland Inc. share transfers pending at the closing of the transaction.
(c)31,253 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. ~~Stock~~Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon.
~~(c)~~ (d)In January 2006, weMarathon announced a $2 billion share repurchase ~~program. In January 2007, our Board of Directors authorized the extension of this~~ program which was increased by an additional $500 ~~million.~~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 ~~March 31,~~September 30, 2007, ~~the Company~~57 million split-adjusted common shares had ~~repurchased 25.8 million common shares~~been acquired at a cost of ~~$2.150~~$2.497 billion, which includes transaction fees and commissions that are not reported in the table above.

~~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:~~37
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

28

Item 6. Exhibits
2.1
Amended and Restated Arrangement Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd., Western Oil Sands Inc. and WesternZagros Resources Inc., dated as of September 14, 2007 (incorporated by reference to Exhibit 2.7 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).
2.2
Amending Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd., Western Oil Sands Inc. and WesternZagros Resources Inc., dated as of October 15, 2007 (incorporated by reference to Exhibit 2.8 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).
2.3
Plan of Arrangement under Section 193 of the Business Corporations Act (Alberta) (incorporated by reference to Exhibit 2.9 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).
3.1

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

3.2

~~By-Laws~~By-laws of Marathon Oil Corporation (incorporated by reference to Exhibit 3.2 to Marathon Oil Corporation’s Form 8-K, filed on April 25, 2007).
3.3
Certificate of Designations of Special Voting Stock of Marathon Oil Corporation.
4.1
Amendment No. 3 dated as of October 4, 2007 to Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent.

10.1

~~Marathon Oil Corporation 2007 Incentive Compensation Plan~~Exchangeable Share Provisions of 1339971 Alberta Ltd (incorporated by reference to ~~Appendix I~~Exhibit 10.1 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil ~~Corporation’s Definitive Proxy Statement on Schedule 14A~~Corporation filed on ~~March 13,~~October 17, 2007).
10.2
Support Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd. and Marathon Canadian Oil Sands Holding Limited, dated as of October 18, 2007
10.3
Voting and Exchange Trust Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd., Marathon Canadian Oil Sands Holding Limited and Valiant Trust Company, dated as of October 18, 2007.

12.1

Computation of Ratio of Earnings to Fixed Charges

31.1

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

31.2

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

32.1

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

32.2

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

2938

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

~~May~~November 7, 2007
30
39

	First Quarter Ended March 31,
(Dollars in millions, except per share data)	2007			2006
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	12,491		$	12,900
Revenues from matching buy/sell transactions	58			3,206
Sales to related parties	320			312
Income from equity method investments	107			92
Net gains on disposal of assets	11			11
Other income	15			18
Total revenues and other income	13,002			16,539
Costs and expenses:
Cost of revenues (excludes items below)	9,542			9,759
Purchases related to matching buy/sell transactions	61			3,233
Purchases from related parties	47			51
Consumer excise taxes	1,197			1,165
Depreciation, depletion and amortization	393			400
Selling, general and administrative expenses	287			287
Other taxes	98			97
Exploration expenses	61			71
Total costs and expenses	11,686			15,063
Income from operations	1,316			1,476
Net interest and other financing costs (income)	(19		)	23
Loss on early extinguishment of debt	2			–
Minority interests in loss of Equatorial Guinea LNG Holdings Limited	(2		)	(3		)
Income from continuing operations before income taxes	1,335			1,456
Provision for income taxes	618			685
Income from continuing operations	717			771
Discontinued operations	–			13
Net income	$	717		$	784
Per Share Data
Basic:
Income from continuing operations	$	2.08		$	2.11
Discontinued operations	–			$	0.04
Net income	$	2.08		$	2.15
Diluted:
Income from continuing operations	$	2.07		$	2.09
Discontinued operations	–			$	0.04
Net income	$	2.07		$	2.13
Dividends paid	$	0.40		$	0.33

	March 31,			December 31,
(Dollars in millions, except per share data)	2007			2006
Assets
Current assets:
Cash and cash equivalents	$	2,347		$	2,585
Receivables, less allowance for doubtful accounts of $3 and $3	4,143			4,114
Receivables from United States Steel	30			32
Receivables from related parties	64			63
Inventories	3,536			3,173
Other current assets	217			129
Total current assets	10,337			10,096
Investments and long-term receivables, less allowance for doubtful accounts of $9 and $9	1,954			1,887
Receivables from United States Steel	495			498
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $13,873 and $13,573	16,963			16,653
Goodwill	1,396			1,398
Intangible assets, less accumulated amortization of $79 and $75	179			180
Other noncurrent assets	72			119
Total assets	$	31,396		$	30,831
Liabilities
Current liabilities:
Accounts payable	$	6,063		$	5,586
Payable to United States Steel	–			13
Payables to related parties	294			264
Payroll and benefits payable	335			409
Accrued taxes	587			598
Deferred income taxes	643			631
Accrued interest	54			89
Long-term debt due within one year	873			471
Total current liabilities	8,849			8,061
Long-term debt	2,654			3,061
Deferred income taxes	1,893			1,897
Defined benefit postretirement plan obligations	1,201			1,245
Asset retirement obligations	1,059			1,044
Payable to United States Steel	7			7
Deferred credits and other liabilities	395			391
Total liabilities	16,058			15,706
Minority interests in Equatorial Guinea LNG Holdings Limited	546			518
Commitments and contingencies
Stockholders’ Equity
Common stock issued – 367,851,558 shares (par value $1 per share, 550,000,000 shares authorized)	368			368
Common stock held in treasury, at cost – 24,897,453 and 20,080,670 shares	(2,073		)	(1,638		)
Additional paid-in capital	5,148			5,152
Retained earnings	11,671			11,093
Accumulated other comprehensive loss	(322		)	(368		)
Total stockholders' equity	14,792			14,607
Total liabilities and stockholders' equity	$	31,396		$	30,831

	First Quarter Ended March 31,
(Dollars in millions)	2007			2006
*Increase (decrease) in cash and cash equivalents*
Operating activities:
Net income	$	717		$	784
Adjustments to reconcile net income to net cash provided from operating activities:
Loss on early extinguishment of debt	2			–
Income from discontinued operations	–			(13		)
Deferred income taxes	26			42
Minority interests in loss of Equatorial Guinea LNG Holdings Limited	(2		)	(3		)
Depreciation, depletion and amortization	393			400
Pension and other postretirement benefits, net	5			(92		)
Exploratory dry well costs and unproved property impairments	26			34
Net gains on disposal of assets	(11		)	(11		)
Equity method investments, net	(20		)	(59		)
Changes in the fair value of long-term U.K. natural gas contracts	(21		)	(78		)
Changes in:
Current receivables	(27		)	(172		)
Inventories	(364		)	(365		)
Current accounts payable and accrued expenses	351			(190		)
All other, net	(49		)	(73		)
Net cash provided from continuing operations	1,026			204
Net cash provided from discontinued operations	–			36
Net cash provided from operating activities	1,026			240
Investing activities:
Capital expenditures	(737		)	(572		)
Acquisitions	–			(527		)
Disposal of assets	32			38
Investments – loans and advances	(20		)	–
– repayments of loans and return of capital	15			87
Investing activities of discontinued operations	–			(26		)
All other, net	(1		)	13
Net cash used in investing activities	(711		)	(987		)
Financing activities:
Debt repayments	(10		)	(302		)
Issuance of common stock	5			8
Purchases of common stock	(452		)	(229		)
Excess tax benefits from stock-based compensation arrangements	13			10
Dividends paid	(138		)	(121		)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited	27			30
Net cash used in financing activities	(555		)	(604		)
Effect of exchange rate changes on cash	2			3
Net decrease in cash and cash equivalents	(238		)	(1,348		)
Cash and cash equivalents at beginning of period	2,585			2,617
Cash and cash equivalents at end of period	$	2,347		$	1,269

(In millions)	E&P			RM&T			IG			Total
First Quarter Ended March 31, 2007
Revenues:
Customer	$	1,705		$	10,767		$	56		$	12,528
Intersegment (a)	140			1			–			141
Related parties	4			316			–			320
Segment revenues	1,849			11,084			56			12,989
Elimination of intersegment revenues	(140		)	(1		)	–			(141		)
Gain on long-term U.K. natural gas contracts	21			–			–			21
Total revenues	$	1,730		$	11,083		$	56		$	12,869
Segment income	$	385		$	345		$	19		$	749
Income from equity method investments	41			41			25			107
Depreciation, depletion and amortization (b)	242			141			1			384
Minority interests in loss of subsidiary	–			–			(2		)	(2		)
Provision for income taxes (b)	414			198			8			620
Capital expenditures (c)	461			217			57			735

	First Quarter Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2007			2006			2007			2006
Service cost	$	33		$	34		$	5		$	6
Interest cost	34			32			11			10
Expected return on plan assets	(38		)	(26		)	–			–
Amortization:
– prior service cost (credit)	3			1			(2		)	(3		)
– actuarial loss	5			13			2			2
Net periodic benefit cost	$	37		$	54		$	16		$	15

	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)	34		(e)	84		(e)
Refined products (d)	27		(e)	70		(e)

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

(In millions)	Fair Value				Incremental Change in Fair Value
Financial assets (liabilities):(a)
Receivable from United States Steel		$	525			$	11
Interest rate swap agreements		$	(17	) (b)		$	8	(c)
Long-term debt, including amounts due within one year		$	(3,710	) (b)		$	(128	) (c)

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

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

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

	First Quarter Ended March 31,
(Dollars in millions, except as noted)	2007			2006
SEGMENT INCOME
Exploration and Production
United States	$	150		$	245
International	235			220
E&P segment	385			465
Refining, Marketing and Transportation	345			319
Integrated Gas	19			8
Segment income	749			792
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(43		)	(66		)
Gain on long-term U.K. natural gas contracts	11			45
Discontinued operations	–			13
Net income	$	717		$	784
CAPITAL EXPENDITURES
Exploration and Production	$	461		$	358
Refining, Marketing and Transportation	217			104
Integrated Gas (a)	57			94
Discontinued Operations	–			26
Corporate	2			17
Total	$	737		$	599
EXPLORATION EXPENSE
United States	$	37		$	28
International	24			43
Total	$	61		$	71
E&P OPERATING STATISTICS
Net Liquid Hydrocarbon Sales (mbpd) (b)
United States	69			80
Europe	32			30
Africa	97			72
Total International	129			102
Worldwide Continuing Operations	198			182
Discontinued Operations	–			29
Worldwide	198			211
Net Natural Gas Sales (mmcfd) (b)(c)
United States	512			561
Europe	247			347
Africa	90			88
Total International	337			435
Worldwide	849			996
Total Worldwide Sales (mboepd)
Continuing operations	339			348
Discontinued operations	–			29
Worldwide	339			377

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

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

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

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

	(a)		(b)	(c)	(d)
Period	Total Number of Shares Purchased (a)		Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (c)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (c)
01/01/07 – 01/31/07	2,161,493		$ 87.29	2,005,921	$ 621,467,418
02/01/07 – 02/28/07	1,819,700		$ 90.51	1,816,692	$ 457,038,920
03/01/07 – 03/31/07	1,253,439	(b)	$ 92.30	1,222,600	$ 344,248,401
Total	5,234,632		$ 89.61	5,045,213

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

	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

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

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

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

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

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

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

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

10.1		~~Marathon Oil Corporation 2007 Incentive Compensation Plan~~Exchangeable Share Provisions of 1339971 Alberta Ltd (incorporated by reference to ~~Appendix I~~Exhibit 10.1 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil ~~Corporation’s Definitive Proxy Statement on Schedule 14A~~Corporation filed on ~~March 13,~~October 17, 2007).

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

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

12.1		Computation of Ratio of Earnings to Fixed Charges

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

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

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

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

MARATHON OIL CORPORATION

Michael K. Stewart

Michael K. Stewart

Vice President, Accounting and Controller