Edgar Filing: MARATHON OIL CORP

form10-q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended June 30, 2008

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

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)

Delaware	25-0996816
(State or other jurisdiction of incorporation or organization)	(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, including area code)

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 Ö No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer Ö	Accelerated filer
Non-accelerated filer (Do not check if a smaller reporting company)	Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No Ö

There were 705,551,204 shares of Marathon Oil Corporation common stock outstanding as of July 31, 2008.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended June 30, 2008

		INDEX
			Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)		2
	Consolidated Balance Sheets (Unaudited)		3
	Consolidated Statements of Cash Flows (Unaudited)		4
	Notes to Consolidated Financial Statements (Unaudited)		5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		28
Item 4.	Controls and Procedures		31
	Supplemental Statistics		32
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		34
Item 1A.	Risk Factors		34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		34
Item 4.	Submission of Matters to a Vote of Security Holders		35
Item 6.	Exhibits		36
	Signatures		37

Unless the context otherwise indicates, references in this Form 10-Q to “Marathon,” “we,” “our,” or “us” are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon exerts significant influence by virtue of its ownership interest).

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions, except per share data)	2008		2007		2008		2007
Revenues and other income:

Sales and other operating revenues (including	$	21,226	$	16,325	$	38,506	$	28,874
consumer excise taxes)
Sales to related parties		686		411		1,228		731
Income from equity method investments		256		117		465		224
Net gain on disposal of assets		12		7		22		18
Other income		45		27		104		42

Total revenues and other income		22,225		16,887		40,325		29,889
Costs and expenses:
Cost of revenues (excludes items below)		17,988		11,804		32,440		21,407
Purchases from related parties		226		89		365		136
Consumer excise taxes		1,295		1,307		2,511		2,504
Depreciation, depletion and amortization		504		396		955		789
Selling, general and administrative expenses		361		327		661		614
Other taxes		127		93		250		191
Exploration expenses		130		115		259		176

Total costs and expenses		20,631		14,131		37,441		25,817

Income from operations		1,594		2,756		2,884		4,072

Net interest and other financing income (costs)		(10)		20		(1)		39
Loss on early extinguishment of debt		-		(1)		-		(3)
Minority interests in loss of Equatorial Guinea
LNG Holdings Limited		-		1		-		3

Income from continuing operations before
income taxes		1,584		2,776		2,883		4,111

Provision for income taxes		810		1,234		1,378		1,852

Income from continuing operations		774		1,542		1,505		2,259

Discontinued operations		-		8		-		8

Net income	$	774	$	1,550	$	1,505	$	2,267

Per Share Data

Basic:
Income from continuing operations	$	1.09	$	2.26	$	2.11	$	3.29
Discontinued operations	$	-	$	0.01	$	-	$	0.01
Net income	$	1.09	$	2.27	$	2.11	$	3.30

Diluted:
Income from continuing operations	$	1.08	$	2.24	$	2.10	$	3.27
Discontinued operations	$	-	$	0.01	$	-	$	0.01
Net income	$	1.08	$	2.25	$	2.10	$	3.28

Dividends paid	$	0.24	$	0.24	$	0.48	$	0.44

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

	June 30,		December 31,
(In millions, except per share data)	2008		2007
Assets
Current assets:
Cash and cash equivalents	$	1,270	$	1,199
Receivables, less allowance for doubtful accounts of $3 and $3		7,467		5,818
Receivables from United States Steel		23		22
Receivables from related parties		134		79
Inventories		5,015		3,277
Other current assets		145		192

Total current assets		14,054		10,587

Equity method investments		2,825		2,630
Receivables from United States Steel		473		485
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $15,778 and $14,857		27,071		24,675
Goodwill		2,887		2,899
Intangible assets, less accumulated amortization of $88 and $80		282		288
Other noncurrent assets		1,098		1,182

Total assets	$	48,690	$	42,746
Liabilities
Current liabilities:
Commercial paper	$	981	$	-
Accounts payable		12,136		8,281
Payables to related parties		79		44
Payroll and benefits payable		320		417
Accrued taxes		733		712
Deferred income taxes		367		547
Accrued interest		124		128
Long-term debt due within one year		87		1,131

Total current liabilities		14,827		11,260

Long-term debt		7,059		6,084
Deferred income taxes		3,768		3,389
Defined benefit postretirement plan obligations		1,170		1,092
Asset retirement obligations		1,173		1,131
Payable to United States Steel		5		5
Deferred credits and other liabilities		579		562

Total liabilities		28,581		23,523

Commitments and contingencies

Stockholders’ Equity
Preferred stock – 5 million shares issued, 4 million and 5 million shares
outstanding, (no par value, 6 million shares authorized)		-		-
Common stock:
Issued – 767 million and 765 million shares (par value $1 per share,
1.1 billion shares authorized)		767		765
Securities exchangeable into common stock – 5 million shares issued,
3 million and 5 million shares outstanding (no par value, unlimited
shares authorized)		-		-
Held in treasury, at cost – 60 million and 55 million shares		(2,660)		(2,384)
Additional paid-in capital		6,697		6,679
Retained earnings		15,575		14,412
Accumulated other comprehensive loss		(270)		(249)

Total stockholders' equity		20,109		19,223

Total liabilities and stockholders' equity	$	48,690	$	42,746

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended
	June 30,
(In millions)	2008		2007
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	1,505	$	2,267
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on early extinguishment of debt		-		3
Income from discontinued operations		-		(8)
Deferred income taxes		16		122
Minority interests in loss of Equatorial Guinea LNG Holdings Limited		-		(3)
Depreciation, depletion and amortization		955		789
Pension and other postretirement benefits, net		71		20
Exploratory dry well costs and unproved property impairments		114		75
Net gain on disposal of assets		(22)		(18)
Equity method investments, net		(149)		(78)
Changes in the fair value of U.K. natural gas contracts		235		(12)
Changes in:
Current receivables		(1,677)		(639)
Inventories		(1,739)		(1,150)
Current accounts payable and accrued expenses		3,500		1,037
All other, net		146		(39)
Net cash provided by operating activities		2,955		2,366
Investing activities:
Capital expenditures		(3,382)		(1,699)
Disposal of assets		24		48
Trusteed funds - withdrawals		258		-
Investments - loans and advances		(60)		(64)
Investments - repayments of loans and return of capital		8		34
Deconsolidation of Equatorial Guinea LNG Holdings Limited		-		(37)
All other, net		(6)		(10)
Net cash used in investing activities		(3,158)		(1,728)
Financing activities:
Commercial paper and other revolving credit arrangements, net		384		-
Borrowings		999		578
Debt issuance costs		(7)		(8)
Debt repayments		(486)		(469)
Issuance of common stock		6		18
Purchases of common stock		(295)		(776)
Excess tax benefits from stock-based compensation arrangements		7		24
Dividends paid		(342)		(302)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited		-		39
Net cash provided by (used in) financing activities		266		(896)
Effect of exchange rate changes on cash		8		4
Net increase (decrease) in cash and cash equivalents		71		(254)
Cash and cash equivalents at beginning of period		1,199		2,585
Cash and cash equivalents at end of period	$	1,270	$	2,331

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including 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 2008 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”) 2007 Annual Report on Form 10-K.

2. New Accounting Standards

In April 2007, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position on FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts” (“FSP FIN No. 39-1”), which allows a party to a master netting agreement to offset the fair value amounts related to the right to reclaim collateral against the fair value amounts recognized for derivative instruments. Such treatment was consistent with Marathon’s accounting policy; therefore, adoption of FSP FIN No. 39-1 effective January 1, 2008, did not have any effect on Marathon’s consolidated financial position.

In February 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure at fair value many financial instruments and certain other items 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. Marathon did not elect the fair value option when this standard became effective on January 1, 2008.

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. In February 2008, the FASB issued FSP FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. Effective January 1, 2008, Marathon adopted SFAS No. 157, except for measurements of those nonfinancial assets and liabilities subject to the one-year deferral, which for Marathon include impairments of goodwill, intangible assets and other long-lived assets, and initial measurement of asset retirement obligations, asset exchanges, business combinations and partial sales of proved properties. Adoption did not have a significant effect on Marathon’s consolidated results of operations or financial position. The additional disclosures regarding assets and liabilities recorded at fair value and measured under SFAS No. 157 are presented in Note 11.

Notes to Consolidated Financial Statements (Unaudited)

3. Income per Common Share

Basic income per share is based on the weighted average number of common shares outstanding, including securities exchangeable into common shares. Diluted income per share includes exercise of stock options and restricted shares, provided the effect is not antidilutive.

	Three Months Ended June 30,
	2008					2007
(In millions, except per share data)	Basic		Diluted			Basic	Diluted

Income from continuing operations	$	774	$	774	$	1,542	$	1,542
Discontinued operations		-		-		8		8
Net income	$	774	$	774	$	1,550	$	1,550

Weighted average common shares outstanding		710		710		683		683
Effect of dilutive securities		-		4		-		6
Weighted average common shares, including
dilutive effect		710		714		683		689

Per share:
Income from continuing operations	$	1.09	$	1.08	$	2.26	$	2.24
Discontinued operations	$	-	$	-	$	0.01	$	0.01
Net income	$	1.09	$	1.08	$	2.27	$	2.25

	Six Months Ended June 30,
	2008					2007
(In millions, except per share data)	Basic		Diluted			Basic	Diluted

Income from continuing operations	$	1,505	$	1,505	$	2,259	$	2,259
Discontinued operations		-		-		8		8
Net income	$	1,505	$	1,505	$	2,267	$	2,267

Weighted average common shares outstanding		711		711		686		686
Effect of dilutive securities		-		5		-		5
Weighted average common shares, including
dilutive effect		711		716		686		691

Per share:
Income from continuing operations	$	2.11	$	2.10	$	3.29	$	3.27
Discontinued operations	$	-	$	-	$	0.01	$	0.01
Net income	$	2.11	$	2.10	$	3.30	$	3.28

The per share calculations above exclude 5.5 million stock options for the second quarter and the first six months of 2008 and 3.0 million stock options for the second quarter and the first six months of 2007, as they were antidilutive.

4. Acquisition

On October 18, 2007, Marathon completed the acquisition of all the outstanding shares of Western Oil Sands Inc. (“Western”) for cash and securities of $5,833 million. Subsequent to the transaction, Western’s name was changed to Marathon Oil Canada Corporation. The acquisition was accounted for under the purchase method of accounting and, as such, Marathon’s results of operations include Western’s results from October 18, 2007. Western’s oil sands mining and bitumen upgrading operations are reported as a separate Oil Sands Mining segment, while its ownership interests in leases where in-situ recovery techniques are expected to be utilized are included in the E&P segment.

Notes to Consolidated Financial Statements (Unaudited)

The following unaudited pro forma data is as if the acquisition of Western had been consummated at the beginning of each period presented. The pro forma data is based on historical information and does not reflect the actual results that would have occurred nor is it indicative of future results of operations.

	Three Months Ended June 30, 2007			Six Months Ended June 30, 2007
(In millions, except per share amounts)	Three Months Ended June 30, 2007			Six Months Ended June 30, 2007
Revenues and other income		$	17,175		$	30,424
Income from continuing operations			1,372			2,015
Net income			1,380			2,023
Per share data:
Income from continuing operations - basic		$	1.91		$	2.80
Income from continuing operations - diluted		$	1.90		$	2.78
Net income - basic		$	1.92		$	2.81
Net income - diluted		$	1.91		$	2.79

5. Segment Information

Marathon’s operations consist of four reportable operating segments:

Exploration and Production (“E&P”) – explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis;

Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and by-products;

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

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

(In millions)		E&P		OSM		RM&T		IG		Total
Three Months Ended June 30, 2008
Revenues:
Customer	$	3,183	$	(80)	$	18,267	$	21	$	21,391
Intersegment (a)		226		96		37		-		359
Related parties		15		-		671		-		686
Segment revenues		3,424		16		18,975		21		22,436
Elimination of intersegment revenues		(226)		(96)		(37)		-		(359)
Loss on U.K. natural gas contracts		(165)		-		-		-		(165)
Total revenues	$	3,033	$	(80)	$	18,938	$	21	$	21,912
Segment income (loss)	$	828	$	(157)	$	158	$	102	$	931
Income from equity method investments		77		-		43		136		256
Depreciation, depletion and amortization (b)		311		33		150		1		495
Income tax provision (benefit) (b)		854		(54)		108		36		944
Capital expenditures (c)(d)		874		262		702		-		1,838

Notes to Consolidated Financial Statements (Unaudited)

(In millions)		E&P		OSM		RM&T		IG		Total
Three Months Ended June 30, 2007
Revenues:
Customer	$	2,018	$	-	$	14,248	$	68	$	16,334
Intersegment (a)		116		-		83		-		199
Related parties		7		-		404		-		411
Segment revenues		2,141		-		14,735		68		16,944
Elimination of intersegment revenues		(116)		-		(83)		-		(199)
Loss on U.K. natural gas contracts		(9)		-		-		-		(9)
Total revenues	$	2,016	$	-	$	14,652	$	68	$	16,736
Segment income	$	400	$	-	$	1,246	$	12	$	1,658
Income from equity method investments		64		-		31		22		117
Depreciation, depletion and amortization (b)		237		-		149		3		389
Minority interest in loss of subsidiary		-		-		-		1		1
Income tax provision(b)		480		-		721		4		1,205
Capital expenditures (c)(d)		580		-		334		34		948

(In millions)		E&P		OSM		RM&T		IG		Total
Six Months Ended June 30, 2008
Revenues:
Customer	$	6,002	$	99	$	32,600	$	40	$	38,741
Intersegment (a)		385		116		202		-		703
Related parties		29		-		1,199		-		1,228
Segment revenues		6,416		215		34,001		40		40,672
Elimination of intersegment revenues		(385)		(116)		(202)		-		(703)
Loss on U.K. natural gas contracts		(235)		-		-		-		(235)
Total revenues	$	5,796	$	99	$	33,799	$	40	$	39,734
Segment income (loss)	$	1,512	$	(130)	$	83	$	201	$	1,666
Income from equity method investments		139		-		71		255		465
Depreciation, depletion and amortization (b)		570		67		298		2		937
Income tax provision (benefit)(b)		1,541		(45)		63		84		1,643
Capital expenditures (c)(d)		1,649		510		1,213		1		3,373

Notes to Consolidated Financial Statements (Unaudited)

(In millions)		E&P		OSM		RM&T		IG		Total
Six Months Ended June 30, 2007
Revenues:
Customer	$	3,723	$	-	$	25,015	$	124	$	28,862
Intersegment (a)		256		-		84		-		340
Related parties		11		-		720		-		731
Segment revenues		3,990		-		25,819		124		29,933
Elimination of intersegment revenues		(256)		-		(84)		-		(340)
Gain on U.K. natural gas contracts		12		-		-		-		12
Total revenues	$	3,746	$	-	$	25,735	$	124	$	29,605
Segment income	$	785	$	-	$	1,591	$	31	$	2,407
Income from equity method investments		105		-		72		47		224
Depreciation, depletion and amortization (b)		479		-		290		4		773
Minority interest in loss of subsidiary		-		-		-		3		3
Income tax provision (b)		894		-		919		12		1,825
Capital expenditures (c)(d)		1,041		-		551		91		1,683

(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 reconciliation below.

(c)

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

(d)

Through April 2007, Integrated Gas segment capital expenditures include Equatorial Guinea LNG Holdings Limited (“EGHoldings”) at 100 percent. Effective May 1, 2007, Marathon no longer consolidates EGHoldings and its investment in EGHoldings is accounted for under the equity method of accounting; therefore, EGHoldings’ capital expenditures subsequent to April 2007 are not included in Marathon’s capital expenditures.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2008			2007	2008		2007
Segment income	$	931	$	1,658	$	1,666	$	2,407
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(73)		(111)		(41)		(154)
Gain (loss) on U.K. natural gas contracts		(84)		(5)		(120)		6
Discontinued operations(a)		-		8		-		8
Net income	$	774	$	1,550	$	1,505	$	2,267

(a)

The Russian businesses sold in June 2006 were accounted for as discontinued operations. Adjustments to the sales price were completed in 2007 and an additional gain on the sale of $8 million ($13 million before income taxes) was recognized. See Marathon’s 2007 Form 10-K for further information.

The following reconciles total revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2008			2007	2008		2007
Total revenues	$	21,912	$	16,736	$	39,734	$	29,605
Less: Sales to related parties		686		411		1,228		731
Sales and other operating revenues (including consumer excise taxes)	$	21,226	$	16,325	$	38,506	$	28,874

Notes to Consolidated Financial Statements (Unaudited)

6. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Three Months Ended June 30,
	Pension Benefits				Other Benefits
(In millions)	2008		2007		2008		2007
Service cost	$	39	$	37	$	4	$	6
Interest cost		41		37		10		11
Expected return on plan assets		(42)		(39)		-		-
Amortization:
– prior service cost (credit)		4		4		(2)		(3)
– actuarial loss		11		13		-		2
Net periodic benefit cost	$	53	$	52	$	12	$	16

	Six Months Ended June 30,
	Pension Benefits				Other Benefits
(In millions)	2008		2007		2008		2007
Service cost	$	73	$	70	$	9	$	11
Interest cost		80		71		22		22
Expected return on plan assets		(84)		(77)		-		-
Amortization:
– prior service cost (credit)		7		7		(4)		(5)
– actuarial loss		15		18		1		4
Net periodic benefit cost	$	91	$	89	$	28	$	32

During the first six months of 2008, Marathon made contributions of $33 million to its funded international pension plans. Marathon expects to make additional contributions of approximately $7 million to its funded pension plans over the remainder of 2008. Contributions made from the general assets of Marathon to cover current benefit payments related to unfunded pension and other postretirement benefit plans were $9 million and $16 million during the first six months of 2008.

7. Income Taxes

The following is an analysis of the effective income tax rates for the periods presented:

	Six Months Ended June 30,
	2008		2007
Statutory U.S. income tax rate	35	%	35	%
Effects of foreign operations, including foreign tax credits	14		9
State and local income taxes, net of federal income tax effects	1		2
Other tax effects	(2)		(1)
Effective income tax rate for continuing operations	48	%	45	%

The geographic sources of income and related tax expense contributed to the increase in the effective income tax rate in the first six months of 2008 when compared to the same period in 2007. The estimated 2008 effective tax rate includes the utilization of Norwegian net operating loss carryforwards for which a valuation allowance had been previously provided.

Notes to Consolidated Financial Statements (Unaudited)

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 2005 tax year. Marathon believes it has made adequate provision for federal income taxes and interest which may become payable for years not yet settled. Further, Marathon is routinely involved in U.S. state and local income tax audits and foreign jurisdiction tax audits. Marathon believes all other audits will be resolved within the amounts paid and/or provided for these liabilities. As of June 30, 2008, Marathon’s income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated.


	United States (a)	2000 - 2007
	Canada	2000 - 2007
	Equatorial Guinea	2006 - 2007
	Libya	2006 - 2007
	United Kingdom	2005 - 2007

(a)

Includes federal, state and local jurisdictions.

8. Comprehensive Income

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2008		2007		2008		2007
Net income	$	774	$	1,550	$	1,505	$	2,267
Other comprehensive income, net of taxes:
Defined benefit postretirement plans (a)		(30)		(81)		(20)		(37)
Other		1		1		(1)		3

Comprehensive income	$	745	$	1,470	$	1,484	$	2,233

(a)

During the first six months of 2008 and 2007, changes were made to the estimates used to measure certain assumptions necessary in determining the funded status of Marathon’s postretirement benefit plans as of December 31, 2007 and 2006.

9. 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.

	June 30,		December 31,
(In millions)	2008		2007
Liquid hydrocarbons, natural gas and bitumen	$	2,476	$	1,203
Refined products and merchandise		2,245		1,792
Supplies and sundry items		294		282
Total, at cost	$	5,015	$	3,277

10. Property, Plant and Equipment

Exploratory well costs capitalized greater than one year after completion of drilling were $62 million as of June 30, 2008, a decrease of $38 million from December 31, 2007, primarily due to the transfer of the Ozona prospect exploratory wells in progress. A well on the Ozona prospect was re-entered and production casing was set in the second quarter of 2008.

11. Fair Value Measurements

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach

Notes to Consolidated Financial Statements (Unaudited)

and the cost approach, each of which include multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

SFAS No. 157 does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. SFAS No. 157 establishes a fair value hierarchy that prioritized the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows.

· Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

· Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

· Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Marathon uses a market or income approach for its recurring fair value measurements and endeavors to use the best information available. Accordingly, valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

The following table presents net financial assets (liabilities) accounted for at fair value on a recurring basis as of June 30, 2008:

(In millions)		Level 1		Level 2		Level 3		Total
Derivative Instruments:
Commodity	$	63	$	(2)	$	(988)	$	(927)
Interest rate		-		-		(1)		(1)
Foreign currency		-		14		1		15
Net derivative instruments	$	63	$	12	$	(988)	$	(913)

Other assets		15		-		-		15
Total at fair value	$	78	$	12	$	(988)	$	(898)

Deposits of $75 million in broker accounts covered by master netting agreements are netted against the value to arrive at the fair values of commodity derivatives. Derivatives in Level 1 are exchange-traded contracts for crude oil, natural gas, refined products and ethanol measured at fair value with a market approach using the close-of-day settlement prices for the market. Derivatives in Level 2 are measured at fair value with a market approach using broker quotes or third-party pricing services, which have been corroborated with market data. Level 3 derivatives are measured at fair value using either a market or income approach. Generally at least one input is unobservable, such as the use of an internally generated model or an external data source. Commodity derivatives in Level 3 include a $526 million liability related to two U.K. natural gas sales contracts that are accounted for as derivative instruments and a $432 million liability for crude oil options related to sales of Canadian synthetic crude oil. The fair value of the U.K. natural gas contracts is measured with an income approach based upon cash flows from expected sales volumes and the U.K. forward natural gas strip price. The crude oil options are measured at fair value using a Black-Scholes option pricing model, an income approach that utilizes market prices and market volatility obtained from a third-party service.

Notes to Consolidated Financial Statements (Unaudited)

The following is a reconciliation of the net beginning and ending balances recorded for derivative instruments classified as Level 3 in the fair value hierarchy for the three and six months ended June 30, 2008.

		Three Months Ended
(In millions)		June 30, 2008
Beginning balance	$	(485)
Total realized and unrealized losses:
Included in net income		(542)
Purchases, sales, issuances and settlements, net		39
Ending Balance	$	(988)

		Six Months Ended
(In millions)		June 30, 2008
Beginning balance	$	(359)
Total realized and unrealized losses:
Included in net income		(679)
Included in other comprehensive income		(1)
Purchases, sales, issuances and settlements, net		51
Ending Balance	$	(988)

The change in unrealized losses included in net income related to instruments held at June 30, 2008 was $557 million and $707 million for the second quarter and first six months of 2008. Amounts reported in net income are classified as sales and other operating revenues or cost of revenues for commodity derivative instruments, as net interest and other financing income for interest rate derivative instruments and as cost of revenues for foreign currency derivatives.

12. Debt

At June 30, 2008, Marathon had $981 million of commercial paper outstanding under its U.S. commercial paper program that is supported by its $3.0 billion revolving credit facility.

On March 12, 2008, Marathon issued $1 billion aggregate principal amount of senior notes bearing interest at 5.900 percent with a maturity date of March 15, 2018. Interest on the senior notes is payable semi-annually beginning September 15, 2008.

In February 2008, the 805 million Canadian dollar revolving term credit facility of Marathon Oil Canada Corporation was repaid and the facility was terminated.

13. Stock-Based Compensation Plans

The following table presents a summary of stock option award and restricted stock award activity for the second quarter 2008:

	Number of Shares Under Option (a)		Weighted Average Exercise Price	Restricted Stock Awards		Weighted Average Grant Date Fair Value


Outstanding at December 31, 2007	12,214,853	$	34.58	1,527,831	$	39.87
Granted (b)	2,463,528		52.01	369,741		49.71
Exercised	(282,194)		24.79	(535,356)		27.04
Canceled	(185,050)		49.66	(68,313)		39.29
Outstanding at June 30, 2008	14,211,137	$	37.60	1,293,903	$	48.03

(a)

Of the stock option awards outstanding as of June 30, 2008, 5,537,357, 8,171,670 and 502,110 were outstanding under the 2007 Incentive Compensation Plan, the 2003 Incentive Compensation Plan and the 1990 Stock Plan, including 749,282 stock options with tandem stock appreciation rights.

(b)

The weighted average grant date fair value of stock option awards granted was $13.09 per share.

Notes to Consolidated Financial Statements (Unaudited)

14. Stockholders’ Equity

Share repurchase – As of June 30, 2008, Marathon had acquired 64 million common shares at a cost of $2,815 million under its $5 billion authorized share repurchase program, including 6 million common shares acquired during the first six months of 2008 at a cost of $295 million.

Stock split – On April 25, 2007, Marathon’s Board of Directors declared a two-for-one split of the Company’s common stock which was affected 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.

15. Commitments and Contingencies

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

Marathon is a defendant, along with many other companies with refinery operations, in 58 cases in 12 states alleging methyl tertiary butyl ether (“MTBE”) contamination in groundwater. These cases, after their removal from state to federal court, have been consolidated in a multi-district litigation (“MDL”) in the Southern District of New York for pre-trial proceedings. On July 22, 2008, the judge issued an opinion holding that the MTBE settlement agreement represented a "good faith" settlement. The settling defendants, which included Marathon, were required to obtain a good faith determination for the California and Illinois cases in order to insure protection from contribution actions. The federal judge in the MDL concluded that both the approximate percentage of estimated liability being paid and the dollar amounts being allocated were reasonable. Similar approvals must also be obtained from state court judges in Illinois and California. The timing of payment under the settlement agreement could be impacted by an appeal of the judges' rulings on fairness. Such settlement is not expected to significantly impact Marathon’s consolidated results of operations, financial position or cash flows.

Contractual commitments – At June 30, 2008 and December 31, 2007, Marathon’s contract commitments to acquire property, plant and equipment totalled $4,130 million and $3,893 million. During the first six months of 2008, the majority of additional contract commitments were related to Gulf of Mexico projects.

16. Supplemental Cash Flow Information

	Six Months Ended June 30,
(In millions)	2008		2007

Net cash provided from operating activities included:
Interest paid (net of amounts capitalized)	$	54	$	20
Income taxes paid to taxing authorities		1,498		1,630

Commercial paper and revolving credit arrangements, net:
Commercial paper - issuances	$	28,992	$	-
- repayments		(28,013)		-
Credit agreements - borrowings	$	249	$	-
- repayments		(844)		-

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

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

Notes to Consolidated Financial Statements (Unaudited)

17. Subsequent Events

On July 31, 2008, Marathon announced that the board of directors is evaluating the separation of Marathon into two independent, publicly-traded companies. One entity would consist of the Exploration and Production, Integrated Gas and Oil Sands Mining businesses; and the other entity would consist of the Refining, Marketing and Transportation business.

On July 9, 2008, Marathon entered into an agreement to sell its outside-operated and undeveloped offshore acreage in Norway, including $41 million in associated deferred income tax assets. The proceeds before closing adjustments are $416 million. The transaction is expected to close by the end of 2008. Beginning the third quarter of 2008, the operating assets, the net carrying value of which is not significant, will be classified as held for sale until the transaction closes.

18. Accounting Standards Not Yet Adopted

In June 2008, the FASB issued FASB Staff Position on EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”) which provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method. For Marathon, FSP EITF 03-6-1 is effective January 1, 2009 and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) will be adjusted retrospectively to conform to its provisions. Early application of FSP EITF 03-6-1 is not permitted. Although restricted stock awards meet this definition of participating securities, Marathon does not expect application of FSP EITF 03-6-1 to have a significant impact on its reported EPS.

On April 25, 2008, the FASB issued FASB Staff Position on FAS 142-3 (FSP 142-3) which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets. The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. For Marathon, FSP 142-3 will be effective on January 1, 2009, early adoption is prohibited. The provisions of FSP 142-3 is to be applied prospectively to intangible assets acquired after the effective date, except for the disclosure requirements which must be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. Marathon is currently evaluating the provisions of this statement.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” This statement expands the disclosure requirements for derivative instruments to provide information regarding (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. To meet these objectives, the statement requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. For Marathon, SFAS No. 161 is effective January 1, 2009. The statement encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. Marathon is currently evaluating the provisions of this statement.

In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS No. 141 (R)”). This statement significantly changes the accounting for business combinations. Under SFAS No.141(R), an acquiring entity will be required to recognize all the assets acquired, liabilities assumed and any non-controlling interest in the acquiree at their acquisition-date fair value with limited exceptions. The statement expands the definition of a business and is expected to be applicable to more transactions than the previous business combinations standard. The statement also changes the accounting treatment for changes in control, step acquisitions, transaction costs, acquired contingent liabilities, in-process research and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination and changes in income tax uncertainties after the acquisition date. Accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting goodwill. Additional disclosures are also required. For Marathon, SFAS No. 141(R) will be applied prospectively effective January 1, 2009.

Notes to Consolidated Financial Statements (Unaudited)

Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - An Amendment of ARB No. 51.” This statement establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement clarifies that a noncontrolling interest in a subsidiary (sometimes called a minority interest) is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements, but separate from the parent's equity. It requires that the amount of consolidated net income attributable to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement. SFAS No. 160 clarifies that changes in a parent's ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, this statement requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated, based on the fair value of the noncontrolling equity investment on the deconsolidation date. Additional disclosures are required that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. For Marathon, SFAS No. 160 will be effective January 1, 2009 and early adoption is prohibited. The statement must be applied prospectively, except for the presentation and disclosure requirements which must be applied retrospectively for all periods presented in consolidated financial statements. 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 liquid hydrocarbons and natural gas; mining, extraction and transportation of bitumen from oil sands deposits in Alberta, Canada, and upgrading of the bitumen for the production and marketing of synthetic crude oil and by-products; domestic refining, marketing and transportation of crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States; and worldwide marketing and transportation of products manufactured from natural gas, such as LNG and methanol, and development of other projects to link stranded natural gas resources with key demand areas. Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Consolidated Financial Statements and Selected Notes to Consolidated Financial Statements, the Supplemental Statistics and our 2007 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 2007 Annual Report on Form 10-K.

We hold a 60 percent interest in Equatorial Guinea LNG Holdings Limited (“EGHoldings”). Effective May 1, 2007, we no longer consolidate EGHoldings. Our investment is accounted for prospectively using the equity method of accounting. Unless specifically noted, amounts presented for the Integrated Gas segment for periods prior to May 1, 2007, include amounts related to the minority interests.

Overview and Outlook

Exploration and Production (“E&P”)

Net liquid hydrocarbon and natural gas sales during the second quarter and first six months of 2008 averaged 350 and 364 thousand barrels of oil equivalent per day (“mboepd”), an increase of 4 percent and 7 percent over the same periods of 2007, primarily due to increased sales of natural gas from the Alba field offshore Equatorial Guinea.

The Alvheim development offshore Norway commenced production on June 8, 2008. Currently there are five wells producing from the Alvheim portion of the development. The Vilje field, which is tied back to the Alvheim floating production, storage and offloading vessel, began producing July 31, 2008. Based on results thus far, Alvheim/Vilje is expected to reach a combined production rate of 75 mboepd net to Marathon (120 mboepd gross) before the end of 2008. We have a 65 percent operated interest in the Alvheim fields and a 47 percent outside-operated interest in the Vilje field.

The Neptune development in the Gulf of Mexico commenced production of oil and natural gas in early July 2008 and reached full oil capacity after 15 days of operations. The field is currently producing from five wells and the sixth well is expected on line in August. Marathon has a 30 percent outside-operated interest in the Neptune development. The facility’s design capacity is 50,000 barrels per day (“bpd”) of oil and 50 million cubic feet per day (“mmcfd”) of natural gas.

We continue to increase production from the Williston Basin (the Bakken shale formation) in North Dakota. We currently have seven rigs drilling. We expect to drill approximately 65 company-operated wells in 2008 and will have over 100 wells in the play by the end of 2008. Our net production from the Bakken shale increased 130 percent from the fourth quarter 2007 rate of 2,170 barrels of oil equivalent per day (“boepd") to the second quarter 2008 rate of 5,070 boepd, and is currently in excess of 6,000 boepd.

During the second quarter of 2008 we were awarded the 15 blocks bid in the Central Gulf of Mexico Lease Sale No. 206 conducted by the Minerals Management Service in the first quarter of 2008. Two blocks are 100 percent Marathon, and the remaining blocks were bid with partners, at a total cost of $121 million. Initial drilling on these leases, and those acquired at Lease Sale No. 205 in October 2007, is planned for 2009. We are also currently participating in two deepwater exploration wells in the Gulf of Mexico with a third well planned later this year.

During the first six months of 2008, in the Gulf of Mexico, we drilled a successful appraisal well on the Droshky discovery and participated in the successful Stones appraisal well. Future drilling activity is being planned which will determine the potential commerciality of this discovery. We hold a 25 percent outside-operated interest in Stones.

Offshore Angola, we have received approval to proceed with the first deepwater oil development project in Block 31. The development is comprised of the Plutao, Saturno, Venus and Marte (“PSVM”) fields. Key contracts are ready to be awarded and construction work is expected to begin later this year. A total of 48 production and injection wells are planned for the PSVM development.

During the first six months of 2008, we participated in the Portia discovery on Block 31 offshore Angola which was our 27th discovery on Blocks 31 and 32. We also participated in three wells in our Angola exploration and appraisal program that have reached total depth, the results of which will be announced upon receipt of government and partner approval. At June 30, 2008 we were participating in one appraisal well in Block 32. On Block 31 we are currently drilling an exploratory well and plan to drill two additional exploratory wells in 2008. We hold a 10 percent outside-operated interest in Block 31 and a 30 percent outside-operated interest in Block 32.

In Indonesia, we are the operator of a drilling rig consortium which has secured a two-year contract for a deepwater exploration drilling rig. The rig will be used for deepwater exploration activities by us and four other companies in Indonesia. Initial drilling is expected to commence in the second half of 2009. The participants have the right to extend this rig commitment.

We decided to cease efforts to pursue exploration opportunities in Ukraine and will close our office in Kiev. We anticipate completing this withdrawal during the third quarter of 2008.

During the first quarter of 2008, we transferred our interest in an exploration and production license in Sudan to the operator, and as a result, we no longer have any interests in Sudan.

On July 9, 2008, we entered into an agreement to sell our outside-operated interests (24 percent of Heimdal field, 47 percent of Vale field and 20 percent of Skirne field) and associated undeveloped acreage offshore Norway, including $41 million in associated deferred income tax assets. Total proceeds before closing adjustments are expected to be $416 million. The transaction is expected to close during the late third quarter or early fourth quarter of 2008.

The above discussion includes forward-looking statements with respect to the Gulf of Mexico lease sale, the timing and levels of future production from the Alvheim/Vilje project, Blocks 31 and 32 offshore Angola, the anticipated disposition of interests in the Heimdal area and related assets, 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 developments and Block 31, 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 disposition of interests in the Heimdal area could also be adversely affected by customary closing conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Oil Sands Mining (“OSM”)

Our bitumen production, before royalties, was 24 thousand barrels per day (“mbpd”) in the second quarter and in the first six months of 2008. Second quarter production was lower than expected due to a revised plan to manage the disposal of tailings that resulted in mining a lower grade ore, as well as planned and unplanned maintenance at the mine. Tailings consist primarily of water and sediment that remains after the bitumen is extracted from the ore. In addition, although operations reliability improved over the fourth quarter of 2007, cold weather caused downtime in the first quarter of 2008.

The Athabasca Oil Sands Project (“AOSP”) Phase 1 expansion, which includes construction of mining and extraction facilities at the Jackpine mine, expansion of treatment facilities at the existing Muskeg River mine, expansion of the Scotford upgrader and development of related infrastructure, is anticipated to begin operations in late 2010. This is a forward-looking statement which could be affected by transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects.

During the first quarter of 2008, the royalty calculation methodology for the AOSP was revised to allow for additional eligible costs to the project. As a result, the project reverted to the one percent gross royalty (in lieu of the 25 percent post-recovery rate) as of July 1, 2007. Due to the continued strong commodity price environment, it is anticipated that the third quarter of 2008, the AOSP will revert to the 25 percent net royalty regime for the existing operations.

Refining, Marketing and Transportation (“RM&T”)

In the second quarter and first six months of 2008, our total refinery throughputs were 6 percent and 8 percent lower than in the second quarter and first six months of 2007. Crude oil refined likewise decreased 5 percent and 9 percent in the same periods.

Our ethanol blending program increased to 55 mbpd in the second quarter of 2008 from 40 mbpd in the second quarter of 2007. For the first six months of 2008 ethanol we blended 28 percent more ethanol than in the same period of 2007. The future expansion or contraction of our ethanol blending program will be driven by the economics of ethanol supply and government regulations.

Second quarter of 2008 Speedway SuperAmerica LLC same store gasoline sales volume declined five percent when compared to the second quarter of 2007 while same store merchandise sales increased by one percent for the same period.

Construction continues to progress as planned on the Garyville refinery expansion project. In the second quarter of 2008, permits were received and construction was begun on our heavy oil upgrading and expansion project at the Detroit refinery. The Detroit project increases the refinery’s ability to process heavy crude oil by 80 mbpd.

We are no longer pursuing the October 2007 agreement to purchase of four light product terminals in Ohio and an ownership interest in a refined product pipeline.

The above discussion includes forward-looking statements with respect to the Garyville and Detroit refinery expansion projects. Factors that could affect those projects include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals, and other risks customarily associated with construction projects. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas (“IG”)

We own 45 percent of Atlantic Methanol Production Company LLC (“AMPCO”) and 60 percent of Equatorial Guinea LNG Holdings Limited (“EGHoldings”), both of which are accounted for under the equity method of accounting. AMPCO operates a methanol plant and EGHoldings operates an LNG production facility, both located on Bioko Island, Equatorial Guinea. Alba field dry natural gas, which remains after the condensate and LPG are removed, is supplied to both of these facilities under long-term contracts at fixed prices. We consider the prices under these contracts to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances, because of the location of and limited local demand for natural gas in Equatorial Guinea.

The EGHoldings LNG production facility delivered 14 cargoes during the second quarter of 2008 compared to 3 cargoes in the second quarter of 2007, which was its first quarter of production. As a result, our share of LNG sales worldwide totaled 6,402 metric tonnes per day (“mtpd”) for the second quarter of 2008 compared to 1,997 mtpd in the second quarter of 2007 and 6,657 mtpd in the first six months of 2008 compared to 1,582 mtpd in the first six months of 2007. These LNG sales volumes include both consolidated sales volumes and our share of the sales volumes of equity method investees. LNG sales from Alaska are conducted through a consolidated subsidiary. LNG and methanol sales from Equatorial Guinea are conducted through equity method investees.

A planned turnaround at the LNG production facility started in mid-July and the facility was back to full capacity by early August. The methanol plant experienced a shutdown at the beginning of the third quarter of 2008 due to a process issue. As of the date of this filing, the facility has been returned to full production.

Evaluation of Separation of Business

On July 31, 2008, Marathon announced that the board of directors is evaluating the separation of Marathon into two independent, publicly-traded companies, each focused on its own set of business opportunities. One entity would consist of the Exploration and Production, Integrated Gas and Oil Sands Mining businesses; and the other entity would consist of the Refining, Marketing and Transportation business. Results of this evaluation and a decision by the board of directors are anticipated during the fourth quarter of 2008. Should the decision be made to separate, the separation would likely occur during the first quarter of 2009.

The above discussion includes forward-looking statements with respect to the evaluation of separating Marathon into two distinct businesses. Some factors that could potentially affect these forward-looking statements include board approval, future financial condition and operating results, and economic, business, competitive and/or regulatory factors affecting our business. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

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 changes to our critical accounting estimates subsequent to December 31, 2007, except those related to fair value estimates resulting from the adoption of SFAS No. 157 as discussed below.

Fair Value Estimates

On January 1, 2008, we adopted SFAS No. 157 for those financial assets and liabilities recognized or disclosed at fair value in the consolidated financial statements on a recurring basis. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. It does not require us to make any new fair value measurements, but rather establishes a fair value hierarchy that prioritizes the inputs to the valuation techniques used to measure fair value. Level 1 inputs are given the highest priority in the fair value hierarchy, as they represent observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date, while Level 3 inputs are given the lowest priority, as they represent unobservable inputs that are not corroborated by market data. Valuation techniques that maximize the use of observable inputs are favored.

FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” deferred the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, which for us includes impairments of goodwill, intangible assets and other long-lived assets, and initial measurement of asset retirement obligations, asset exchanges, business combinations and partial sales of proved properties.

For Marathon, the primary impact from the adoption of SFAS No. 157 at January 1, 2008, related to the fair value measurement of derivative instruments. Derivatives in Level 1 are exchange-traded contracts for crude oil, natural gas, refined products and ethanol measured at fair value with a market approach using the close-of-day settlement prices for the market. Derivatives in Level 2 are measured at fair value with a market approach using broker quotes or third-party pricing services, which have been corroborated with market data. Level 3 derivatives are measured at fair value using either a market or income approach. Generally at least one input is unobservable, such as the use of an internally generated model or an external data source. Commodity derivatives in Level 3 include a $526 million liability related to two U.K. natural gas sales contracts that are accounted for as derivative instruments and a $432 million liability for crude oil options related to sales of Canadian synthetic crude oil. The fair value of the U.K. natural gas contracts is measured with an income approach based upon cash flows from expected sales volumes and the U.K. forward natural gas strip price. The crude oil options are measured at fair value using a Black-Scholes option pricing model, an income approach that utilizes market prices and market volatility obtained from a third-party service. Additional information about derivatives may be found in Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Management's Discussion and Analysis of Results of Operations

Consolidated Results of Operations

Revenues are summarized by segment in the following table:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2008		2007		2008		2007
E&P	$	3,424	$	2,141	$	6,416	$	3,990
OSM		16		-		215		-
RM&T		18,975		14,735		34,001		25,819
IG		21		68		40		124

Segment revenues		22,436		16,944		40,672		29,933

Elimination of intersegment revenues		(359)		(199)		(703)		(340)
Gain (loss) on U.K. natural gas contracts		(165)		(9)		(235)		12

Total revenues	$	21,912	$	16,736	$	39,734	$	29,605

Items included in both revenues and costs and
expenses:

Consumer excise taxes on petroleum products
and merchandise	$	1,295	$	1,307	$	2,511	$	2,504

E&P segment revenues increased $1,283 million in the second quarter and $2,426 million in the first six months of 2008 from the comparable prior-year periods. Increased liquid hydrocarbon realizations account for the majority of the revenue increase. Partially offsetting the increase in liquid hydrocarbon realizations were lower sales volumes. International liquid hydrocarbon sales volumes were lower in the second quarter due primarily to the timing of liftings of crude oil. Liquid hydrocarbon and natural gas sales volumes in the U.S. were lower due primarily to natural production declines in the Gulf of Mexico. While international natural gas sales volumes increased, the majority of the increase was due to sales to the EGHoldings LNG production facility that began operations in the second quarter of 2007. This increase in fixed-price sales volumes limited the increase in our average international natural gas realizations. Our share of the income ultimately generated by the subsequent export of LNG produced by EGHoldings, as well as methanol produced by AMPCO, is reflected in our Integrated Gas segment as discussed below.

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

Excluded from E&P segment revenues were losses of $165 million and gains of $9 million for the second quarters of 2008 and 2007 related to natural gas sales contracts in the United Kingdom that are accounted for as derivative instruments. For the first six months of 2008 and 2007 losses of $235 million and gains of $12 million are excluded from E&P segment revenues.

OSM segment revenues totaled $16 million in the second quarter and $215 million in the first six months of 2008. Revenues in both periods were reduced by losses on derivative instruments intended to mitigate price risk related to future sales of synthetic crude. The pretax losses on derivative instruments were $338 million in the second quarter and $386 million in the first six months of 2008. Net synthetic crude sales for the second quarter of 2008 were 31 mbpd at an average realized price of $ 116 per barrel.

RM&T segment revenues increased $4,240 million in the second quarter of 2008 and $8,182 million in the first six months of 2008 from the comparable prior-year periods primarily reflecting increased refined product and liquid hydrocarbon selling prices, slightly offset by lower refined product and liquid hydrocarbon sales volumes.

For information on segment income, see Segment Results.

Income from equity method investments increased $139 million in the second quarter of 2008 and $241 in the first six months of 2008 from the comparable prior-year periods. Income from the EGHoldings LNG production facility accounts for most of the increase, as it began operations in May 2007. Twenty-nine cargoes of LNG were delivered during the first six months of 2008: 14 cargoes in the second quarter and 15 cargoes in the first quarter as compared to 3 cargoes in the 2007 period in which operations commenced.

Cost of revenues increased $6,184 million and $11,033 million in the second quarter and first six months of 2008 from the comparable prior-year periods. These increases resulted primarily from increases in acquisition costs of crude oil, refinery charge and blend stocks and purchased refined products in the RM&T segment.

Provision for income taxes decreased $424 million and $474 million in the second quarter and first six months of 2008 from the comparable periods of 2007 as a result of decreases in income before income taxes. The geographic sources of income and related tax expense contributed to the increase in the effective income tax rate in the first six months of 2008 when compared to the same period in 2007. The estimated 2008 effective tax rate includes the utilization of Norwegian net operating loss carryforwards for which a valuation allowance had been previously provided.

The following is an analysis of the effective income tax rates for the first six months of 2008 and 2007:

	Six Months Ended June 30,
	2008		2007
Statutory U.S. income tax rate	35	%	35	%
Effects of foreign operations, including foreign tax credits	14		9
State and local income taxes, net of federal income tax effects	1		2
Other tax effects	(2)		(1)
Effective income tax rate for continuing operations	48	%	45	%

Discontinued operations in 2007 is a sales price adjustment on the June 2006 sale of our Russian oil exploration and production businesses.

Segment Results

Segment income is summarized in the following table:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2008			2007	2008		2007
E&P

United States	$	359	$	173	$	603		$	323
International		469		227		909			462

E&P segment		828		400		1,512			785

OSM		(157)		-		(130)			-

RM&T		158		1,246		83			1,591

IG		102		12		201			31

Segment income		931		1,658		1,666			2,407
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(73)		(111)		(41)			(154)
Gain (loss) on U.K. natural gas contracts		(84)		(5)		(120)			6
Discontinued operations		-		8		-			8

Net income	$	774	$	1,550	$	1,505		$	2,267

United States E&P income increased $186 million, or 108 percent, and $280 million, or 87 percent, in the second quarter and first six months of 2008 compared to the same periods of 2007. Pretax income increased $312 million and $451 million in the same periods. The higher pretax income in both periods is primarily a result of revenue increases as a result of higher liquid hydrocarbon realizations. Higher natural gas realizations contributed to the income increase, partially offset by lower liquid hydrocarbon and natural gas sales volumes.

International E&P income increased $242 million, or 107 percent, and $447 million, or 97 percent, in the second quarter and first six months of 2008 compared to the same periods of 2007. Pretax income increased $490 million and $923 million in the same periods. The higher pretax income in both periods is primarily a result of revenue increases from higher liquid hydrocarbon realizations and natural gas sales volumes, as discussed above.

OSM segment income was a loss of $157 million and $130 million in the second quarter and first six months of 2008. The second quarter loss includes a $250 million after-tax loss, of which $220 million is unrealized, on derivative

instruments intended to mitigate price risk related to future sales of synthetic crude oil. For the first six months of 2008, the after-tax derivative loss was $286 million, of which $252 million is unrealized.

RM&T segment income decreased by $1,088 million, or 87 percent, and $1,508 million, or 95 percent, in the second quarter and first six months of 2008 compared to the same periods of 2007. Pretax income decreased $1,701 million and $2,364 million in the same periods. The decreases in RM&T pretax income in both periods are primarily the result of a lower refining and wholesale marketing gross margin which is consistent with market indicators. Our refining and wholesale marketing gross margin averaged 8.35 cents per gallon in the second quarter of 2008 and 4.20 cents per gallon in the first six months of 2008 compared to 39.25 cents per gallon and 26.34 cents per gallon in the comparable periods of 2007. The major cause of this margin decline was the significant increase in crude oil prices in 2008, which we were not able to fully pass along to our wholesale customers.

Our refining and wholesale marketing gross margin also included pretax derivative losses of $187 million and $307 million in the second quarter and first six months of 2008 compared to losses of $139 million and $112 million in the second quarter and first six months of 2007. For a more complete explanation of our strategies to manage market risk related to commodity prices, see Quantitative and Qualitative Disclosures About Market Risk.

Crude oil refined averaged 1,023 mbpd and 934 mbpd, during the second quarter and first six months of 2008, 49 mbpd and 87 mbpd lower than the averages for the same periods of 2007.

IG segment income increased $90 million in the second quarter of 2008 and $170 million in the first six months of 2008 compared to the same periods of 2007 due primarily to increased income from our equity method investment in EGHoldings. The first LNG deliveries from EGHoldings’ LNG production facility were made in the second quarter of 2007.

Management’s Discussion and Analysis of Cash Flows and Liquidity

Cash Flows

Net cash provided from operating activities totaled $2,955 million in the first six months of 2008, compared to $2,366 million in the first six months of 2007. This resulted primarily from favorable working capital changes in our RM&T segment.

Net cash used in investing activities totaled $3,158 million in the first six months of 2008, compared to $1,728 million in the first six months of 2007. Capital expenditures were $3,382 million compared with $1,699 million for the comparable prior-year period, with the increased spending related primarily to the Alvheim development and Gulf of Mexico projects in the E&P Segment, the AOSP expansion in the OSM segment and the Garyville refinery expansion in the RM&T segment. See Supplemental Statistics for information regarding capital expenditures by segment.

Net cash provided by financing activities was $266 million in the first six months of 2008, compared to $896 million used by financing activities in the first six months of 2007. Significant uses of cash in financing activities during both periods included stock repurchases, repayments of maturing debt and dividend payments. Financing activities for the first six of 2008 included the issuance of $1.0 billion in senior notes, $981 million of commercial paper and the payment and termination of the Marathon Oil Canada Corporation (previously Western Oil Sands, Inc.) revolving credit facility. Financing activities for the first six months of 2007 included borrowings of $578 million from the Norwegian export credit agency.

Dividends to Stockholders

On July 31, 2008, our Board of Directors declared a dividend of 24 cents per share, payable September 10, 2008, to stockholders of record at the close of business on August 20, 2008.

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. Because of the alternatives available to us, including internally generated cash flow and potential asset sales, 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 ultimately may be paid in connection with contingencies.

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+. Following our announcement regarding the possible separation of the upstream and downstream businesses, Moody's Investors Service placed our ratings under review for a possible downgrade. Standard & Poor's Ratings Services placed our ratings on credit watch with negative implications. Fitch Ratings affirmed our current ratings and maintained their previously announced negative outlook.

We have a committed $3.0 billion revolving credit facility with third-party financial institutions. At June 30, 2008, there were no borrowings against this facility and we had commercial paper in the amount of $981 million outstanding under our U.S. commercial paper program that is backed by the revolving credit facility. Effective April 3, 2008, Marathon entered into an amendment to its revolving credit facility, extending the termination date on $2,625 million from May 2012 to May 2013. The remaining $375 million continues to have a termination date of May 2012.

On March 12, 2008, we issued $1 billion aggregate principal amount of senior notes bearing interest at 5.900 percent with a maturity date of March 15, 2018. Interest on the senior notes is payable semi-annually beginning September 15, 2008.

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

Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 24 percent at June 30, 2008, compared to 22 percent at year-end 2007 as shown below. This includes $488 million of debt that is serviced by United States Steel Corporation (“United States Steel”).

		June 30,		December 31,
(In millions)		2008		2007
Commercial paper	$	981	$	-
Long-term debt due within one year		87		1,131
Long-term debt		7,059		6,084

Total debt	$	8,127	$	7,215

Cash	$	1,270	$	1,199
Trusteed funds from revenue bonds	$	502	$	744
Equity	$	20,109	$	19,223

Calculation:

Total debt	$	8,127	$	7,215
Minus cash		1,270		1,199
Minus trusteed funds from revenue bonds		502		744

Total debt minus cash	$	6,355	$	5,272

Total debt		8,127		7,215
Plus equity		20,109		19,223
Minus cash		1,270		1,199
Minus trusteed funds from revenue bonds		502		744

Total debt plus equity minus cash	$	26,464	$	24,495

Cash-adjusted debt-to-capital ratio		24%		22%

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.

Stock Repurchase Program

Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion. As of June 30, 2008, we had repurchased 64 million common shares at a cost of $2,815 million. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program’s authorization does not include specific price targets or timetables; however, we expect to complete the authorized purchases by the end of 2009, although repurchases are likely to be less ratable than in prior years. 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 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, refining and mining 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 June 30, 2008, our consolidated contractual cash obligations have increased by $6,542 million from December 31, 2007. Our purchase obligations under crude oil, refinery feedstock, refined product and ethanol contracts, which are primarily short term, increased $5,215 million primarily related to increased crude oil prices in combination with increased charge and blend stock prices and volumes, partially offset by lower crude oil volumes. Short and long-term debt increased by $948 million primarily due to the issuance of commercial paper. There have been no other significant changes to our obligations to make future payments under existing contracts subsequent to December 31, 2007. 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, 2007.

Off-Balance Sheet Arrangements

Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources; and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on our liquidity and capital resources. There have been no significant changes to our off-balance sheet arrangements subsequent to December 31, 2007.

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 $528 million as of June 30, 2008. Of this amount, $268 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 $50 million of the total PTC debt.

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.

The EPA is in the process of implementing regulations to address current National Ambient Air Quality Standards (“NAAQS”) for fine particulate emissions and ozone. In connection with these standards, the EPA will designate certain areas as “nonattainment,” meaning that the air quality in such areas does not meet the NAAQS. To address these nonattainment areas, the EPA proposed a rule in 2004 called the Interstate Air Quality Rule (“IAQR”) that would

require significant emissions reductions in numerous states. The final rule, promulgated in 2005, was renamed the Clean Air Interstate Rule (“CAIR”). While the EPA expected that states would meet their CAIR obligations by requiring emissions reductions from electric generating units, states were to have the final say on what sources they regulate to meet attainment criteria. Significant uncertainty in the final requirements of this rule comes from litigation (State of North Carolina, et al v. EPA). On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAIR in its entirety and remanded it to EPA to promulgate a rule consistent with the Court’s opinion. The CAIR will be significantly altered, and it could result in changes in emissions control strategies. 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, in 2007, the EPA proposed a revised ozone standard. This revised ozone standard was promulgated in March of 2008, and the EPA is starting 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 EPA has issued a revised rule and states have taken further action to implement that rule. We also cannot reasonably estimate the final financial impact of the revised ozone standard until the implementing rules are established and judicial challenges over the revised ozone standard are resolved.

We previously reported that we have not finalized our strategy or cost estimate to comply with Mobile Source Air Toxics II regulations relating to benzene, but the cost estimate may be approximately $1 billion over a three-year period beginning in 2008, with $16 million spent through June 30, 2008. This cost estimate is a forward-looking statement and is subject to change as front-end engineering and design work is completed in 2008.

There have been no other significant changes to our environmental matters subsequent to December 31, 2007.

Other Contingencies

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

Accounting Standards Not Yet Adopted

In June 2008, the FASB issued FASB Staff Position on EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”) which clarifies that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method described in paragraphs 60 and 61 of SFAS No. 128, “Earnings per Share.” For us, FSP EITF 03-6-1 is effective January 1, 2009 and all prior-period EPS data presented shall be adjusted retrospectively to conform to its provisions. Early application of FSP EITF 03-6-1 is not permitted. Although our restricted stock awards meet this definition of participating securities, we do not expect application of FSP EITF 03-6-1 to have a significant impact on our reported EPS.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” This statement expands the disclosure requirements for derivative instruments to provide information regarding (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. To meet these objectives, the statement requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. For us, SFAS No. 161 is effective January 1, 2009. The statement encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. We are currently evaluating the provisions of this statement.

acquiree at their acquisition-date fair value with limited exceptions. The statement expands the definition of a business and is expected to be applicable to more transactions than the previous business combinations standard. The statement also changes the accounting treatment for changes in control, step acquisitions, transaction costs, acquired contingent liabilities, in-process research and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination and changes in income tax uncertainties after the acquisition date. Accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting goodwill. Additional disclosures are also required. For us, SFAS No. 141(R) will be applied prospectively effective January 1, 2009.

Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - An Amendment of ARB No. 51.” This statement establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement clarifies that a noncontrolling interest in a subsidiary (sometimes called a minority interest) is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements, but separate from the parent's equity. It requires that the amount of consolidated net income attributable to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement. SFAS No. 160 clarifies that changes in a parent's ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, this statement requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated, based on the fair value of the noncontrolling equity investment on the deconsolidation date. Additional disclosures are required that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. For us, SFAS No. 160 will be effective January 1, 2009 and early adoption is prohibited. The statement must be applied prospectively, except for the presentation and disclosure requirements which must be applied retrospectively for all periods presented in consolidated financial statements. We are currently evaluating the provisions of this statement.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks related to the volatility of crude oil, natural gas and refined product prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. We are also exposed to market risks related to changes in interest rates and foreign currency exchange rates. We employ various strategies, including the use of financial derivative instruments, to manage the risks related to these fluctuations. We are at risk for changes in the fair value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes related to the underlying commodity or financial transaction.

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

Commodity Price Risk

Our strategy is 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 commodity derivative instruments, including futures, forwards, swaps and combinations of options, as part of an overall program to manage commodity price risk in our different businesses. We also may utilize the market knowledge gained from these activities to do a limited amount of trading not directly related to our physical transactions.

Our E&P segment primarily uses commodity derivative instruments to mitigate the natural gas price risk during the time that the natural gas is held in storage before it is sold or on natural gas that is purchased to be marketed with our own natural gas production. We also may use commodity derivative instruments selectively to protect against price decreases on portions of our future sales of liquid hydrocarbons or natural gas when it is deemed advantageous to do so.

Certain natural gas contracts in the United Kingdom that are accounted for as derivative instruments are excluded from E&P segment income. For additional information on these U.K. natural gas contracts, see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Fair Value Estimates.

Our OSM segment may use commodity derivative instruments to protect against price decreases on portions of our future sales of synthetic crude oil when it is deemed advantageous to do so.

Our RM&T segment primarily uses commodity derivative instruments on a selective basis to mitigate crude oil price risk during the time that crude oil inventories are held before they are actually refined into salable petroleum products. We also use derivative instruments in our RM&T segment to manage price risk related to refined petroleum products, feedstocks used in the refining process and ethanol blended with refined petroleum products. We use commodity derivative instruments to mitigate crude oil price risk between the time that crude oil purchases are priced and when they are actually refined into salable petroleum products, but we have decreased our use of derivatives in this manner as described further below.

Generally, commodity derivative instruments used in our E&P segment qualify for hedge accounting. As a result, we do not recognize in net income any changes in the fair value of those derivative instruments until the underlying physical transaction occurs. We have not qualified commodity derivative instruments used in our OSM or RM&T segments for hedge accounting. As a result, we recognize in net income all changes in the fair value of derivative instruments used in those operations.

Open Commodity Derivative Positions as of June 30, 2008 and Sensitivity Analysis

At June 30, 2008, our E&P segment held open derivative contracts to mitigate the price risk on natural gas held in storage or purchased to be marketed with our own natural gas production in amounts that were in line with normal levels of activity. At June 30, 2008, we had no open derivative contracts related to our future sales of liquid hydrocarbons and natural gas and therefore remained substantially exposed to market prices of these commodities.

Our OSM segment holds options indexed to West Texas Intermediate crude oil, covering a three-year period ending December 31, 2009. The premiums for the put options were partially offset by the sale of call options for the same period, resulting in a net premium liability. Payment of the net premium liability is deferred until the settlement of the option contracts. We have entered no new derivatives since we acquired the OSM business.

At June 30, 2008, the number of open derivative contracts held by our RM&T segment was lower than in previous periods. During the second quarter of 2008, we decreased our use of derivatives to mitigate crude oil price risk between the time that domestic spot crude oil purchases are priced and when they are actually refined into salable petroleum

products. Instead, we are addressing this price risk through other means, including changes in contractual terms and crude oil acquisition practices.

Additionally, in previous periods, certain contracts in our RM&T segment for the purchase or sale of commodities were not qualified or designated as normal purchase or normal sales under generally accepted accounting principles and therefore were accounted for as derivative instruments. During the second quarter of 2008, as we decreased our use of derivatives, we began to designate such contracts for the normal purchase and normal sale exclusion as we entered into new arrangements. We intend to continue to designate new contracts as normal purchase or normal sales contracts.

Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent changes in commodity prices for open commodity derivative instruments as of June 30, 2008, is provided in the following table. 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.


	Incremental Decrease in IFO Assuming a Hypothetical Price Change of (a)
(In millions)		10	%		25	%
Commodity Derivative Instruments: (b)
Crude oil	$	159	(c)	$	397	(c)
Natural gas		94	(c)		214	(c)
Refined products		21	(c)		53	(c)

(a)

We remain at risk for possible changes in the market value of commodity 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 for each open contract position at June 30, 2008. Included in the natural gas impacts above are $96 million and $218 million for hypothetical price changes of 10 percent and 25 percent related to the U.K. natural gas contracts accounted for as derivative instruments. We evaluate our portfolio of commodity derivative instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed continuously and master netting agreements are used when practical. Changes to the portfolio after June 30, 2008, would cause future IFO effects to differ from those presented above.

(b)

The number of net open contracts for the E&P segment varied throughout the second quarter of 2008, from a low of 43 contracts on April 1, 2008, to a high of 234 contracts on May 4, 2008, and averaged 111 for the quarter. The number of net open contracts for the RM&T segment varied throughout the second quarter of 2008, from a low of 13 contracts on May 16, 2008, to a high of 4,794 contracts on June 18, 2008, and averaged 2,013 for the quarter. The number of net open contracts for the OSM segment varied throughout the second quarter of 2008, from a low of 19,215 contracts on June 30, 2008 to a high of 21,350 contracts on April 1, 2008 and averaged 20,277 for the quarter. The commodity derivative 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)	Price increase.

Interest Rate Risk

We are impacted by interest rate fluctuations which affect the fair value of certain financial instruments. 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 mix of fixed and floating interest rate debt in our portfolio. During the second quarter of 2008, we entered into new interest rate swap agreements for a notional amount of $250 million. As of June 30, 2008, we had multiple interest rate swap agreements with a total notional amount of $450 million, designated as a fair value hedge, which effectively resulted in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates. The weighted average floating rate on these swap agreements is LIBOR plus 2.060 percent.

Sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates in financial assets and liabilities, as of June 30, 2008, is provided in the following table.

				Incremental Change in Fair Value
(In millions)	Fair Value			Incremental Change in Fair Value
Financial assets (liabilities): (a)
Receivable from United States Steel		$	495		$	9 (c)
Interest rate swap agreements		$	- (b)		$	6 (c)
Long-term debt, including amounts due within one year		$	(7,897)(b)		$	(367)(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 receivables from United States Steel and long-term debt, this assumes a 10 percent decrease in the weighted average yield-to-maturity of our receivables and long-term debt at June 30, 2008. For interest rate swap agreements, this assumes a 10 percent decrease in the effective swap rate at June 30, 2008.

At June 30, 2008, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to interest rate fluctuations. Our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value.

Foreign Currency Exchange Rate Risk

We manage our exposure to foreign currency exchange rates by utilizing forward and option contracts. The primary objective of this program is to reduce our exposure to movements in foreign currency exchange rates by locking in such rates. The following tables summarize our derivative foreign currency instruments as of June 30, 2008.

(In millions)	Period	Notional Amount		Average Forward Rate (a)	Fair Value (b)
Foreign Currency Forwards:
Dollar (Canada)	November 2008 - December 2008	$	51	1.016 (d)	$	-
Euro	July 2008 – November 2008	$	28	1.278 (d)	$	6
Kroner (Norway)	July 2008 – October 2009	$	48	6.086 (c)	$	8

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

(b)	Fair value was based on market rates.

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

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

(In millions)	Period	Notional Amount		Weighted Average Exercise Price (a)	Fair Value (b)
Foreign Currency Options:
Dollar (Canada)	July 2008 - October 2008	$	180	1.000 (c)	$	1

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

(b)	Fair value was based on market rates.

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

The aggregate cash flow effect on foreign currency contracts of a hypothetical 10 percent change to exchange rates at June 30, 2008, would be approximately $14 million.

Safe Harbor

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

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective. During the quarter ended June 30, 2008, there were no changes in our internal controls over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal controls over financial reporting.

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

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions, except as noted)	2008			2007			2008			2007

Segment Income (Loss)
Exploration and Production
United States	$	359		$	173		$	603		$	323
International		469			227			909			462
E&P segment		828			400			1,512			785
Oil Sands Mining		(157	)		-			(130	)		-
Refining, Marketing and Transportation		158			1,246			83			1,591
Integrated Gas		102			12			201			31
Segment income		931			1,658			1,666			2,407
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(73	)		(111	)		(41	)		(154	)
Loss on U.K. natural gas contracts		(84	)		(5	)		(120	)		6
Discontinued operations		-			8			-			8
Net income	$	774		$	1,550		$	1,505		$	2,267

Capital Expenditures
Exploration and Production	$	874		$	580		$	1,649		$	1,041
Oil Sands Mining		262			-			510			-
Refining, Marketing and Transportation		702			334			1,213			551
Integrated Gas (a)		-			34			1			91
Corporate		7			14			9			16
Total	$	1,845		$	962		$	3,382		$	1,699

Exploration Expenses
United States	$	55		$	47		$	105		$	84
International		75			68			154			92
Total	$	130		$	115		$	259		$	176

E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbpd) (b)
United States		63			65			63			67

Europe		38			34			31			34
Africa		81			100			92			98
Total International		119			134			123			132
Worldwide		182			199			186			199
Net Natural Gas Sales (mmcfd) (b)(c)
United States		431			460			456			485

Europe		175			178			214			213
Africa		398			196			396			143
Total International		573			374			610			356
Worldwide		1,004			834			1,066			841

Total Worldwide Sales (mboepd)		350			338			364			339

(a)

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

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

(c)	Includes natural gas acquired for injection and subsequent resale of 25 mmcfd and 54 mmcfd in the second quarters of 2008 and 2007, and 31 mmcfd and 47 mmcfd for the first six months of 2008 and 2007.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions, except as noted)	2008		2007		2008		2007

E&P Operating Statistics (continued)
Average Realizations (d)
Liquid Hydrocarbons (per bbl)
United States	$	109.85	$	55.19	$	96.96	$	52.19

Europe		121.96		61.34		111.54		59.12
Africa		108.70		60.91		98.33		55.79
Total International		112.99		61.02		101.66		56.63
Worldwide	$	111.90	$	59.11	$	100.07	$	55.13

Natural Gas (per mcf)
United States	$	8.66	$	6.16	$	7.70	$	6.03

Europe		7.86		4.47		7.82		5.71
Africa(e)		0.25		0.25		0.25		0.26
Total International		2.58		2.27		2.90		3.51
Worldwide	$	5.19	$	4.41	$	4.95	$	4.96

OSM Operating Statistics
Net Bitumen Production (mbpd) (f)		24		-		24		-
Net Synthetic Crude Sales (mbpd) (f)		31		-		31		-
Synthetic Crude Average Realization (per bbl)	$	116.40	$	-	$	102.70	$	-

RM&T Operating Statistics
Refinery Runs (mbpd)
Crude oil refined		1,023		1,072		934		1,021
Other charge and blend stocks		180		208		207		217
Total		1,203		1,280		1,141		1,238
Refined Product Yields (mbpd)
Gasoline		607		680		604		651
Distillates		367		377		326		350
Propane		23		26		22		23
Feedstocks and special products		116		96		108		121
Heavy fuel oil		23		27		27		25
Asphalt		86		89		73		83
Total		1,222		1,295		1,160		1,253

Refined Products Sales Volumes (mbpd) (g)		1,369		1,426		1,324		1,385
Refining and Wholesale Marketing Gross
Margin (per gallon) (h)	$	0.0835	$	0.3925	$	0.0420	$	0.2634
Speedway SuperAmerica
Retail outlets		1,625		1,637		-		-
Gasoline and distillate sales (millions of gallons)		788		828		1,580		1,628
Gasoline and distillate gross margin (per gallon)	$	0.0862	$	0.1029	$	0.1005	$	0.1121
Merchandise sales	$	722	$	714	$	1,369	$	1,358
Merchandise gross margin	$	181	$	182	$	344	$	342

IG Operating Statistics
Net Sales (mtpd) (i)
LNG		6,402		1,997		6,657		1,582
Methanol		1,188		1,107		1,159		1,215

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

(e)	Primarily represents a fixed price under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, equity method investees. We include our share of Alba Plant LLC’s income in our E&P segment and we include our share of AMPCO’s and EGHoldings’ income in our Integrated Gas segment.

(f)	Amounts are before royalties.

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

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

(i)	Includes both consolidated sales volumes and our share of the sales volumes of equity method investees. LNG sales from Alaska are conducted through a consolidated subsidiary. LNG and methanol sales from Equatorial Guinea are conducted through equity method investees.

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

MTBE Litigation

We are a defendant, along with many other companies with refinery operations, in 58 cases in 12 states alleging methyl tertiary butyl ether (“MTBE”) contamination in groundwater. These cases, after their removal from state to federal court, have been consolidated in a multi-district litigation (“MDL”) in the Southern District of New York for pretrial proceedings. On July 22, 2008, the judge issued an opinion holding that the MTBE settlement agreement represented a "good faith" settlement. The settling defendants, which include Marathon, were required to obtain a good faith determination for the California and Illinois cases in order to insure protection from contribution actions. The federal judge in the MDL concluded that both the approximate percentage of estimated liability being paid and the dollar amounts being allocated were reasonable. Similar approvals must also be obtained from state court judges in Illinois and California. The timing of payment under the settlement agreement could be impacted by an appeal of the judges' rulings on fairness. Such settlement is not expected to significantly impact Marathon’s consolidated results of operations, financial position or cash flows.

Environmental Proceedings

The U.S. Occupational Safety and Health Administration (“OSHA”) announced a National Emphasis Program where it plans to inspect domestic oil refinery locations. The inspections began in 2007 and have focused on compliance with the OSHA Process Safety Management requirements. U.S. OSHA and Kentucky OSHA have been conducting extensive inspections of the Texas City, Texas, and Catlettsburg, Kentucky, refineries in the summer of 2008 and an inspection of the Detroit refinery is anticipated. U.S. OSHA or state OSHA’s may conduct inspections of other Marathon refineries during 2008. Enforcement actions may result from these inspections.

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 2007 Annual Report on Form 10-K. There have been no material changes from the risk factors previously disclosed in that Form 10-K.

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

	(a)	(b)	(c)	(d)
			Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (d)	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (d)


	Total Number of	Average Price Paid
Period	Shares Purchased (a)(b)	per Share

04/01/08 – 04/30/08	1,222,360	$47.29	1,197,000	$2,274,870,936
05/01/08 – 05/31/08	889,817	$52.35	836,733	$2,233,239,806
06/01/08 – 06/30/08	1,037,755 (c)	$51.38	1,006,200	$2,182,029,038
Total	3,149,932	$50.07	3,039,933

(a)	78,944 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.

(b)

Under the terms of the transaction whereby Marathon acquired the minority interest in Marathon Petroleum Company and other businesses from Ashland, Marathon paid Ashland shareholders cash in lieu of issuing fractional shares of Marathon’s common stock to which such holders would otherwise be entitled. Marathon acquired 26 shares due to acquisition share exchanges and Ashland share transfers pending at the closing of the transaction.

(c)

31,029 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon.

(d)

Marathon announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion. As of June 30, 2008, 64 million split-adjusted common shares had been acquired at a cost of $2,815 million, 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 30, 2008. 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 2008 Proxy Statement.

1.	Votes regarding the persons elected to serve as directors for a term expiring in 2009 were as follows:

NOMINEE	VOTES FOR	VOTES AGAINST	VOTES ABSTAINED
Charles F. Bolden, Jr.	599,103,752	6,742,733	5,885,080
Gregory H. Boyce	599,608,993	6,226,851	5,895,720
Shirley Ann Jackson	568,817,354	36,872,443	6,041,768
Philip Lader	589,554,936	16,134,226	6,050,713
Charles R. Lee	595,772,958	9,918,480	6,040,127
Dennis H. Reilley	602,185,300	3,640,514	5,905,751
Seth E. Schofield	597,714,389	8,025,658	5,991,517
John W. Snow	602,665,954	3,184,530	5,881,082
Thomas J. Usher	597,469,714	8,422,218	5,839,632

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 our independent registered public accounting firm for 2008. The voting results were as follows:

VOTES FOR	VOTES AGAINST	VOTES ABSTAINED
600,158,639	5,937,958	5,627,869

3.	The stockholder proposal requesting that the Board of Directors amend our By-laws and any other appropriate governing documents to give holders of 10% to 25% of Marathon’s outstanding common stock the power to call a special stockholder meeting was approved. The voting results were as follows:

VOTES FOR	VOTES AGAINST	VOTES ABSTAINED
368,242,912	160,594,408	6,124,251

The stockholder proposal requesting that the Board of Directors adopt a policy that provides stockholders the opportunity at each stockholder meeting to vote on an advisory management resolution to ratify the compensation of the named executive officers was defeated. The voting results were as follows:

VOTES FOR	VOTES AGAINST	VOTES ABSTAINED
222,997,698	291,858,947	20,104,927

Item 6. Exhibits

12.1	Computation of Ratio of Earnings to Fixed Charges
31.1	Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
31.2	Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
32.1	Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2	Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

SIGNATURES

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

August 8, 2008	MARATHON OIL CORPORATION

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