MARATHON OIL CORP - Quarter Report: 2011 August (Form 10-Q)

form10q2011aug8.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, 2011

[ ]	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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of

Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 714,008,956 shares of Marathon Oil Corporation common stock outstanding as of July 31, 2011.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended June 30, 2011

	INDEX
		Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)		2
	Consolidated Statements of Comprehensive Income (Unaudited)		3
	Consolidated Balance Sheets (Unaudited)		4
	Consolidated Statements of Cash Flows (Unaudited)		5
	Consolidated Statements of Stockholders’ Equity (Unaudited)		6
	Notes to Consolidated Financial Statements (Unaudited)		7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		33
Item 4.	Controls and Procedures		33
	Supplemental Statistics (Unaudited)		34
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		36
Item 1A.	Risk Factors		36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		37
Item 6.	Exhibits		38
	Signatures		40

Unless the context otherwise indicates, references in this Form 10-Q to “Marathon Oil,” “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 Oil exerts significant influence by virtue of its ownership interest). Any reference to “Marathon” indicates Marathon Oil Corporation as it existed prior to the June 30, 2011 spin-off of the downstream business.

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Satements of Income (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions, except per share data)	2011			2010			2011			2010
Revenues and other income:

Sales and other operating revenues	$	3,680		$	2,793		$	7,336		$	5,448
Sales to related parties		14			14			29			26
Income from equity method investments		120			83			237			168
Net gain on disposal of assets		45			10			50			822
Other income		6			3			22			28

Total revenues and other income		3,865			2,903			7,674			6,492
Costs and expenses:
Cost of revenues (excludes items below)		1,667			1,230			3,071			2,277
Purchases from related parties		71			35			127			75
Depreciation, depletion and amortization		564			416			1,199			846
Impairments		307			5			307			439
Selling, general and administrative expenses		130			118			267			220
Other taxes		53			52			111			101
Exploration expenses		145			125			375			223

Total costs and expenses		2,937			1,981			5,457			4,181

Income from operations		928			922			2,217			2,311

Net interest and other		(13	)		(15	)		(32	)		(37	)
Loss on early extinguishment of debt		-			(92	)		(279	)		(92	)


Income from continuing operations before income taxes		915			815			1,906			2,182

Provision for income taxes		617			441			1,153			1,191

Income from continuing operations		298			374			753			991

Discontinued operations		698			335			1,239			175

Net income	$	996		$	709		$	1,992		$	1,166

Per Share Data

Basic:

Income from continuing operations	$	0.42		$	0.53		$	1.06		$	1.39
Discontinued operations	$	0.98		$	0.47		$	1.74		$	0.25
Net income per share	$	1.40		$	1.00		$	2.80		$	1.64

Diluted:

Income from continuing operations	$	0.42		$	0.53		$	1.05		$	1.39
Discontinued operations	$	0.97		$	0.47		$	1.73		$	0.25
Net income per share	$	1.39		$	1.00		$	2.78		$	1.64

Dividends paid	$	0.25		$	0.25		$	0.50		$	0.49

Weighted average shares:
Basic		713			710			712			709
Diluted		717			712			716			711

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2011			2010			2011			2010
Net income	$	996		$	709		$	1,992		$	1,166
Other comprehensive income

Post-retirement and post-employment plans
Change in actuarial gain		64			128			97			158
Spin-off downstream business		968			-			968			-
Income tax provision on post-retirement and
post-employment plans		(403	)		(59	)		(415	)		(83	)
Post-retirement and post-employment plans, net of tax		629			69			650			75

Derivative hedges
Net unrecognized gain		(6	)		1			3			3
Income tax benefit (provision) on derivatives		3			-			(1	)		1
Derivative hedges, net of tax		(3	)		1			2			4

Foreign currency translation and other
Unrealized gain (loss)		(1	)		-			(1	)		-
Income tax provision on foreign currency translation and other		-			-			-			-
Foreign currency translation and other, net of tax		(1	)		-			(1	)		-

Other comprehensive income		625			70			651			79

Comprehensive income	$	1,621		$	779		$	2,643		$	1,245

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)	2011			2010
Assets
Current assets:
Cash and cash equivalents	$	4,711		$	3,951
Receivables, less allowance for doubtful accounts of $2 and $7		1,790			5,972
Receivables from related parties		53			58
Inventories		343			3,453
Other current assets		417			395

Total current assets		7,314			13,829

Equity method investments		1,475			1,802
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $16,243 and $19,805		20,140			32,222
Goodwill		537			1,380
Other noncurrent assets		1,024			781

Total assets	$	30,490		$	50,014
Liabilities
Current liabilities:
Accounts payable	$	1,631		$	8,000
Payables to related parties		21			49
Payroll and benefits payable		139			418
Accrued taxes		1,839			1,447
Deferred income taxes		-			324
Other current liabilities		193			580
Long-term debt due within one year		338			295

Total current liabilities		4,161			11,113

Long-term debt		4,684			7,601
Deferred income taxes		2,658			3,569
Defined benefit postretirement plan obligations		673			2,171
Asset retirement obligations		1,336			1,354
Deferred credits and other liabilities		271			435

Total liabilities		13,783			26,243

Commitments and contingencies

Stockholders’ Equity
Preferred stock – no shares issued and outstanding (no par value, 26 million shares
authorized)		-			-
Common stock:
Issued – 770 million shares (par value $1 per share,
1.1 billion shares authorized)		770			770
Securities exchangeable into common stock – no shares issued and outstanding
(no par value, 29 million shares authorized)		-			-
Held in treasury, at cost – 56 million and 60 million shares		(2,493	)		(2,665	)
Additional paid-in capital		6,723			6,756
Retained earnings		12,053			19,907
Accumulated other comprehensive loss		(346	)		(997	)

Total stockholders' equity		16,707			23,771

Total liabilities and stockholders' equity	$	30,490		$	50,014

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)	2011			2010
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	1,992		$	1,166
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on early extinguishment of debt		279			92
Discontinued operations		(1,239	)		(175	)
Deferred income taxes		(427	)		(279	)
Depreciation, depletion and amortization		1,199			846
Impairments		307			439
Pension and other postretirement benefits, net		22			29
Exploratory dry well costs and unproved property impairments		264			111
Net gain on disposal of assets		(50	)		(822	)
Equity method investments, net		(21	)		-
Changes in:
Current receivables		78			(13	)
Inventories		46			(41	)
Current accounts payable and accrued liabilities		748			531
All other operating, net		122			71
Net cash provided by continuing operations		3,320			1,955
Net cash provided by discontinued operations		1,090			172
Net cash provided by operating activities		4,410			2,127
Investing activities:
Additions to property, plant and equipment		(1,702	)		(1,860	)
Disposal of assets		371			1,354
Investments - repayments of loans and return of capital		-			35
Investing activities of discontinued operations		(493	)		(635	)
Property deposit		(100	)		-
All other investing, net		51			(36	)
Net cash used in investing activities		(1,873	)		(1,142	)
Financing activities:
Debt repayments		(2,843	)		(620	)
Dividends paid		(356	)		(350	)
Financing activities of discontinued operations		2,916			(5	)
Distribution in Spin-off		(1,622	)		-
All other financing, net		126			5
Net cash used in financing activities		(1,779	)		(970	)
Effect of exchange rate changes on cash		2			(10	)
Net increase in cash and cash equivalents		760			5
Cash and cash equivalents at beginning of period		3,951			2,057
Cash and cash equivalents at end of period	$	4,711		$	2,062

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

MARATHON OIL CORPORATION

Consolidated Statement of Stockholders’ Equity (Unaudited)

(In millions)	Preferred Stock		Common Stock		Securities Exchangeable for Common Stock		Treasury Stock			Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholders' Equity
Balance as of December 31, 2010	$	-	$	770	$	-	$	(2,665	)	$	6,756		$	19,907		$	(997	)	$	23,771
Shares issued - stock based compensation		-		-		-		175			(58	)		-			-			117
Shares repurchased		-		-		-		(3	)		-			-			-			(3	)
Stock-based compensation		-		-		-		-			20			-			-			20
Net income		-		-		-		-			-			1,992			-			1,992
Other comprehensive income		-		-		-		-			-			-			64			64
Dividends paid		-		-		-		-			-			(356	)		-			(356	)
Spin-off of downstream business		-		-		-		-			5			(9,490	)		587			(8,898	)
Balance as of June 30, 2011	$	-	$	770	$	-	$	(2,493	)	$	6,723		$	12,053		$	(346	)	$	16,707

(Shares in millions)	Preferred Stock		Common Stock		Securities Exchangeable for Common Stock		Treasury Stock
Balance as of December 31, 2010		-		770		-		(60	)
Shares issued - stock based compensation		-		-		-		4
Balance as of June 30, 2011		-		770		-		(56	)

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; however, in the opinion of management, these statements 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.

As a result of the spin-off (see Note 2), the results of operations for our downstream (Refining, Marketing and Transportation) business have been classified as discontinued operations for all periods presented. The disclosures in this report are presented on the basis of continuing operations, unless otherwise stated. Any reference to “Marathon” indicates Marathon Oil Corporation as it existed prior to the June 30, 2011 spin-off.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation 2010 Annual Report on Form 10-K. The results of operations for the quarter and six months ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year.

2. Spin-off Downstream Business

On June 30, 2011, the spin-off of the downstream (Refining, Marketing and Transportation) business was completed, creating two independent energy companies: Marathon Oil Corporation (“Marathon Oil”) and Marathon Petroleum Corporation (“MPC”). On June 30, 2011, stockholders of record as of 5:00 p.m. Eastern Daylight Savings time on June 27, 2011 (the “Record Date”) received one common share of MPC stock for every two common shares of Marathon stock held as of the Record Date.

In order to affect the spin-off and govern our relationship with MPC after the spin-off, we entered into a Separation and Distribution Agreement, a Tax Sharing Agreement, an Employee Matters Agreement and a Transition Services Agreement. The Separation and Distribution Agreement governed the separation of the downstream business, the distribution of MPC’s shares of common stock to our stockholders, transfer of assets and intellectual property, and other matters related to our relationship with MPC. The Separation and Distribution Agreement provides for cross-indemnities between Marathon Oil and MPC. In general, we have agreed to indemnify MPC for any liabilities relating to our historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and MPC has agreed to indemnify us for any liabilities relating to the historical downstream operations.

The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of Marathon Oil and MPC with respect to taxes and tax benefits, the filing of tax returns, the control of audits and other tax matters. In addition, the Tax Sharing Agreement reflects each company’s rights and obligations related to taxes that are attributable to periods prior to and including the Separation date and taxes resulting from transactions effected in connection with the Separation. In general, under the Tax Sharing Agreement, Marathon Oil is responsible for all U.S. federal, state, local and foreign income taxes attributable to Marathon Oil or any of its subsidiaries for any tax period that begins after the date of the spin-off, and MPC is responsible for all taxes attributable to it or its subsidiaries, whether accruing before, on or after the spin-off. The Tax Sharing Agreement contains covenants intended to protect the tax-free status of the spin-off. These covenants may restrict the ability of Marathon Oil and MPC to pursue strategic or other transactions that otherwise could maximize the values of their respective businesses and may discourage or delay a change of control of either company.

The Employee Matters Agreement contains provisions concerning benefit protection for employees who become MPC employees prior to December 31, 2011, treatment of holders of Marathon stock options, stock appreciation rights, restricted stock and restricted stock units, and cooperation between Marathon Oil and MPC in the sharing of employee information and maintenance of confidentiality. Unvested equity-based compensation awards were converted to awards of the entity where the employee holding them is working post-separation. For vested equity-based compensation awards, employees received both Marathon Oil and MPC awards.

Under the Transition Services Agreement, Marathon Oil and MPC are providing and/or making available various administrative services and assets to each other, for the up to a one-year period beginning on the distribution date of the spin-off. The services include: administrative services; accounting services; audit services; health, environmental and safety services; human resource services; information technology services; legal services; natural gas administration services; tax services; and treasury services. In consideration for such services, the companies are paying fees to the other for the services provided, and these fees are generally in amounts intended to allow the party providing services to recover all of its direct and indirect costs incurred in providing these services.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table presents the carrying value of assets and liabilities of MPC, immediately preceding the spin-off, which is excluded from the Marathon Oil consolidated balance sheet as a result of the spin-off on June 30, 2011.

(In millions)
Current assets:
Cash and cash equivalents	$	1,622
Receivables		5,041
Inventories		3,679
Other current assets		170
Total current assets of discontinued operations		10,512
Equity method investments		323
Property, plant and equipment		11,935
Goodwill		847
Other noncurrent assets		351
Total assets of discontinued operations	$	23,968

Current liabilities:
Accounts payable	$	7,329
Payroll and benefits payable		222
Accrued and deferred taxes		443
Other current liabilities		461
Long-term debt due within one year		12
Total current liabilities of discontinued operations		8,467
Long-term debt		3,262
Deferred income taxes		1,576
Defined benefit postretirement plan obligations		1,489
Deferred credits and other liabilities		276
Total liabilities of discontinued operations	$	15,070

The following table presents selected financial information regarding the results of operations of our downstream business which are reported as discontinued operations. Transaction costs incurred to affect the spin-off of $57 million and $74 million for the second quarter and first six months of 2011 are included in discontinued operations.

		Three Months Ended June 30,					Six Months Ended June 30,
(In millions)	2011			2010			2011			2010
Revenues applicable to discontinued operations		$	20,760		$	15,795		$	38,602		$	29,157
Pretax income from discontinued operations			1,244			646			2,012			248

3. Accounting Standards

Not Yet Adopted

In May 2011, the FASB issued an update amending the accounting standards for fair value measurement and disclosure, resulting in common principles and requirements under U.S. generally accepted accounting principles (“U.S. GAAP”) and International Financial Reporting Standards (“IFRS”). The amendments change the wording used to describe certain of the U.S. GAAP requirements either to clarify the intent of existing requirements, to change measurement or expand disclosure principles or to conform to the wording used in IFRS. The amendments are to be applied prospectively and will be effective for our interim and annual periods beginning with the first quarter of 2012. Early application is not permitted. We do not expect adoption of these amendments to have a significant impact on our consolidated results of operations, financial position or cash flows.

The Financial Accounting Standards Board (“FASB”) amended the reporting standards for comprehensive income in June 2011 to eliminate the option to present the components of other comprehensive income as part of the statement of changes in stockholders' equity. All non-owner changes in stockholders’ equity are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive income. The amendments did not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. We are still evaluating this reporting standard, but we do not expect adoption of this amendment to have an impact on our consolidated results of operations, financial position or cash flows.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

4. Variable Interest Entities

The Athabasca Oil Sands Project (“AOSP”), in which we hold a 20 percent undivided interest, contracted with a wholly-owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with a $3 million current liability recorded at June 30, 2011. Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline. Currently, no third-party shippers use the pipeline. Should shipments be suspended, by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all remaining periods. The contract expires in 2029; however, the shippers can extend its term perpetually. This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a Variable Interest Entity (“VIE”). We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore, the Corridor Pipeline is not consolidated by Marathon Oil. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $765 million as of June 30, 2011. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.

5. Income per Common Share

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

	Three Months Ended June 30,
	2011				2010
(In millions, except per share data)	Basic		Diluted		Basic		Diluted

Income from continuing operations	$	298	$	298	$	374	$	374
Discontinued operations		698		698		335		335
Net income	$	996	$	996	$	709	$	709

Weighted average common shares outstanding		713		713		710		710
Effect of dilutive securities		-		4		-		2
Weighted average common shares, including
dilutive effect		713		717		710		712

Per share:
Income from continuing operations	$	0.42	$	0.42	$	0.53	$	0.53
Discontinued operations	$	0.98	$	0.97	$	0.47	$	0.47
Net income	$	1.40	$	1.39	$	1.00	$	1.00

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Six Months Ended June 30,
	2011				2010
(In millions, except per share data)	Basic		Diluted		Basic		Diluted

Income from continuing operations	$	753	$	753	$	991	$	991
Discontinued operations		1,239		1,239		175		175
Net income	$	1,992	$	1,992	$	1,166	$	1,166

Weighted average common shares outstanding		712		712		709		709
Effect of dilutive securities		-		4		-		2
Weighted average common shares, including
dilutive effect		712		716		709		711

Per share:
Income from continuing operations	$	1.06	$	1.05	$	1.39	$	1.39
Discontinued operations	$	1.74	$	1.73	$	0.25	$	0.25
Net income	$	2.80	$	2.78	$	1.64	$	1.64

The per share calculations above exclude 5 million and 6 million stock options and stock appreciation rights for the second quarter and the first six months of 2011, as they were antidilutive. Excluded in the second quarter and the first six months of 2010 were 12 million stock options and stock appreciation rights.

6. Dispositions

In April 2011, we assigned a 30 percent undivided working interest in our Exploration and Production (“E&P”) segment’s approximately 180,000 acres in the Niobrara shale play located within the DJ Basin of southeast Wyoming and northern Colorado for total consideration of $270 million, recording a pretax gain of $39 million. We remain operator of this jointly owned leasehold.

In March 2011, we closed the sale of our E&P segment's outside-operated interests in the Gudrun field development and the Brynhild and Eirin exploration areas offshore Norway for net proceeds of $85 million, excluding working capital adjustments. A $64 million pretax loss on this disposition was recorded in the fourth quarter 2010.

During the first quarter 2010, we closed the sale of a 20 percent outside-operated interest in our E&P segment’s Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola. We received net proceeds of $1.3 billion and recorded a pretax gain on the sale in the amount of $811 million. We retained a 10 percent outside-operated interest in Block 32.

7. Segment Information

We have three reportable operating segments. Each of these segments is organized and managed based upon the nature of the products and services they offer.

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 vacuum gas oil; and

Integrated Gas (“IG”) – markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis.

Segment income represents income from continuing operations, net of income taxes, attributable to the operating segments. Our corporate general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate activities, net of associated income tax effects. Foreign currency remeasurement and transaction gains or losses are not allocated to operating segments.

Differences between segment totals for income taxes and depreciation, depletion and amortization and our consolidated totals represent amounts related to corporate administrative activities and other unallocated items which are included in “Items not allocated to segments, net of income taxes” in the reconciliation below. Capital expenditures include accruals.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

As discussed in Notes 1 and 2, our downstream business was spun-off on June 30, 2011 and has been reported as discontinued operations in all periods presented. Crude oil sales to MPC previously reported as Intersegment revenues are now reported as Customer revenues because such sales are expected to continue subsequent to the spin-off. Such sales were $787 million and $349 million in the second quarter of 2011 and 2010 and $1,395 million and $647 million in the first six months of 2011 and 2010.

	Three Months Ended June 30, 2011
(In millions)	E&P			OSM		IG		Total

Revenues:
Customer	$	3,220		$	447	$	13	$	3,680
Intersegment		15			-		-		15
Related parties		14			-		-		14
Segment revenues		3,249			447		13		3,709
Elimination of intersegment revenues		(15	)		-		-		(15	)
Total revenues	$	3,234		$	447	$	13	$	3,694
Segment income	$	601		$	69	$	43	$	713
Income from equity method investments		66			-		54		120
Depreciation, depletion and amortization		501			49		1		551
Income tax provision		598			23		17		638
Capital expenditures		749			80		-		829

	Three Months Ended June 30, 2010
(In millions)	E&P			OSM			IG		Total

Revenues:
Customer	$	2,570		$	190		$	33	$	2,793
Intersegment		16			-			-		16
Related parties		14			-			-		14
Segment revenues		2,600			190			33		2,823
Elimination of intersegment revenues		(16	)		-			-		(16	)
Total revenues	$	2,584		$	190		$	33	$	2,807
Segment income (loss)	$	432		$	(60	)	$	24	$	396
Income from equity method investments		40			-			43		83
Depreciation, depletion and amortization		391			16			1		408
Income tax provision (benefit)		625			(10	)		12		627
Capital expenditures		585			243			-		828

	Six Months Ended June 30, 2011
(In millions)	E&P			OSM		IG		Total

Revenues:
Customer	$	6,506		$	753	$	77	$	7,336
Intersegment		41			-		-		41
Related parties		29			-		-		29
Segment revenues		6,576			753		77		7,406
Elimination of intersegment revenues		(41	)		-		-		(41	)
Total revenues	$	6,535		$	753	$	77	$	7,365
Segment income	$	1,269		$	101	$	103	$	1,473
Income from equity method investments		124			-		113		237
Depreciation, depletion and amortization		1,087			86		3		1,176
Income tax provision		1,211			33		43		1,287
Capital expenditures		1,417			200		1		1,618

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Six Months Ended June 30, 2010
(In millions)	E&P			OSM			IG		Total

Revenues:
Customer	$	5,018		$	370		$	60	$	5,448
Intersegment		29			-			-		29
Related parties		26			-			-		26
Segment revenues		5,073			370			60		5,503
Elimination of intersegment revenues		(29	)		-			-		(29	)
Total revenues	$	5,044		$	370		$	60	$	5,474
Segment income (loss)	$	934		$	(77	)	$	68	$	925
Income from equity method investments		77			-			91		168
Depreciation, depletion and amortization		788			39			2		829
Income tax provision (benefit)		1,162			(17	)		35		1,180
Capital expenditures		1,188			508			1		1,697

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)	2011			2010			2011			2010
Segment income	$	713		$	396		$	1,473		$	925
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(21	)		7			(136	)		(80	)
Foreign currency remeasurement of income taxes		(3	)		37			(17	)		70
Impairments(a)		(195	)		(9	)		(195	)		(271	)
Loss on early extinguishment of debt(b)		-			(57	)		(176	)		(57	)
Tax effect of subsidiary restructuring(c)		(122	)		-			(122	)		-
Deferred income tax items(c)		(50	)		-			(50	)		(45	)
Water abatement - Oil Sands(d)		(48	)		-			(48	)		-
Gain on dispositions (e)		24			-			24			449
Income from continuing operations		298			374			753			991
Discontinued operations		698			335			1,239			175
Net income	$	996		$	709		$	1,992		$	1,166

(a)	Impairments are discussed in Note 12.

(b)	Additional information on debt retired early can be found in Note 14.

(c)	Changes in deferred taxes and the non cash tax restructuring are discussed in Note 9.

(d)	Oil sands water abatement costs are discussed in Note 17.

(e)	Additional information on these gains can be found in Note 6.

The following reconciles total revenues to sales and other operating revenues as reported in the consolidated statements of income:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2011			2010		2011			2010
Total revenues		$	3,694	$	2,807		$	7,365		$	5,474
Less: Sales to related parties			14		14			29			26
Sales and other operating revenues		$	3,680	$	2,793		$	7,336		$	5,448

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

8. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost related to continuing operations:

	Three Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Service cost	$	10		$	11		$	1		$	1
Interest cost		16			18			4			4
Expected return on plan assets		(16	)		(16	)		-			-
Amortization:
– prior service cost (credit)		2			1			(1	)		(1	)
– actuarial loss		12			14			-			-
Net periodic benefit cost	$	24		$	28		$	4		$	4

	Six Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Service cost	$	23		$	23		$	2		$	2
Interest cost		33			35			8			8
Expected return on plan assets		(33	)		(32	)		-			-
Amortization:
– prior service cost (credit)		3			3			(3	)		(3	)
– actuarial loss		25			25			-			-
Net periodic benefit cost	$	51		$	54		$	7		$	7

During the first six months of 2011, we made contributions related to continuing operations of $26 million to our funded pension plans. We expect to make additional contributions up to an estimated $28 million to our funded pension plans over the remainder of 2011. Current benefit payments related to unfunded pension and other postretirement benefit plans of our continuing operations were $2 million and $10 million during the first six months of 2011.

9. Income Taxes

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

	Six Months Ended June 30,
	2011			2010
Statutory U.S. income tax rate		35	%		35	%
Effects of foreign operations, including foreign tax credits		11			17
Change in permanent reinvestment assertion		12			-
Adjustments to valuation allowances		-			1
Tax law change		2			2
Effective income tax rate for continuing operations		60	%		55	%

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income, the relative magnitude of these sources of income, and foreign currency remeasurement effects. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to individual items not allocated to segments is reported in “Corporate and other unallocated items” shown in Note 7.

The effects of foreign operations on our effective tax rate decreased in the first six months of 2011 as compared to the first six months of 2010, primarily due to the suspension of all production operations in Libya in the first quarter of 2011, where the statutory tax rate is in excess of 90 percent. This decrease was partially offset by a deferred tax charge of $122 million related to an internal restructuring of our international subsidiaries in the second quarter of 2011

In the second quarter of 2011, we recorded $716 million of deferred U.S. tax on undistributed earnings of $2,046 million that we previously intended to permanently reinvest in foreign operations. Offsetting this tax expense were associated foreign tax credits of $488 million.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

We reduced our valuation allowance related to foreign tax credits of $228 million due to recognizing deferred U.S. tax on previously undistributed earnings. In addition, we recorded a valuation allowance of $18 million on our deferred tax assets related to state operating loss carryforwards. Due to the spin-off (see Note 2), we have determined it is more likely than not that we will be unable to realize all recorded deferred tax assets.

On May 25, 2011, Michigan enacted legislation that replaced the Michigan Business Tax (“MBT”) with a corporate income tax (“CIT”), effective January 1, 2012. The new CIT legislation eliminates the “book-tax difference deduction” that was provided under the MBT to mitigate the net increase in a taxpayer’s deferred tax liability resulting when Michigan moved from the Single Business Tax, a non-income tax, to the MBT, an income tax, on July 12, 2007. Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date. The total effect of tax law changes on deferred tax balances is recorded as income tax expense related to continuing operations in the period the law is enacted, even if a portion of the deferred tax balances relate to discontinued operations. As a result of the new CIT legislation, we recorded an expense of $32 million in the second quarter of 2011.

The Patient Protection and Affordable Care Act (“PPACA”) and the Health Care and Education Reconciliation Act of 2010 (“HCERA”), (together, the “Acts”) were signed in to law in March 2010. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “MPDIMA”). Under the MPDIMA, the federal subsidy does not reduce our income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Beginning in 2013, under the Acts, our income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date. The total effect of tax law changes on deferred tax balances is recorded as income tax expense related to continuing operations in the period the law is enacted, even if a portion of the deferred tax balances relate to discontinued operations. As a result, we have recorded a charge of $45 million in the first quarter of 2010 for the write-off of deferred tax assets to reflect the change in the tax treatment of the federal subsidy.

The following table summarizes the activity in unrecognized tax benefits:

	Six Months Ended June 30,
(In millions)	2011			2010
Beginning balance	$	103		$	75
Additions based on tax positions related to the current year		2			4
Reductions based on tax positions related to the current year		(2	)		(4	)
Additions for tax positions of prior years		53			15
Reductions for tax positions of prior years		(8	)		(20	)
Settlements		(9	)		(1	)
Ending balance	$	139		$	69

If the unrecognized tax benefits as of June 30, 2011 were recognized, $132 million would affect our effective income tax rate. There were $13 million of uncertain tax positions as of June 30, 2011 for which it is reasonably possible that the amount of unrecognized tax benefits would decrease during the next twelve months.

10. 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. A significant portion of our inventories were related to our downstream business (see Note 2) at December 31, 2010.

	June 30,		December 31,
(In millions)	2011		2010
Liquid hydrocarbons, natural gas and bitumen	$	124	$	1,275
Refined products and merchandise		-		1,774
Supplies and sundry items		219		404
Total inventories, at cost	$	343	$	3,453

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

11. Property, Plant and Equipment

	June 30,			December 31,
(In millions)	2011			2010
E&P
United States	$	14,078		$	13,532
International		12,105			11,736
Total E&P		26,183			25,268
OSM		9,831			9,631
IG		48			47
RM&T(a)		-			16,624
Corporate		321			457
Total property, plant and equipment		36,383			52,027
Less accumulated depreciation, depletion and amortization		(16,243	)		(19,805	)
Net property, plant and equipment	$	20,140		$	32,222

(a)	See Note 2 for a discussion of the spin-off of our downstream (RM&T) business.

In the first quarter 2011, production operations in Libya were suspended and we are not currently making deliveries of hydrocarbons from our interest in the Waha concession in eastern Libya. As of June 30, 2011, our net property, plant and equipment investment in Libya is approximately $762 million and our net proved reserves in Libya were 242 million barrels of oil equivalent (“mmboe”) at December 31, 2010. The impact of continued unrest upon our investment and future operations in Libya is unknown at this time. In addition, payments due to the Libyan government or entities affiliated with the Libyan government have been blocked by the U.S. government under a February 25, 2011 executive order. Such amounts, as of June 30, 2011, primarily related to taxes and royalties due on our January and February 2011 sales totaled approximately $200 million.

Exploratory well costs capitalized greater than one year after completion of drilling were $386 million as of June 30, 2011, an increase of $63 million from December 31, 2010. The resumption of our offshore Norway exploration project in 2011 reduced the total suspended exploratory costs by $26 million in the first quarter of 2011. Drilling on the Innsbruck prospect, located on Mississippi Canyon Block 993 in the Gulf of Mexico was suspended in the second quarter of 2010 due to the U.S. Department of Interior’s drilling moratorium. Costs of $88 million related to that project have now been capitalized for greater than one year. We have submitted plans for continuing drilling at Innsbruck and are awaiting regulatory approval.

12. Fair Value Measurements

Fair Values - Recurring

As of June 30, 2011, balances related to interest rate swaps accounted for at fair value on a recurring basis were assets of $5 million and liabilities of $3 million. The interest rate swaps are in Level 2 of the fair value hierarchy and at June 30, 2011, are measured at fair value with a market approach using market price quotes or a price obtained from third-party services such as Bloomberg LP which have been corroborated with data from active markets for similar assets and liabilities. The majority of our 2010 derivatives related to our downstream business. The following table presents assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2010 by fair value hierarchy level.

	December 31, 2010
(In millions)	Level 1			Level 2		Level 3			Collateral		Total
Derivative instruments, assets
Commodity	$	58		$	-	$	1		$	81	$	140
Interest rate		-			32		-			-		32
Derivative instruments, assets		58			32		1			81		172
Derivative instruments, liabilities
Commodity		(102	)		-		(3	)		-		(105	)
Derivative instruments, liabilities	$	(102	)	$	-	$	(3	)	$	-	$	(105	)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

At December 31, 2010, commodity derivatives in Level 1 are exchange-traded contracts for crude oil, natural gas and refined products measured at fair value with a market approach using the close-of-day settlement price for the market. Commodity derivatives, interest rate derivatives and foreign currency forwards in Level 2 are measured at fair value with a market approach using broker price quotes or prices obtained from third-party services such as Bloomberg L.P. or Platt’s, a Division of McGraw-Hill Corporation (“Platt’s”), which have been corroborated with data from active markets for similar assets and liabilities. Collateral deposits related to both Level 1 and Level 2 commodity derivatives are in broker accounts covered by master netting agreements. Commodity derivatives in Level 3 are measured at fair value with a market approach using prices obtained from third-party services such as Platt’s and price assessments from other independent brokers.

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.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2011			2010			2011			2010
Beginning balance	$	(1	)	$	8		$	(2	)	$	9
Included in net income		1			20			-			19
Included in other comprehensive income		-			2			-			4
Transfers to Level 2		-			(30	)		-			(30	)
Purchases		-			-			-			2
Settlements		(2	)		(3	)		-			(7	)
Spin-off downstream business		2			-			2			-
Ending balance	$	-		$	(3	)	$	-		$	(3	)

No instruments measured at fair value using Level 3 inputs were held on June 30, 2011. Net income for second quarter and first six months of 2010 included unrealized losses of $2 million and $4 million related to instruments held on June 30, 2010. See Note 13 for the income statement impacts of our derivative instruments.

Fair Values - Nonrecurring

The following tables show the values of assets, by major class, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

		Three Months Ended June 30,
		2011				2010
(In millions)		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	226	$	282	$	2	$	33
Intangible assets	$	-	$	25	$	-	$	-

		Six Months Ended June 30,
		2011				2010
(In millions)		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	226	$	282	$	146	$	439
Intangible assets	$	-	$	25	$	-	$	-

In May 2011, significant water production and reservoir pressure declines occurred at the Droshky development. Plans for a waterflood have been cancelled and the field will be produced to abandonment pressures, expected in the first half of 2012. Consequently, 3.4 mmboe of proved reserves were written off and a $273 million impairment of this long-lived asset to fair value was recorded in the second quarter of 2011. The $226 million fair value of the Droshky development was determined using an income approach based upon internal estimates of future production levels, prices and discount rate, all Level 3 inputs.

Our outlook for U.S. natural gas prices makes it unlikely that sufficient U.S. demand for LNG will materialize by 2021, which is when the rights lapse under arrangements at the Elba Island, Georgia regasification facility. Using an income approach based upon internal estimates of gas prices and future deliveries, which are Level 3 inputs, we determined that the contract had no remaining fair value and recorded a full impairment of this intangible asset held in our Integrated Gas segment.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

In March 2010, we completed a reservoir study which resulted in a portion of our Powder River Basin field being removed from plans for future development in our E&P segment. The field’s fair value was measured at $144 million, an income approach based upon internal estimates of future production levels, prices and discount rate which are Level 3 inputs. This resulted in an impairment of $423 million.

Impairments of several other long-lived assets held for use in our E&P segment, that were evaluated in the six months ended June 30, 2011 and 2010 were a result of reduced drilling expectations, reduction of estimated reserves or declining natural gas prices, are also reported above. The fair values of those assets were measured using an income approach based upon internal estimated of future production levels, prices and discount rate, which are Level 3 inputs.

Fair Values – Reported

The following table summarizes financial instruments, excluding the derivative financial instruments, and their reported fair value by individual balance sheet line item at June 30, 2011 and December 31, 2010:

	June 30, 2011				December 31, 2010
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other current assets	$	225	$	220	$	226	$	220
Other noncurrent assets		243		239		396		231
Total financial assets		468		459		622		451
Financial liabilities
Long-term debt, including current portion(a)		5,504		4,984		8,364		7,527
Deferred credits and other liabilities		46		47		66		67
Total financial liabilities	$	5,550	$	5,031	$	8,430	$	7,594

(a) Excludes capital leases.

Our current assets and liabilities include financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk. Exceptions to this assessment are:

·	receivables from United States Steel Corporation (“United States Steel”), which are reported in other current assets above and discussed below; and

·	the current portion of our long-term debt, which is reported with long-term debt above and discussed below.

The current portion of receivables from United States Steel is reported in other current assets, and the long-term portion is included in other noncurrent assets. The fair value of the receivables from United States Steel is measured using an income approach that discounts the future expected payments over the remaining term of the obligations. Because this receivable is not publicly-traded and not easily transferable, a hypothetical market based upon United States Steel’s borrowing rate curve is assumed and the majority of inputs to the calculation are Level 3. The industrial revenue bonds are to be redeemed on or before December 31, 2011, the tenth anniversary of the USX Separation.

Fair values of our remaining financial assets included in other noncurrent assets and of our financial liabilities included in deferred credits and other liabilities are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.

Over 90 percent of our long-term debt instruments are publicly-traded. A market approach based upon quotes from major financial institutions is used to measure the fair value of such debt. Because these quotes cannot be independently verified to an active market they are considered Level 3 inputs. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

13. Derivatives

For information regarding the fair value measurement of derivative instruments, see Note 12.

As of June 30, 2011, the gross fair values of interest rate swaps that are fair value hedges were assets of $5 million and liabilities of $3 million. The assets and liabilities are located on the consolidated balance sheet in Other noncurrent assets and Deferred credits and other liabilities.

The majority of our 2010 derivatives related to our downstream business. The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of December 31, 2010.

	December 31, 2010
(In millions)	Asset		Liability		Net Asset			Balance Sheet Location
Fair Value Hedges
Interest rate	$	32	$	-	$	32		Other noncurrent assets
Total Designated Hedges		32		-		32

Not Designated as Hedges
Commodity		58		102		(44	)	Other current assets
Total Not Designated as Hedges		58		102		(44	)

Total	$	90	$	102	$	(12	)

	December 31, 2010
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Not Designated as Hedges

Commodity	$	1	$	3	$	2	Other current liabilities

Total Not Designated as Hedges		1		3		2
Total	$	1	$	3	$	2

Derivatives Designated as Cash Flow Hedges

As of June 30, 2011, no derivatives were designated as cash flow hedges.

Gains of $10 million related to cash flow hedges were reclassified from accumulated other comprehensive income into net income during the first quarter of 2011. This amortization was accelerated because the related debt was retired.

Derivatives Designated as Fair Value Hedges

In connection with the debt retired in February and March 2011 discussed in Note 14, we settled interest rate swaps with a notional amount of $1,450 million. We recorded a $29 million gain, which reduced the loss on extinguishment of debt.

As of June 30, 2011, we had multiple interest rate swap agreements with a total notional amount of $500 million at a weighted average, LIBOR-based, floating rate of 3.65 percent.

The following table summarizes the pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income:

		Gain (Loss)
		Three Months Ended								Six Months Ended
		June 30,								June 30,
(In millions)	Income Statement Location	2011				2010				2011				2010
Derivative
Interest rate	Net interest and other financing costs		$	3			$	19			$	(1	)		$	24
Hedged Item
Long-term debt	Net interest and other financing costs		$	(3	)		$	(19	)		$	1			$	(24	)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Derivatives not Designated as Hedges

The effect related to continuing operations of all derivative instruments not designated as hedges in our consolidated statements of income appear on the sales and other operating revenues line in the amounts of $1 million and $81 million in the second quarters of 2011 and 2010. For the first six months of 2011 and 2010 the derivative effects were $1 million and $123 million.

14. Debt

At June 30, 2011, we had no borrowings outstanding, and no borrowings were made during the second quarter and six-months ended June 30, 2011 against our $3 billion revolving credit facility or under our U.S. commercial paper program that is backed by the revolving credit facility.

In February and March 2011, we retired the following debt at a weighted average price equal to 112 percent of face value. A $279 million loss on extinguishment of debt was recognized in the first quarter of 2011. The loss includes related deferred financing and premium costs partially offset by the gain on settled interest rate swaps.

(In millions)
6.000% notes due 2012	$	400
6.125% notes due 2012		450
8.375% secured notes due 2012(a)		448
6.500% debentures due 2014		700
5.900% notes due 2018		40
7.500% debentures due 2019		460
Total debt purchases	$	2,498

(a)	These notes were senior secured notes of Marathon Oil Canada Corporation.

In April 2010, we retired $500 million in aggregate principal of our debt under two tender offers as a weighted average price equal to 117 percent of face value. As a result of the tender offers, we recorded a loss on extinguishment of debt of $92 million, including the transaction premium as well as the expensing of related deferred financing costs on the debt in the second quarter of 2010.

15. Stock-Based Compensation Plans

Pursuant to the Employee Matters Agreement (see Note 2), we made certain adjustments to the exercise price and number of our stock-based compensation awards, under existing antidilutive provisions, with the intention of generally preserving the intrinsic value of the awards immediately prior to the spin-off. Outstanding options to purchase common shares of Marathon stock that were vested prior to the spin-off was adjusted so that the holders of the options will hold options to purchase common shares of both Marathon Oil and MPC stock. Unvested stock options and restricted stock were converted to those of the entity where the employee holding them is working post-separation. Adjustments to our stock-based compensation awards did not result in additional compensation expense.

The following table presenting a summary of stock option award and restricted stock award activity for the six months ended June 30, 2011 reflects the adjustments discussed above.

	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2010		24,912,237		$	24.85		2,084,680		$	23.03
Granted (a)		7,610,911			41.51		564,583			30.53
Options Exercised/Stock Vested		(3,465,679	)		15.02		(335,781	)		27.24
Cancelled		(219,052	)		23.03		(66,424	)		24.09
Spin-off downstream business		(6,996,298	)		31.21		(286,450	)		21.24
Outstanding at June 30, 2011		21,842,119		$	24.43		1,960,608		$	24.70

(a) The weighted average grant date fair value of stock option awards granted was $10.40 per share.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

16. Supplemental Cash Flow Information

	Six Months Ended June 30,
(In millions)	2011		2010
Net cash provided from operating activities:
Interest paid (net of amounts capitalized)	$	83	$	53
Income taxes paid to taxing authorities		1,351		845
Noncash investing and financing activities:
Debt payments made by United States Steel		14		102

The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures.

	Six Months Ended June 30,
(in millions)	2011				2010
Additions to property, plant and equipment		$	1,702			$	1,860
Change in capital accruals			(54	)			(149	)
Capital expenditures, continuing operations		$	1,648			$	1,711

17. Commitments and Contingencies

We are defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Certain of these matters are discussed below.

Litigation - In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. Noble is seeking an unspecified amount of damages. We are vigorously defending this litigation. The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain. We do not believe an estimate of a reasonably possible loss (or range of loss) can be made for this lawsuit at this time.

Guarantees – A limited number of guarantees on behalf of MPC were not cancelled prior to the spin-off date of June 30, 2011. The most significant of these guarantees related to crude purchases made by MPC. Our maximum potential undiscounted payment for all guarantees as of June 30, 2011 is $381 million. Since the fair value of these guarantees was de minimis, no liabilities were recorded as of June 30, 2011. Subsequent to June 30, 2011, all guarantees associated with MPC’s crude purchases were cancelled and there are no future payments.

Other contingencies - During the second quarter, the AOSP operator determined the need and developed preliminary plans to address water flow into a previously mined and contained section of the Muskeg River mine. Our share of the estimated costs in the amount of $64 million has been recorded to cost of revenues in the second quarter of 2011.

Contractual commitments – At June 30, 2011, Marathon’s contract commitments to acquire property, plant and equipment were $1,486 million. The decrease from commitment levels previously reported is primarily due to the spin-off of our downstream business on June 30, 2011. See Note 2 for discussion of the spin-off.

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

We are an international energy company with operations in the U.S., Canada, Africa, the Middle East and Europe. Our operations are organized into three reportable segments:

w	Exploration and Production (“E&P”) which explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.
w	Oil Sands Mining (“OSM”) which mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
w	Integrated Gas (“IG”) which markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis.

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 forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2010 Annual Report on Form 10-K.

Spin-off Downstream Business into Independent Company

On June 30, 2011, the spin-off of Marathon’s downstream (Refining, Marketing and Transportation) business was completed, creating two independent energy companies: Marathon Petroleum Corporation (“MPC”) and Marathon Oil Corporation (“MRO”). Marathon shareholders at the close of business on the record date of June 27, 2011 received one share of MPC common stock for every two shares of Marathon common stock held. Fractional shares of MPC common stock were not distributed and any fractional share of MPC common stock otherwise issuable to a Marathon shareholder was sold in the open market on such shareholder's behalf, and such shareholder received a cash payment with respect to that fractional share. A tax ruling received in June 2011 from the U.S. Internal Revenue Service (“IRS”) affirmed the tax-free nature of the spin-off. Activities related to the downstream business have been treated as discontinued operations in all periods presented in this Form 10-Q (see Note 2 to the consolidated financial statements for additional information).

Overview and Outlook

Exploration and Production

Production

Net liquid hydrocarbon and natural gas sales averaged 337 thousand barrels of oil equivalent per day (“mboepd”) during the second quarter of 2011 compared to 386 mboepd in the same quarter of 2010 and 368 mboepd during the first six months of 2011 compared to 374 mboepd in the same period of 2010. Domestic liquid hydrocarbon volumes sales increased in both periods, primarily due to the Droshky development in the Gulf of Mexico which commenced production in July 2010. International liquid hydrocarbon sales volumes in both periods reflect the impact of Libyan production operations being suspended during the first quarter of 2011. Additionally, second quarter liquid hydrocarbon sales volumes were lower in the second quarter of 2011 compared to the same period of 2010 due to unplanned downtime at Alvheim and the timing of liftings in the U.K.

The Alvheim floating, production, storage and offloading (“FPSO”) vessel offshore Norway experienced a 13-day unplanned shutdown during the second quarter of 2011 to ensure the safe operation of the FPSO fire protection system. After maintenance activities, the system is fully functional and compliant with all regulatory and operational requirements.

Exploration

On June 1, 2011, we announced a definitive agreement with Hilcorp Resources Holdings, LP (“Hilcorp”) to purchase its assets in the core of the Eagle Ford shale formation in Texas in a transaction valued at $3.5 billion, subject to closing adjustments, customary terms and conditions. The transaction is expected to close on November 1, 2011. The assets

being acquired include approximately 141,000 net acres (217,000 gross) primarily in Atascosa, Karnes, Gonzales and DeWitt counties in Texas. Approximately 90 percent of the properties are operated with 65 percent average working interest. Additionally, during the second quarter of 2011, we acquired 40,000 acres in the Eagle Ford shale and continued our exploration program with four wells drilled and being evaluated.

The Earb well offshore Norway has been determined to be dry and costs incurred through June 30, 2011 were charged to exploration expense in the second quarter of 2011. Approximately $11 million in additional well costs are expected in the third quarter of 2011.

In the second quarter of 2011, we completed drilling the Romeo prospect in the Pasangkayu block offshore Indonesia. The well was drilled in a water depth of approximately 6,300 feet and reached a total depth of 11,804 feet, but was dry. Exploration expenses for the first quarter of 2011 included well costs incurred through March 31, 2011 and additional costs of $22 million were charged to exploration expense in the second quarter of 2011. We have notified our joint venture partner and the Indonesian government that we intend to relinquish the Pasangkayu Production Sharing Contract (PSC). Discussions continue and we are awaiting a government response. We also plan to shift from an operating to a non-operating position in both the Bone Bay and Kumawa PSCs over the coming year.

In April 2011, we assigned a 30 percent undivided working interest in approximately 180,000 net acres in the Niobrara Shale play located within the DJ Basin of southeast Wyoming and northern Colorado for a total consideration of $270 million and recorded a $39 million gain. As operator of this jointly owned leasehold, we are acquiring seismic data, commenced drilling our first exploratory horizontal well in July 2011 and expect to drill eight to twelve gross wells by yearend.

Also in April 2011, we farmed-out a 40 percent working interest in 10 concessions in Poland’s Paleozoic Shale play. We are currently acquiring seismic and plan to drill one to two gross wells in the fourth quarter of 2011. In late July 2011, we sold an additional 9 percent working interest. We currently hold a 51 percent working interest in these 10 concessions and serve as operator. Our plans are to begin drilling on two wells in Poland 2011.

During the first quarter of 2011, on the Birchwood oil sands lease located in Alberta, Canada, we drilled 94 stratigraphic test wells. The drilling results are currently being evaluated. Initial results are positive, with the wells encountering expected or greater-than-expected reservoir potential.

In April 2011, we announced a discovery on the Atrush block in the Iraqi Kurdistan Region. The Atrush-1 well was drilled to a total depth of approximately 11,000 feet and encountered pay in the Jurassic zones. Test flow rates were more than 6,000 gross barrels per day. We hold a 20 percent non-operated working interest in the Atrush block. A second discovery in the Iraqi Kurdistan Region was the Swara Tika-1 well on the Sarsang block. It was drilled to a total depth of approximately 12,500 feet and encountered 1,500 feet of gross oil column in the Triassic Kura Chine zones. Test flow rates totaled more than 7,000 barrels of light oil per day with associated gas. Test flow rates were limited by tubing sizes and testing equipment. We hold a 25 percent non-operated working interest in the Sarsang block. The Kurdistan Regional Government holds a 4 percent carried interest in both the Atrush and Sarsang blocks.

In March 2011, we completed our evaluation of the Flying Dutchman exploratory well, located on Green Canyon Block 511 in the Gulf of Mexico. We determined that the options to develop were not viable and reported the remaining well cost in exploration expense in the first quarter of 2011.

Dispositions

In March 2011, we closed the sale of our outside-operated interests in the Gudrun field development and the Brynhild and Eirin exploration areas offshore Norway for net proceeds of $85 million, excluding working capital adjustments. A $64 million pretax loss on this disposition was recorded in the fourth quarter 2010.

Libya

Civil unrest, which began in February 2011 in parts of North Africa, escalated to armed conflict in Libya where we have exploration and production operations. During the first quarter 2011, all production operations in Libya were suspended and we are not currently making deliveries of hydrocarbons from our interest in the Waha concession in eastern Libya. As of June 30, 2011, our net property, plant and equipment investment in Libya is approximately $762 million and our net proved reserves in Libya were 242 mmboe at December 31, 2010. Sales from Libya in 2010 averaged 46,000 barrels of oil equivalent per day and we are in an underlift position of 847 thousand net barrels of liquid hydrocarbons. The impact of continued unrest upon our investment and future operations in Libya is unknown at this time.

In addition, payments due to the Libyan government or entities affiliated with the Libyan government have been blocked by the U.S. government under a February 25, 2011 executive order. As of June 30, 2011, such amounts, primarily related to taxes and royalties due on our January and February 2011 sales, totaled approximately $200 million.

The above discussions include forward-looking statements with respect to the pending acquisition from Hilcorp, the intended shift from operating to a non-operating position in Indonesia, the timing and levels of future production, 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 terrorists acts and the governmental or military response, and other geological, operating and economic considerations. The completion of the agreement to purchase asset from Hilcorp in the Eagle Ford shale formation is subject to customary closing conditions. The anticipated shift from operating to a non-operating position in both the Bone Bay and Kumawa PSCs in Indonesia is subject to obtaining necessary government and third-party approvals. 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 net synthetic crude oil sales were 41 thousand barrels per day (“mbpd”) in the second quarter and 39 mbpd in the first six months of 2011 compared to 20 mbpd and 22 mbpd in the same periods of 2010. The 2011 sales increase primarily reflects the impact of Athabasca Oil Sands Project (“AOSP”) Expansion 1. The Jackpine mine commenced production under a phased start-up in the third quarter of 2010 and began supplying oil sands ore to the base processing facility in the fourth quarter of 2010. The upgrader expansion was completed and commenced operations in the second quarter of 2011. The planned turnaround at the Muskeg River mine and upgrader that began March 22, 2010 and halted production in April before a staged resumption of operations in May also caused 2010 sales to be lower. Incurred in the first six months of 2010, our net share of total turnaround costs was $99 million.

In the second quarter of 2011, as a result of project sanction and life extension for the greater Jackpine area, and in accordance with the terms of the original 1999 AOSP Joint Venture Agreement, we received 20 percent ownership of the portion of Lease 13 known as the Greater Jackpine Area. We added net proved developed reserves of approximately 54 million barrels.

Plans progress on the Quest Carbon Capture and Storage (“Quest CCS”) project, which would capture more than 1 million tons of carbon dioxide annually from the upgrading process and store it in underground reservoirs upon completion in 2015. In the second quarter of 2011, the operator of the AOSP announced agreements with the governments of Alberta and Canada for funding 865 million Canadian dollars, a portion of total Quest CCS costs. The financing would be done over a period of 15 years, including development, construction and 10 years of operations. However, the funding is subject to conditions of achieving certain performance objectives. A final investment decision on Quest CCS is expected to be made in 2012. We hold a 20 percent interest in the AOSP.

The above discussions include forward-looking statements with respect to the Quest CCS project. Some factors that could potentially affect these forward-looking statements include projected costs and 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 the Quest CCS project. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas (“IG”)

Our share of LNG sales worldwide totaled 6,614 metric tonnes per day (“mtpd”) for the second quarter of 2011 compared to 6,556 mtpd in the second quarter of 2010 and 7,215 mtpd in the first six months of 2011 compared to 6,176 mtpd in the first six months of 2010. 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. The Alaska LNG plant will close following the summer of 2011. Our sales from the plant have been at much lower levels since early 2011. LNG and methanol sales from Equatorial Guinea are conducted through equity method investees. Sales volumes of both LNG and methanol are higher in the first six months of 2011 mainly due to the planned turnaround at the Equatorial Guinea gas production facilities in the first quarter of 2010, which significantly reduced natural gas volumes available to the LNG and methanol facilities.

Our outlook for U.S. natural gas prices makes it unlikely that sufficient U.S. demand for LNG will materialize by 2021, which is when the rights lapse under arrangements at the Elba Island, Georgia regasification facility. In the second quarter of 2011, we determined that the contract had no remaining fair value and recorded a $25 million impairment of this intangible asset.

Market Conditions

Exploration and Production

Prevailing prices for the various qualities of crude oil and natural gas that we produce significantly impact our revenues and cash flows. Prices have been volatile in recent years. The following table lists the benchmark crude oil and natural gas price averages in the second quarter and first six months of 2011, when compared to the same periods in 2010.

		Three Months Ended June 30,				Six Months Ended June 30,
Benchmark		2011		2010		2011		2010
West Texas Intermediate ("WTI")
crude oil	(Dollars per barrel)	$	102.34	$	78.05	$	98.50	$	78.46
Dated Brent crude oil	(Dollars per barrel)	$	117.04	$	78.24	$	111.09	$	77.29
Henry Hub natural gas	(Dollars per mmbtu)(a)	$	4.32	$	4.09	$	4.21	$	4.70

(a)	First-of-month price index per million British thermal units.

Crude oil prices were higher in all periods of 2011 than in 2010. Dated Brent has been at over $100 per barrel since early February and WTI at greater than $90 per barrel since late February.

Our domestic crude oil production was about 63 percent sour in the second quarter and first six months of 2011. Sour crude oil contains more sulfur than light sweet WTI. Sour crude oil also tends to be heavier than and sells at a discount to light sweet crude oil because of its higher refining costs and lower refined product values. Our international crude oil production is relatively sweet and a majority is sold in relation to the Dated Brent crude oil benchmark.

Average natural gas prices have been less volatile in the periods presented. A significant portion of our natural gas production in the lower 48 states of the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas. Our other major natural gas-producing regions are Europe and Equatorial Guinea, where our natural gas sales have been and, in the case of Equatorial Guinea primarily, still are subject to term contracts, making realized prices in these areas less volatile. The natural gas being sold from these regions, primarily Equatorial Guinea, is at fixed prices; therefore, our reported average natural gas realized prices may not fully track market price movements.

Oil Sands Mining

OSM segment revenues correlate with prevailing market prices for the various qualities of synthetic crude oil and vacuum gas oil we produce. Roughly two-thirds of our normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil market, primarily Western Canadian Select. Output mix can be impacted by operational problems or planned unit outages at the mine or upgrader.

The operating cost structure of the oil sands mining operations is predominantly fixed, and therefore many of the costs incurred in times of full operation continue during production downtime. Per unit costs are sensitive to production rate. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company (“AECO”) natural gas sales index and crude prices respectively.

The table below shows benchmark prices that impacted both our revenues and variable costs for the second quarter and first six months of 2011 and 2010:

		Three Months Ended June 30,				Six Months Ended June 30,
Benchmark		2011		2010		2011		2010
WTI crude oil	(Dollars per barrel)	$	102.34	$	78.05	$	98.50	$	78.46
Western Canadian Select	(Dollars per barrel)(a)	$	84.92	$	63.95	$	78.08	$	66.81
AECO natural gas sales
index	(Dollars per mmbtu)(b)	$	4.04	$	3.74	$	3.94	$	4.27

(a)	Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.

(b)	Monthly average of Alberta Energy Company (“AECO”) day ahead index.

Integrated Gas

Our integrated gas operations include marketing and transportation of products manufactured from natural gas, such as LNG and methanol, primarily in the U.S., Europe and West Africa.

Our most significant LNG investment is our 60 percent ownership in a production facility in Equatorial Guinea, which sells LNG under a long-term contract at prices tied to Henry Hub natural gas prices. In general, LNG delivered to the U.S. is tied to Henry Hub prices and will track with changes in U.S. natural gas prices, while LNG sold in Europe and Asia is indexed to crude oil prices and will track the movement of those prices.

We own a 45 percent interest in a methanol plant located in Equatorial Guinea through our investment in Atlantic Methanol Production Company LLC (“AMPCO”). Methanol demand has a direct impact on AMPCO’s earnings. Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices. AMPCO’s plant capacity of 1.1 million tones is about 3 percent of total world demand.

Results of Operations

Consolidated Results of Operation

Consolidated net income for 2011 was 40 percent higher in second quarter and 71 percent higher in the first six months than in the same periods of 2010. Due to the spin-off of our downstream business on June 30, 2011, which is reported as discontinued operations, income from continuing operations is more representative of Marathon Oil as an independent energy company. Income from continuing operations was 20 percent lower in second quarter and 24 percent lower in the first six months of 2011 as compared to the same periods of 2010. Higher liquid hydrocarbon realizations and sales volumes in the second quarter of 2011 were offset by higher taxes. Smaller gains on disposal of assets, a loss on early extinguishment of debt, increased depreciation, depletion and amortization and higher taxes contributed to the year to date decrease.

Revenues are summarized by segment in the following table:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2011			2010			2011			2010
E&P	$	3,249		$	2,600		$	6,576		$	5,073
OSM		447			190			753			370
IG		13			33			77			60

Segment revenues		3,709			2,823			7,406			5,503
Elimination of intersegment revenues		(15	)		(16	)		(41	)		(29	)
Total revenues	$	3,694		$	2,807		$	7,365		$	5,474

E&P segment revenues increased $649 million in the second quarter and $1,503 million in the first six months of 2011 from the comparable prior-year periods. Included in our E&P segment are supply optimization activities which include sales of crude oil and natural gas purchased from partners and nearby producers for sale to satisfy transportation commitments and achieving flexibility in product type and delivery point. Revenues from these supply optimization activities are higher in the second quarter and first six months of 2011 than in comparable periods primarily due higher crude oil prices in 2011. The increase in revenues from sale of our production was primarily a result of higher liquid hydrocarbon price realizations. Liquid hydrocarbon realizations averaged $104.93 per barrel in the second quarter and $99.89 in the first six months of 2011 compared to $73.68 and $74.00 in the same periods of 2010. Partially offsetting these revenue increases were decreased volumes, as previously discussed. Net sales volumes during the quarter were 337 mboepd in 2011 and 386 mboepd in 2010. For the first six months of 2011 net sales volumes were 2 percent lower than the comparable prior-year period.

Revenues in both 2010 periods include the impact of derivative instruments intended to mitigate price risk on future sales of liquid hydrocarbons and natural gas. A net pretax gain of $29 million was reported by the E&P segment in the second quarter of 2010, while there was a net pretax gain of $78 million in the first six months of 2010.

The following tables report E&P segment realizations and sales volumes in greater detail for all periods.

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010

E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbpd)
United States		72		57		75		57
Europe		87		110		99		98
Africa		39		79		49		81
Total International		126		189		148		179
Worldwide		198		246		223		236

Natural Gas Sales (mmcfd)
United States		315		334		341		343
Europe(a)		96		104		99		106
Africa		420		402		433		378
Total International		516		506		532		484
Worldwide		831		840		873		827

Total Worldwide Sales (mboepd)		337		386		368		374

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010

E&P Operating Statistics
Average Realizations
Liquid Hydrocarbons (per bbl)
United States	$	99.51	$	68.01	$	92.76	$	70.25

Europe		122.13		79.66		115.27		79.36
Africa		76.86		69.41		79.60		70.20
Total International		108.05		75.37		103.51		75.20
Worldwide		104.93		73.68		99.89		74.00

Natural Gas (per mcf)
United States	$	5.08	$	4.41	$	5.12	$	4.96

Europe		10.05		5.92		10.18		6.05
Africa		0.25		0.25		0.25		0.25
Total International		2.06		1.41		2.09		1.52
Worldwide		3.21		2.61		3.28		2.95

(a)	Includes natural gas acquired for injection and subsequent resale of 13 mmcfd and 16 mmcfd for the second quarters of 2011 and 2010, and 14 mmcfd and 21 mmcfd for the first six months of 2011 and 2010.

OSM segment revenues increased $257 million in the second quarter and $383 million in the first six months of 2011 compared to the same periods of 2010. The impact of derivative instruments intended to mitigate price risk relative to future sales of synthetic crude were gains of $53 million and $43 million the second quarter and first six months of 2010. All derivative positions closed in December 2010. See Note 13 to the consolidated financial statements for additional information about derivative instruments.

Excluding the derivative effects, segment revenues increased in both periods of 2011, as a result of higher synthetic crude realizations and volumes. Net synthetic crude sales for the second quarter of 2011 were 41 mbpd at an average realized price of $100.68 per barrel compared to 20 mbpd at $65.11 in the same period last year. For the six-month period net synthetic crude sales were 39 mbpd at $93.26 in 2011 compared to 22 mbpd at $69.94 in 2010. The 2011 sales volumes improved as a result of the Jackpine mine, which commenced operations in late 2010, and the upgrader expansion was completed and commenced operations in the second quarter of 2011. Sales volumes in 2010 were impacted by a turnaround that commenced on March 22, 2010 that caused production to be completely shut down in April, with a staged resumption in May 2010.

Income from equity method investments increased $37 million in the second quarter of 2011 and $69 million in the first six months of 2011 from the comparable prior-year periods. Higher commodity prices positively impacted the earnings of our equity method investees.

Net gain on disposal of assets in the first six months of 2011 was primarily a gain of $39 million from assigning a 30 percent undivided working interest in the Niobrara Shale play, where we remain operator. The gain in the first six months of 2010 primarily related to the $811 million gain on the sale of a 20 percent outside-operated undivided interest in our E&P segment’s Production Sharing and Joint Operating Agreement in Block 32 offshore Angola.

Cost of revenues increased $437 million and $794 million in the second quarter and first six months of 2011 from the comparable periods of 2010 primarily due to our supply optimization activities. WTI prices increased 31 percent for the second quarter and 26 percent in the first six months of 2011.

OSM segment costs increased in total in the second quarter and first six months of 2011 when compared to the same periods of 2010 primarily due to the start-up of the Jackpine mine and upgrader expansion which included start-up costs and other cost increases associated with the increased volumes, however, on a per barrel basis costs are decreasing. These increases were partially offset by no turnaround costs in 2011. We incurred $66 million and $99 million in the second quarter and first six months of 2010 associated with the turnaround. Additionally, estimated costs of $64 million net to us have been recorded in the second quarter of 2011 to address water flow in a previously mined and contained area of the Muskeg River mine.

Purchases from related parties increased $36 million and $52 million in the second quarter and first six months of 2011 compared to the same periods of 2010. Our most significant related party purchases are from the Alba gas plant in Equatorial Guinea in which we own an equity interest. Higher liquid hydrocarbon prices in 2011 increased the value of those purchases.

Depreciation, depletion and amortization (“DD&A”) increased in the second quarter and first six months of 2011 from the comparable prior-year periods. Increased DD&A related to the higher sales volumes in our OSM segment and in our E&P segment, primarily in the Gulf of Mexico.

Impairments in the first six months of 2011 related primarily to our Droshky development in the Gulf of Mexico for $273 million and an intangible asset for a LNG delivery contract at Elba Island, as previously discussed. In 2010, impairments were primarily related to the Powder River Basin in the amount of $423 million. See Note 12 for information about these impairments.

Selling, general and administrative expenses increased $12 million in the second quarter and $47 million in the first six months of 2011 compared to the same periods in 2010 primarily due to additional compensation expense. The first six months of 2011 also includes higher costs of stock awards due to increased stock price of Marathon.

Exploration expenses were $145 million in the second quarter of 2011, with $62 million related to dry wells and $375 million in the first six months of 2011, including expenses related to dry wells of $220 million, primarily in the Gulf of Mexico, Indonesia, and Norway. Exploration expenses were $125 million and $223 million in the second quarter and first six months of 2010, including expenses related to dry wells of $57 million and $89 million, primarily in the Gulf of Mexico and Equatorial Guinea.

Provision for income taxes increased $176 million in the second quarter and decreased $38 million in the first six months of 2011 from the comparable periods of 2010.

The following is an analysis of the effective income tax rates for the first six months of 2011 and 2010:

	Six Months Ended June 30,
	2011			2010
Statutory U.S. income tax rate		35	%		35	%
Effects of foreign operations, including foreign tax credits		11			17
Change in permanent reinvestment assertion		12			-
Adjustments to valuation allowances		-			1
Tax law change		2			2
Effective income tax rate for continuing operations		60	%		55	%

As discussed in Note 9 to the consolidated financial statements, we suspended production operations in Libya in the first quarter of 2011, where the statutory tax rate is in excess of 90 percent. As a result, the effects of foreign operations on our effective tax rate decreased in the first six months of 2011 compared to the same period of 2010. This decrease was partially offset by a deferred tax charge of $122 million related to an internal restructuring of our international subsidiaries in the second quarter of 2011.

We reduced our valuation allowance related to foreign tax credits by $228 million due to recognizing deferred U.S. tax on previously undistributed earnings. In addition, we recorded a valuation allowance of $18 million on our deferred tax assets related to state operating loss carryforwards. Due to the spin-off (see Note 2), we have determined it is more likely than not that we will be unable to realize all recorded deferred tax assets.

The effective tax rate is also influenced by a variety of factors including the geographical and functional sources of income, the relative magnitude of these sources of income, foreign currency remeasurement effects, and tax legislation changes. See Note 9 to the consolidated financial statements for further discussion of items impacting our effective tax rate.

The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to individual items not allocated to segments is reported in corporate and other unallocated items.

Discontinued operations reflect the June 30, 2011 spin-off of our downstream businesses and the historical results of those operations, net of tax, for all periods presented.

Segment Results

Segment income (loss) is summarized in the following table:

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2011			2010			2011			2010
E&P
United States	$	126		$	25		$	157		$	134
International		475			407			1,112			800
E&P segment		601			432			1,269			934

OSM		69			(60	)		101			(77	)
IG		43			24			103			68

Segment income		713			396			1,473			925
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(21	)		7			(136	)		(80	)
Foreign currency remeasurement of income taxes		(3	)		37			(17	)		70
Impairments		(195	)		(9	)		(195	)		(271	)
Loss on early extinguishment of debt		-			(57	)		(176	)		(57	)
Tax effect of subsidiary restructuring		(122	)		-			(122	)		-
Deferred income tax items		(50	)		-			(50	)		(45	)
Water abatement - Oil Sands		(48	)		-			(48	)		-
Gain on dispositions		24			-			24			449
Income from continuing operations		298			374			753			991
Discontinued operations		698			335			1,239			175
Net income	$	996		$	709		$	1,992		$	1,166

United States E&P income increased $101 million and $23 million in the second quarter and first six months of 2011 compared to the same periods of 2010. The income increase in the second quarter of 2011 was primarily the result of higher liquid hydrocarbon realization and sales volume increases, as previously discussed, offset by increased DD&A. For the six-month period, the increase in liquid hydrocarbon realizations and sales volume increases were partially offset by increased DD&A, exploration expenses and lower derivative revenue.

International E&P income increased $68 million in the second quarter of 2011 and $312 million in the first six months of 2011 compared to the same periods of 2010. The income increase in the second quarter was primarily due to a lower effective tax rate, as previously discussed. Liquid hydrocarbon realizations increased 43 percent and 38 percent for the second quarter and first six months of 2011 compared to the same periods of 2010 which increased income in the first six months when compared to the same period in the prior year. This increase was partially offset by increased exploration expense in the first six months of 2011.

OSM segment income increased $129 million and $178 million in the second quarter and first six months of 2011. As previously discussed, higher sales volumes and synthetic crude realizations in the second quarter and the first six months of 2011 were the primary reasons for the increase in income. This was partially offset by increased costs and higher DD&A.

IG segment income increased $19 million and $35 million in the second quarter of 2011 and first six months of 2011 compared to the same periods of 2010. The increase was primarily the result of higher price realizations in both periods of 2011 compared to 2010.

Management’s Discussion and Analysis of Cash Flows and Liquidity

Cash Flows

Net cash provided by continuing operations totaled $3,320 million in the first six months of 2011, compared to $1,955 million in the first six months of 2010 reflecting primarily the impact of higher liquid hydrocarbon prices on operating income.

Net cash used in investing activities totaled $1,873 million in the first six months of 2011, compared to $1,142 million in the first six months of 2010. Significant investing activities are additions to property, plant and equipment and disposal of assets. In the first half of 2011, most of the additions were in the E&P segment with continued spending on U.S. unconventional resource plays and drilling in Norway, Indonesia and the Iraqi Kurdistan Region. This compares to spending in the first half of 2010 which was more focused upon the U.S., particularly the Gulf of Mexico. Spending

has slowed compared to 2010 in our OSM segment as the upgrader portion of AOSP Expansion 1 was completed and commenced operations in the second quarter 2011. In the first six months of 2010, the majority of sales proceeds were from the sale of a portion of our interest in Block 32 offshore Angola. A $100 million deposit related to the pending purchase of acreage from Hilcorp in the Eagle Ford shale formation was paid in the second quarter of 2011.

For further information regarding capital expenditures by segment, see Supplemental Statistics.

Net cash used in financing activities was $1,779 million in the first six months of 2011, compared to $970 million in the first six months of 2010. Dividends paid were a significant use of cash in both periods. During the first quarter of 2011, we retired $2.5 billion aggregate principal amount of our debt. In the first half of 2010, we retired $500 million aggregate principal value of debt. In connection with the spin-off, we distributed $1.6 billion to MPC in the second quarter of 2011.

Liquidity and Capital Resources

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations and our $3.0 billion committed revolving credit facility. Because of the alternatives available to us, including internally generated cash flow and access to capital markets, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, share repurchase program, and other amounts that may ultimately be paid in connection with contingencies.

Capital Resources

At June 30, 2011, we had no borrowings against our revolving credit facility and no commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 2 percent at June 30, 2011, compared to 14 percent at December 31, 2010. This includes $221 million of debt that is serviced by United States Steel Corporation (“United States Steel”).

	June 30,			December 31,
(In millions)	2011			2010
Long-term debt due within one year	$	338		$	295
Long-term debt		4,684			7,601

Total debt	$	5,022		$	7,896

Cash	$	4,711		$	3,951
Equity	$	16,707		$	23,771

Calculation:

Total debt	$	5,022		$	7,896
Minus cash		4,711			3,951

Total debt minus cash	$	311		$	3,945

Total debt		5,022			7,896
Plus equity		16,707			23,771
Minus cash		4,711			3,951

Total debt plus equity minus cash	$	17,018		$	27,716

Cash-adjusted debt-to-capital ratio		2	%		14	%

Capital Requirements

We expect to close the acquisition of Eagle Ford shale acreage from Hilcorp on November 1, 2011. This is a cash transaction valued at $3.5 billion, subject to closing adjustments, customary terms and conditions.

While the dividends will be subject to quarterly review by the respective boards, following the spin-off the aggregate $0.25 per share quarterly dividend ($1 per share per annum dividend) will be maintained by allocating the dividend as follows: Marathon Oil will pay an initial dividend of $0.15 per quarter or $0.60 per year (based on approximately 710 million shares outstanding) and MPC will pay $0.20 per quarter or $0.80 per year (based on an estimated 355 million shares outstanding). On July 27, 2011, our Board of Directors approved a dividend of 15 cents per share for the second quarter of 2011, payable September 12, 2011 to stockholders of record at the close of business on August 17, 2011.

Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion. As of June 30, 2011, we had repurchased 66 million common shares at a cost of $2,922 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. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and market conditions. No shares have been repurchased under this program during the period from August 2008 through June 2011.

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.

Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Estimates may differ from actual results. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The completion of the agreement to purchase asset from Hilcorp in the Eagle Ford shale formation is subject to customary closing conditions. 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, and natural gas, 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

The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of June 30, 2011:

(In millions)	Total		2011			2012-2013		2014-2015	Later Years
Long-term debt (excludes interest)(a)	$	4,995	$	232	$	326	$	136	$	4,301
Sale-leaseback financing
Capital lease obligations(a)		57		5		23		2		27
Operating lease obligations(a)		282		19		70		56		137
Operating lease obligations under sublease(a)
Purchase obligations:
Crude oil and feedstock contracts		102		36		61		3		2
Transportation and related contracts		1,276		145		213		149		769
Contracts to acquire property, plant and equipment		1,486		554		471		424		37
LNG terminal operating costs(b)		126		6		26		26		68
Service and materials contracts(c)		912		108		277		107		420
Unconditional purchase obligations(d)		40		8		16		16		-
Commitments for oil and gas exploration
(non-capital)(e)		53		39		8		1		5
Other long-term liabilities reported in the consolidated balance sheet(f)		2,795		235		863		717		980
Total contractual cash obligations(g)	$	12,124	$	1,387	$	2,354	$	1,637	$	6,746

(a)	Includes debt and lease obligations assumed by United States Steel upon the USX Separation.

(b)	We have the right to deliver 58 bcf of natural gas per year to the Elba Island LNG re-gasification terminal. The agreement’s primary term ends in 2021. Pursuant to this agreement, we are also committed to pay for a portion of the operating costs of the terminal.

(c)	Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.

(d)	We are party to a long-term transportation services agreement with Alliance Pipeline. This agreement was used by Alliance Pipeline to secure its financing.

(e)	Commitments on oil and gas exploration (non-capital) include estimated costs related to contractually obligated exploratory work programs that are expensed immediately, such as geological and geophysical costs.

(f)	Primarily includes obligations for pension and other postretirement benefits including medical and life insurance, which we have estimated through 2019. Also includes amounts for uncertain tax positions.

(g)	This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties.

Receivable from United States Steel

We remain obligated (primarily or contingently) for $225 million of certain debt and other financial arrangements for which United States Steel has assumed responsibility for repayment (see the USX Separation in Item 1. of our 2010 Annual Report on Form 10-K). United States Steel reported in its Form 10-Q for the three months ended June 30, 2011 that it believes that its liquidity will be adequate to satisfy its obligations for the foreseeable future.

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.

In July 2011, the Environmental Protection Agency (“U.S. EPA”) finalized a Federal Implementation Plan under the Clean Air Act that includes New Source Review regulations which apply to air emissions sources in Indian country states of Wyoming, Oklahoma and North Dakota. This rule will become effective on August 30, 2011, and will require the registration and/or permitting of our facilities. We cannot reasonably estimate the impact of these new permitting requirements until the U.S. EPA finalizes its permitting procedures.

There have been no other significant changes to our environmental matters subsequent to December 31, 2010.

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.

During the second quarter, the AOSP operator determined the need and developed preliminary plans to address water flow into a previously mined and contained section of the Muskeg River mine. Estimated costs of $64 million net to us have been recorded to cost of revenues in the second quarter of 2011.

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 related to continuing operations subsequent to December 31, 2010.

Accounting Standards Not Yet Adopted

The Financial Accounting Standards Board (“FASB”) amended the reporting standards for comprehensive income in June 2011 to eliminate the option to present the components of other comprehensive income as part of the statement of changes in stockholders' equity. All non-owner changes in stockholders’ equity are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of other comprehensive income, and the total of comprehensive income. The amendments did not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. We are still evaluating this reporting standard, but we do not expect adoption of this amendment to have a significant impact on our consolidated results of operations, financial position or cash flows.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A Quantitative and Qualitative Disclosures about Market Risk, in our 2010 Annual Report on Form 10-K.

Disclosures about how derivatives are reported in our consolidated financial statements and how the fair values of our derivative instruments are measured may be found in Note 12 and 13 to the consolidated financial statements.

The majority of our previous derivative activity was conducted by our downstream business. Sensitivity of the commodity derivatives and interest rate swaps related to continuing operations has not changed significantly.

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, 2011, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2011			2010			2011			2010

Segment Income (Loss)
Exploration and Production
United States	$	126		$	25		$	157		$	134
International		475			407			1,112			800
E&P segment		601			432			1,269			934
Oil Sands Mining		69			(60	)		101			(77	)
Integrated Gas		43			24			103			68
Segment income		713			396			1,473			925
Items not allocated to segments, net of income taxes		(415	)		(22	)		(720	)		66
Income from continuing operations		298			374			753			991
Discontinued operations		698			335			1,239			175
Net income	$	996		$	709		$	1,992		$	1,166
Capital Expenditures(a)
Exploration and Production
United States	$	556		$	412		$	905		$	870
International		193			173			512			318
E&P segment		749			585			1,417			1,188
Oil Sands Mining		80			243			200			508
Integrated Gas		-			-			1			1
Corporate		24			14			30			14
Total	$	853		$	842		$	1,648		$	1,711
Exploration Expenses
United States	$	54		$	112		$	204		$	158
International		91			13			171			65
Total	$	145		$	125		$	375		$	223

(a)	Capital expenditures include changes in accruals.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010

E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbpd)
United States		72		57		75		57

Europe		87		110		99		98
Africa		39		79		49		81
Total International		126		189		148		179
Worldwide		198		246		223		236
Net Natural Gas Sales (mmcfd)
United States		315		334		341		343

Europe(b)		96		104		99		106
Africa		420		402		433		378
Total International		516		506		532		484
Worldwide		831		840		873		827
Total Worldwide Sales (mboepd)		337		386		368		374

Average Realizations (e)
Liquid Hydrocarbons (per bbl)
United States	$	99.51	$	68.01	$	92.76	$	70.25

Europe		122.13		79.66		115.27		79.36
Africa		76.86		69.41		79.60		70.20
Total International		108.05		75.37		103.51		75.20
Worldwide	$	104.93	$	73.68	$	99.89	$	74.00

Natural Gas (per mcf)
United States	$	5.08	$	4.41	$	5.12	$	4.96

Europe		10.05		5.92		10.18		6.05
Africa(c)		0.25		0.25		0.25		0.25
Total International		2.06		1.41		2.09		1.52
Worldwide	$	3.21	$	2.61	$	3.28	$	2.95

OSM Operating Statistics
Net Synthetic Crude Sales (mbpd) (d)		41		20		39		22
Synthetic Crude Average Realization (per bbl)(e)	$	100.68	$	65.11	$	93.26	$	69.94

IG Operating Statistics
Net Sales (mtpd) (f)
LNG		6,614		6,556		7,215		6,176
Methanol		1,243		1,135		1,281		1,147

(b)	Includes natural gas acquired for injection and subsequent resale of 13 mmcfd and 16 mmcfd for the second quarters of 2011 and 2010, and 14 mmcfd and 21 mmcfd for the first six months of 2011 and 2010.

(c)

Primarily represents a fixed price under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC (“AMPCO”) and Equatorial Guinea LNG Holdings Limited (“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.

(d)	Includes blendstocks.

(e)	Excludes gains and losses on derivative instruments.

(f)	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

In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. Noble is seeking an unspecified amount of damages. We are vigorously defending this litigation. The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain. We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.

Environmental Proceedings

In April 2008, the State of Colorado Oil and Gas Conservation Commission (“COGCC”) issued a Notice of Alleged Violation as a result of a release of flow-back water from a lined reserve pit in Garfield County, Colorado. No formal enforcement action was initiated by COGCC until May 2011. This matter was finalized on June 30, 2011 and a penalty in the amount of $143,350 has been paid.

In December 2008, the State of New Mexico filed a state court suit against us alleging violations of the New Mexico Air Quality Control Act. The lawsuit arose out of a February 2008 notice of violation issued to our Indian Basin Natural Gas Plant. We believe there has been no adverse impact to public health or the environment, having implemented voluntary emission reduction measures over the years. We have finalized a consent order and the court has approved it. The order required a cash penalty of $610,560 plus plant compliance projects and supplemental environmental projects estimated to cost over $5 million. We paid the cash penalty of $610,560 and entered into a Supplemental Consent Decree, approved by the court on July 30, 2010, pursuant to which we would pay $2.7 million as a civil penalty in lieu of one of the proposed supplemental environmental projects. All of these payments were made on August 11, 2010. Installation of the plant compliance projects was completed on November 15, 2010, by the current operator of the plant. We were the operator and part owner of the plant through June 2009. We are working with the other plant owners to obtain reimbursement for their share of these costs. In March 2011, the State of New Mexico found that we complied in full with the terms and Conditions of the Consent Decree (as amended by the Supplemental Consent Decree), and held that the case was dismissed, and the Consent Decree terminated. Thus, this matter is concluded.

SEC Investigation Relating to Libya

On May 25, 2011 we received a subpoena issued by the Securities and Exchange Commission (“SEC”) requiring the production of documents related to payments made to the government of Libya, or to officials and persons affiliated with officials of the government of Libya. We have been and intend to continue cooperating with the SEC in its investigation.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. The discussion of such risks and uncertainties may be found under Item 1A. Risk Factors in our 2010 Annual Report on Form 10-K. The following is an update to our risk factors.

The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.

Hydraulic fracturing is a commonly used process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. The U.S. Congress has considered legislation that would require additional regulation affecting the hydraulic fracturing process. Consideration of new federal regulation and increased state oversight continues to arise. The U.S. EPA announced in the first quarter of 2010 its intention to conduct a comprehensive research study on the potential effects that hydraulic fracturing may have on water quality and public health. The U.S. EPA has begun preparation for the study and expects to complete the study in 2012. In addition, various state-level initiatives in regions with substantial shale gas resources have been or may be proposed or implemented to further

regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal or state laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs, which could adversely affect our financial position, results of operations and cash flows.

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



	Column (a)			Column (b)		Column (c)		Column (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

04/01/11 – 04/30/11		6,374		$	53.77		-	$	2,080,366,711
05/01/11 – 05/31/11		19,629		$	53.62		-	$	2,080,366,711
06/01/11– 06/30/11		32,706	(c)	$	50.54		-	$	2,080,366,711
Total		58,709		$	51.92		-

(a)	29,059 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

(b)

Under the terms of the transaction whereby we acquired the minority interest in Marathon Petroleum Company LLC and other businesses from Ashland Inc. (“Ashland”), Ashland shareholders have the right to receive 0.2364 shares of Marathon Oil common stock for each share of Ashland common stock owned as of June 30, 2005 and cash in lieu of fractional shares based on a value of $52.17 per share. In the second quarter of 2011, we acquired 6 fractional shares due to acquisition share exchanges and Ashland share transfers pending at the closing of the transaction.

(c)

29,644 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 Oil.

(d)

We 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, 2011, 66 million split-adjusted common shares had been acquired at a cost of $2,922 million, which includes transaction fees and commissions that are not reported in the table above.

Item 6. Exhibits

The following exhibits are filed as a part of this report:

Exhibit Number

Incorporated by Reference

Filed Herewith

Furnished Herewith

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

2.1

Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation.

8-K

2.1

5/26/11

2.2++

Purchase and Sale Agreement between Hilcorp Resources Holding, LP and Marathon Oil Company dated May 31, 2011

3.1

Amended and Restated By-Laws of Marathon Oil Corporation effective April 27, 2011.

8-K

3.1

4/29/11

10.1

Tax Sharing Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC.

8-K

10.1

5/26/11

10.2

Employee Matters Agreement dated as of May 25, 2011 among Marathon Oil Corporation and Marathon Petroleum Corporation.

8-K

10.2

5/26/11

10.3

Amendment to Employee Matters Agreement dated as of June 30, 2011 among Marathon Oil Corporation and Marathon Petroleum Corporation

10.4

Transition Services Agreement dated as of May 25, 2011 between Marathon Oil Corporation and Marathon Petroleum Corporation.

8-K

10.3

5/26/11

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.

101.INS

XBRL Instance Document

Exhibit Number

Incorporated by Reference

Filed Herewith

Furnished Herewith

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

101.SCH

XBRL Taxonomy Extension Schema

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

101.LAB

XBRL Taxonomy Extension Label Linkbase

101.DEF

XBRL Taxonomy Extension Definitions Linkbase

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, 2011	MARATHON OIL CORPORATION

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