10-Q

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

OR

[   ]	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.

1

        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.

2

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.

3

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.

4

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.

5

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.

6

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.

7

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.

8

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

9

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.

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

2) 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

3) 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.

10

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

11

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

12

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.

13

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

14

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	)

15

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.

16

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.

17

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	)

18

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.

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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 ofguarantees 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.

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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.

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 million boe 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.

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 theseforward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration

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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 theseforward-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.

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		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.

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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

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	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 segmentrevenues 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.

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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.

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.

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

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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 activitiestotaled $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

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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

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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

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(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.

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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

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 a significant impact on our consolidated results of operations, financial position or cash flows.

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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.

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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.

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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.

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Part II – OTHER INFORMATION

Item 1. Legal Proceedings

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.

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

36

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.

37

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					X
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					X
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.					X
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.					X
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.					X
32.1	Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.					X
32.2	Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.					X
101.INS	XBRL Instance Document						X

38

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.

101.SCH	XBRL Taxonomy Extension Schema	X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase	X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase	X
101.LAB	XBRL Taxonomy Extension Label Linkbase	X
101.DEF	XBRL Taxonomy Extension Definitions Linkbase	X

39

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

40

EX-2.2

Exhibit 2.2

·   Portions of this exhibit have been omitted pursuant to a request for confidential treatment according to Rule 24b-2 of the Securities and Exchange Commission. Non-public information has been filed with the Commission.

PURCHASE AND SALE AGREEMENT

between

HILCORP RESOURCES HOLDINGS, LP,

and

MARATHON OIL COMPANY

Dated as of May 31, 2011

5065.1

TABLE OF CONTENTS

Article 1. Definitions and Rules of Construction			1
	1.1	Definitions	1
	1.2	Rules of Construction	8
Article 2. Purchase and Sale; Closing			9
	2.1	Purchase and Sale of Interests	9
	2.2	Consideration	9
	2.3	Performance Deposit	9
	2.4	Closing Payment	9
	2.5	Closing Statement	10
	2.6	Closing Deposits	10
	2.7	Repayment of Company Indebtedness	10
	2.8	Closing	10
	2.9	Post-Closing Adjustment.	10
	2.1	Purchase Price Allocation	12
Article 3. Representations and Warranties Relating to Seller			13
	3.1	Organization of Seller	13
	3.2	Authorization; Enforceability	13
	3.3	Ownership of Interests	13
Article 4. Representations and Warranties Relating to the Company			14
	4.1	[Omitted]	14
	4.2	[Omitted]	14
	4.3	[Omitted]	14
	4.4	[Omitted]	15
	4.5	[Omitted]	15
	4.6	[Omitted]	16
	4.7	[Omitted]	16
	4.8	[Omitted]	16
	4.9	[Omitted]	17
	4.1	[Omitted]	18
	4.11	[Omitted]	18
	4.12	[Omitted]	19
	4.13	[Omitted]	19
	4.14	[Omitted]	19
	4.15	[Omitted]	19
	4.16	[Omitted]	19
Article 5. Representations and Warranties Relating to Buyer			19
	5.1	Organization of Buyer	19
	5.2	Authorization; Enforceability	19
	5.3	No Conflict; Consents	20
	5.4	Litigation	20
	5.5	Brokers’ Fees	20
	5.6	Financial Ability	20
	5.7	Securities Law Compliance	20
	5.8	Buyer’s Independent Investigation	20
Article 6. Covenants			21
	6.1	Conduct of Business	21
	6.2	Transferred and Terminated Contracts	23
	6.3	Access and Title Examination	23
	6.4	Third Party Approvals	23
	6.5	Regulatory Filings	23
	6.6	Books and Records	24
	6.7	Use of Hilcorp Marks	25
	6.8	Insurance	25
	6.9	Tag Along Rights	26
	6.1	Company	26
	6.11	Company Indebtedness	26
	6.12	Further Assurances	27
	6.13	Fees and Expenses	27
	6.14	Continuation of Operatorship	27
	6.15	Cooperation with Respect to Financial Statements	27
	6.16	Replacement of Bonds, Letters of Credit, Guarantees, and Security Deposits	27
	6.17	Data Transfer	28
	6.18	Restricted Area	28
	6.19	Non-Solicitation	28
	6.2	April 2011 Balance Sheet	29
	6.21	[Omitted]	29
Article 7. Tax Matters			29
	7.1	Responsibility for Filing Tax Returns and Paying Taxes	29
	7.2	Responsibility for Tax Audits	29
	7.3	Tax Refunds	30
	7.4	Transfer Taxes	30
	7.5	Tax Treatment of Indemnities	30
	7.6	Survival and Conflict.	30
Article 8. Conditions to Closing			30
	8.1	Conditions to Obligations of Buyer to Closing	30
	8.2	Conditions to the Obligations of Seller to Closing	31
Article 9. Indemnification and Waivers			32
	9.1	Indemnification	32
	9.2	Limitations on Liability	33
	9.3	Procedures	34
	9.4	Waiver of Consequential Damages	36
	9.5	Waivers and Disclaimers	36
	9.6	Exclusive Remedy and Release	37
Article 10. Termination			37
	10.1	Termination	37
	10.2	Effect of Termination	39
Article 11. Other Provisions			39
	11.1	Notices	39
	11.2	Assignment	40
	11.3	Rights of Third Parties	40
	11.4	Counterparts	40
	11.5	Entire Agreement	41
	11.6	Disclosure Schedule	41
	11.7	Amendments	41
	11.8	Publicity	41
	11.9	Severability	41
	11.1	Specific Performance	42
	11.11	Governing Law; Jurisdiction	42

LIST OF EXHIBITS AND SCHEDULES

Exhibits:
Exhibit A-1	Assignment Agreement
Exhibit A-2	Performance Deposit Escrow Agreement
Exhibit A-3	Indemnity Deposit Escrow Agreement
Exhibit A-4	Title Defect Deposit Escrow Agreement
Exhibit B	Title Defects Procedures
Exhibit C-1	Leases
Exhibit C-2	Company Assets
Exhibit C-3	Carried Interest Agreement
Exhibit D	Wells
Exhibit E	Interim Operations Plan
Schedules:
Schedule 1.1	Knowledge of Seller
Schedule 3.3	Ownership of Interests
Schedule 4.2	No Conflict; Consents
Schedule 4.4	Litigation
Schedule 4.5	Financial Statements
Schedule 4.6	Absence of Certain Changes
Schedule 4.7	Taxes
Schedule 4.8	Material Contracts
Schedule 4.10	Environmental Matters
Schedule 4.11(a)	Compliance with Laws
Schedule 4.12	Insurance
Schedule 4.15	Bonds, Letters of Credit, Guarantees and Security Deposits
Schedule 6.2(a)	Transferred Contracts
Schedule 6.2(b)	Agreements to be Terminated
Schedule 6.10	Tag Along Rights
Schedule 6.17	Property Records Delivery Schedule

PURCHASE AND SALE AGREEMENT

THIS PURCHASE AND SALE AGREEMENT (this “Agreement”), dated as of May 31, 2011, is between Hilcorp Resources Holdings, LP, a Delaware limited partnership (“Seller”), and Marathon Oil Company, an Ohio corporation (“Buyer”), and solely for the purposes of the covenants in Section 6.18, Hilcorp Energy Company, a Texas corporation (“HEC”).  Seller and Buyer are sometimes referred to herein individually as a “Party” and collectively as the “Parties.”

Recital:

Seller owns all of the issued and outstanding member interests (the “Interests”) of Hilcorp Resources, LLC, a Delaware limited liability company (the “Company”), and Seller desires to sell to Buyer, and Buyer desires to purchase from Seller, the Interests, on and subject to the terms and conditions of this Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained herein, the Parties agree as follows:

Article 1.

Definitions and Rules of Construction

1.1Definitions»

.  Capitalized terms used throughout this Agreement and not defined in this Section 1.1 have the meaning ascribed to them elsewhere in this Agreement or in the Schedules or Exhibits, including Section 1 of Exhibit B.  As used herein, the following terms shall have the following meanings:

“Adjustment Amount” means an amount equal to:  (i) the sum of (A) all costs, expenses, and other expenditures incurred by or on behalf of Seller or the Company on or after May 1, 2011 and paid prior to the Closing Date in respect of owning, developing, operating, and maintaining the Company Assets (including the renewal and extension of leases) (in accordance with the relevant operating agreement, where applicable), including development costs and expenditures related to confirming title, permitting, drilling, completing, fracturing, testing, deepening, plugging back, side tracking, reworking, and operating wells on the Company Assets, costs associated with gathering, transporting, processing, and marketing production from the Company Assets, ad valorem, production, and severance taxes, and interest costs, commitment fees (including those for unused borrowings and increasing the Company’s borrowing base) and letter of credit fees related to Indebtedness for Borrowed Money of the Company, but excluding all obligations with respect to Hedge Contracts, (B) costs of acquiring additional oil, gas, and mineral leases (including purchase money, lease bonus payments, broker fees, and other similar costs or payments) during the Interim Period, (C) amounts incurred by or on behalf of Seller or the Company during the Interim Period and paid to HEC (1) as overhead charges under operating agreements (and accounting procedures) relating to or covering the Company Assets and (2) under [Omitted], and (D) the amount of cash on hand and cash equivalents in lock boxes or otherwise in the possession of the Company at Closing, plus deposits with third parties and any checks in transit; less (ii) the sum of (X) all income, revenues, and proceeds received by the Company prior to the Closing Date and attributable to the Interim Period, including the sale of hydrocarbons produced from the Company Assets during the Interim Period, (Y) the Resolved Title Defect Amount, and (Z) any insurance proceeds received by the Company prior to the Closing Date and attributable to losses during the Interim Period.  For purposes of clarity, a positive Adjustment Amount will increase the Base Purchase Price at Closing and a negative Adjustment Amount will decrease the Base Purchase Price at Closing.

“Affiliate” means, with respect to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with, such specified Person through one or more intermediaries or otherwise.  For the purposes of this definition, “control” means, where used with respect to any Person, the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise, and the terms “controlling” and “controlled” have correlative meanings.  For purposes of this Agreement, Kohlberg, Kravis & Roberts Co. and its Affiliates (other than Seller or the Company) shall not be deemed Affiliates of HEC or any of its Affiliates.

“Agreement” is defined in the preamble to this Agreement.

“Allocation” is defined in Section 2.10.

“Arbitrator’s Closing Balance Sheet” is defined in Section 2.9(b).

“Arbitrator’s Closing Statement” is defined in Section 2.9(b).

“Assignment Agreement” means the Assignment Agreement attached hereto as Exhibit A-1.

“Audited Financial Statement” is defined in Section 4.5(a).

“Base Purchase Price” is defined in Section 2.2.

“Business Day” means any day that is not a Saturday, Sunday, or legal holiday in the States of Texas and New York and that is not otherwise a federal holiday in the United States.

“Buyer” is defined in the preamble to this Agreement.

“Buyer Indemnified Parties” is defined in Section 9.1(a).

“Claim Notice” is defined in Section 9.3(a).

“Closing” is defined in Section 2.8.

“Closing Balance Sheet” is defined in Section 2.9(a).

“Closing Date” is defined in Section 2.8.

“Closing Payment” is defined in Section 2.4.

“Closing Statement” is defined in Section 2.5.

“Closing Statement Arbitrator” is defined in Section 2.9(b).

“Code” means the Internal Revenue Code of 1986, as amended.

“Company” is defined in the recital of this Agreement.

“Company Assets” means the Leases described in Exhibit C-1; the Wells described in Exhibit D; the Equipment; the Material Contracts; Permits held by the Company; any surface fee interests, easements, licenses, servitudes, rights-of-way, surface leases, and other surface rights or interests appurtenant to, and owned by the Company for use in connection with, the Leases and Wells; hydrocarbons produced from or attributable to, the Leases or Wells; the Company Records; and any other assets, properties, or rights owned by the Company, including the assets, properties, and interests described in Exhibit C-2.  For purposes of the representations and warranties of Seller in this Agreement, Company Assets shall not include any additional Leases (or related assets) acquired by the Company during the Restricted Period.

“Company Indebtedness” means all outstanding Indebtedness for Borrowed Money of the Company as of the Closing Date.

“Company LLC Agreement” means the Second Amended and Restated Limited Liability Company Agreement of the Company, dated as of May 25, 2011, as amended from time to time.

“Company Records” is defined in Section 6.6.

“Confidentiality Agreement” means that certain confidentiality agreement, dated as of April 28, 2011, between Buyer and Company.

“Constituents of Concern” means petroleum substances (and any components, fractions or derivatives thereof), exploration and production wastes, and any other substance, in each case, to the extent defined or regulated as a hazardous substance, toxic substance, hazardous waste, hazardous material, radioactive material, radioactive waste, pollutant, or contaminant by any Environmental Law.

“Contract” means any written or legally binding oral agreement, commitment, lease, license, or other legally binding contractual undertaking.

“Deductible” means an amount equal to [Omitted] of the Base Purchase Price.

“Direct Claim” is defined in Section 9.3(d).

“Disclosure Schedule” means the schedules attached hereto.

“Dollars” and “$” mean the lawful currency of the United States.

“Environmental Laws” means all applicable Laws, including common law, relating to health, safety, the protection of the environment, natural resources, or threatened or endangered species, pollution, or its impacts on human health.

“Environmental Permits” means all permits, licenses, authorizations, certificates, and approvals of Governmental Authorities required by Environmental Laws for the conduct of the business of the Company.

“Equipment” means all equipment, machinery, buildings, fixtures, and other tangible personal property and improvements owned by the Company and located on the Lands or used or held for use in connection with the operation of the Company Assets or the production of oil or gas from the Leases and Wells.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

“ERISA Plan” means any (i) nonqualified deferred compensation plan (as described in Section 409A of the Code), (ii) any Employee Pension Benefit Plan (as described in Section 3(2) of ERISA), (iii) any Employee Welfare Benefit Plan (as described in Section 3(1) of ERISA), or (iv) any bonus, deferred compensation, incentive compensation, stock option, severance or termination pay arrangement.

“Escrow Agent” means JPMorgan Chase Bank, N.A.

“Estimated Adjustment Amount” is defined in Section 2.5.

“Excepted Employees” is defined in Section 6.19.

“Excepted Matters” is defined in Section 9.2(a).

“Final Closing Balance Sheet” is defined in Section 2.9(b).

“Final Closing Statement” is defined in Section 2.9(b).

“Final Settlement Date” is defined in Section 2.9(a).

“Financial Statement” is defined in Section 4.5(b).

“GAAP” means generally accepted accounting principles of the United States, consistently applied.

“Governmental Authority” means any federal, state, municipal, local, or similar governmental authority, regulatory or administrative agency, court, or arbitral body.

“HEC” is defined in the preamble to this Agreement.

“Hedge Contracts” means the Contracts listed in Part II of Schedule 4.8 and any other hedge or swap Contracts entered into by the Company after the date hereof and in the ordinary course of business in connection with Indebtedness for Borrowed Money of the Company.

“Hilcorp Marks” means the name “Hilcorp” and other trademarks, service marks, and trade names owned by Seller or its Affiliates.

“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

 “Indebtedness for Borrowed Money” means all obligations to any Person for borrowed money, including any obligation to reimburse any bank or other Person in respect of amounts paid or payable under a standby letter of credit.

“Indemnified Party” is defined in Section 9.3(a).

“Indemnifying Party” is defined in Section 9.3(a).

“Indemnity Deposit” means an amount equal to [Omitted] of the Base Purchase Price.

“Indemnity Deposit Escrow Account” means the account maintained by the Escrow Agent and initially funded with the Indemnity Deposit.

“Indemnity Deposit Escrow Agreement” is defined in Section 2.6.

“Interests” is defined in the recital of this Agreement.

“Interim Operations Plan” is defined in Section 6.1(a).

“Interim Period” means the period from and including May 1, 2011 to and including the Closing Date.

“IRS” means Internal Revenue Service of the United States.

“Knowledge” means, as to Seller, the actual knowledge of those Persons listed in Schedule 1.1 as of the date of this Agreement.

“Lands” means the lands covering the Leases described in Exhibit C-1.

“Law” means any applicable statute, writ, law, rule, regulation, ordinance, Order, judgment, injunction, award, determination, or decree of a Governmental Authority, in each case as in effect on and as interpreted on the date of this Agreement.

“Liens” means liens, pledges, options, mortgages, deeds of trust, or security interests.

“Losses” is defined in Section 9.1(a).

[Omitted].

“Material Adverse Effect” means, with respect to any Person, any circumstance, change, or effect that is materially adverse to the business, operations, assets, or financial condition of such Person taken as a whole, but shall exclude any circumstance, change, or effect resulting or arising from: (i) any general change in conditions in the industries or markets in which the Company operates; (ii) seasonal reductions in revenues and/or earnings of Seller and the Company in the ordinary course of their business; (iii) any adverse change, event, or effect on the global, national, or regional energy industry as a whole, including those impacting energy prices or the value of oil and gas assets and propertiesor other commodities, goods, or services, or the availability or costs of hedges; (iv) national or international political conditions, including any engagement in hostilities, whether or not pursuant to the declaration of a national emergency or war, or the occurrence of any military or terrorist attack; (v) changes in Law, GAAP, or the interpretation thereof; (vi) the entry into or announcement of this Agreement, actions contemplated by this Agreement, or the consummation of the transactions contemplated hereby (provided that the exceptions in this clause (vi) shall not be deemed to apply to references to Material Adverse Effect in the representations and warranties set forth in Section 4.2); (vii) any failure to meet internal or third party projections or forecasts or revenue or earnings or reserve predictions (provided that the foregoing shall not prevent any determination that the facts underlying any such failure have a Material Adverse Effect); (x) changes or developments in financial or securities markets or the economy in general; or (xi) effects of weather, meteorological events, natural disasters, or other acts of God, except to the extent such circumstance, change, or effect resulting or arising from clauses (i), (iii), or (iv) above materially and disproportionately affects such Person relative to other participants in the onshore oil and gas exploration and production industry in Texas.

“Material Contracts” is defined in Section 4.8.

“Notice of Disagreement” is defined in Section 2.9(a).

“Notices” is defined in Section 11.1.

“Order” means any order, judgment, injunction, ruling, sentence, subpoena, writ or award issued, made, entered or rendered by any court, administrative agency, or other Governmental Authority or by any arbitrator.

“Organizational Documents” means any charter, certificate of incorporation, articles of association, partnership agreements, limited liability company agreements, bylaws, operating agreement, or similar formation or governing documents and instruments.

“Party” and “Parties” are defined in the preamble of this Agreement

“Payoff Amount” is defined in Section 6.11.

“Payoff Letters” is defined in Section 6.11.

“Performance Deposit” is defined in Section 2.3.

“Performance Deposit Escrow Account” means the account maintained by the Escrow Agent and initially funded with the Performance Deposit.

“Performance Deposit Escrow Agreement” is defined in Section 2.3.

“Permits” means authorizations, licenses, permits, or certificates issued by Governmental Authorities.

“Person” means any individual, firm, corporation, partnership, limited liability company, incorporated or unincorporated association, joint venture, joint stock company, Governmental Authority, or other entity of any kind.

“Pre-Closing Tax Period” means any Tax period ending on or before the Closing Date.  With respect to the Texas franchise Tax, for purposes of this Agreement, the Tax period shall mean the accounting period upon which the Tax is based (i.e., the calendar year, or any portion thereof) and not the privilege period for which the Tax is paid.

“Proceeding” means any action, suit, litigation, arbitration, lawsuit, claim, proceeding, hearing, inquiry, investigation, or dispute commenced, brought, conducted, or heard by or before, or otherwise involving, any Governmental Authority or any arbitrator.

“Purchase Price” is defined in Section 2.2.

“Representatives” means a Person’s directors, officers, partners, members, managers, employees, agents or advisors (including attorneys, accountants, consultants, bankers, financial advisors, and any representatives of those advisors).

“Resolution Firm” is defined in Section 2.10.

“Resolved Title Defect Amount” means, for purposes of the Adjustment Amount, the amount by which the sum of any Title Defect Amounts finally determined in accordance with the procedures in Exhibit B prior to or on the Closing Date exceedsthe Deductible.

“Restricted Period” is defined in Section 6.1(a).

[Omitted]

“Selected Employees” is defined in Section 6.19.

“Seller” is defined in the preamble to this Agreement.

“Seller Indemnified Parties” is defined in Section 9.1(c).

“Specified Tax Representations” means clauses (viii) and (ix) of Section 4.7.

“Specified Taxes” means any Texas franchise Taxes.

“Straddle Period” means any Tax period that includes but does not end on (i) the Closing Date, in the case of income, franchise and similar Taxes, and (ii) April 30, 2011, in the case of all other Taxes.

“Tax Audit” means any audit, adjustment, claim, examination, assessment, contest or other proceeding with respect to Taxes.

“Tag Along Interests” is defined in Section 6.9.

“Tag Along Rights” is defined in Section 6.9.

“Tax Returns” means any report, return, election, document, estimated tax filing, declaration, claim for refund, information returns, or other filing provided to any Governmental Authority including any schedules or attachments thereto and any amendment thereof.

“Taxes” means all taxes, assessments, charges, duties, fees, levies, imposts or other similar charges imposed by a Governmental Authority, including all income, franchise, profits, margins, capital gains, capital stock, transfer, gross receipts, sales, use, transfer, service, occupation, ad valorem, real or personal property, excise, severance, windfall profits, customs, premium, stamp, license, payroll, employment, social security, unemployment, disability, environmental, alternative minimum, add-on, value-added, withholding and other taxes, any taxes of another Person for Texas franchise tax arising out of the Company’s inclusion in a combined tax report with such Person, and assessments, charges, duties, fees, levies, imposts or other similar charges of any kind, and all estimated taxes, deficiency assessments, additions to tax, penalties and interest with respect to taxes, whether disputed or otherwise.

“Third Party Claim” is defined in Section 9.3(a).

“Title Defect Deposit” is defined in Exhibit B.

“Title Defect Deposit Escrow Account” means the account maintained by the Escrow Agent and initially funded with the Title Defect Deposit.

“Title Defect Deposit Escrow Agreement” an escrow agreement substantially in form attached as Exhibit A-4.

“Unaudited Financial Statement” is defined in Section 4.5(b).

“United States” means United States of America.

1.2Rules of Construction

(a)All article, section, schedule and exhibit references used in this Agreement are to articles and sections of, and schedules and exhibits to, this Agreement unless otherwise specified.  The schedules and exhibits attached to this Agreement constitute a part of this Agreement and are incorporated herein for all purposes.

(b)If a term is defined as one part of speech (such as a noun), it shall have a corresponding meaning when used as another part of speech (such as a verb).  Terms defined in the singular have the corresponding meanings in the plural, and vice versa.  Unless the context of this Agreement clearly requires otherwise, words importing the masculine gender shall include the feminine and neutral genders and vice versa.  The term “includes” or “including” shall mean “including without limitation.”  The words “hereof,” “hereto,” “hereby,” “herein,” “hereunder” and words of similar import, when used in this Agreement, shall refer to this Agreement as a whole and not to any particular section or article in which such words appear.

(c)The Parties acknowledge that each Party and its attorney have reviewed this Agreement and that any rule of construction to the effect that any ambiguities are to be resolved against the drafting Party, or any similar rule operating against the drafter of an agreement, shall not be applicable to the construction or interpretation of this Agreement.

(d)The captions in this Agreement are for convenience only and shall not be considered a part of or affect the construction or interpretation of any provision of this Agreement.

(e)All references to currency herein shall be to, and all payments required hereunder shall be paid in, Dollars.

Article 2.

Purchase and Sale; Closing

2.1Purchase and Sale of Interests»

.  Upon the terms and subject to the conditions set forth in this Agreement, Seller shall sell, assign, transfer and convey to Buyer, and Buyer shall purchase and acquire from Seller, at the Closing, the Interests.   The Interests shall be transferred by Seller to Buyer by delivery of the Assignment Agreement at Closing.

2.2Consideration»

.  In consideration for the purchase of the Interests, Buyer agrees to pay to Seller $3,500,000,000.00(the “Base Purchase Price”), as adjusted by the Adjustment Amount (the Base Purchase Price as so adjusted, the “Purchase Price”).

2.3Performance Deposit»

.  No later than 2:00 p.m., Houston, Texas time, on June 3, 2011, Buyer shall deliver to the Escrow Agent a deposit of [Omitted] (the “Performance Deposit”) in cash by wire transfer of immediately available funds for deposit to the Performance Deposit Escrow Account, to assure Buyer’s performance of its obligations hereunder.  The Performance Deposit together with any interest accrued thereon shall be held pursuant to this Agreement and an escrow agreement substantially in the form attached as Exhibit A-2 (the “Performance Deposit Escrow Agreement”) until Closing and shall be applied as a credit against the Closing Payment as provided in Section 2.4.  No less than two (2) Business days prior to Closing, Seller and Buyer shall provide a joint written instruction to the Escrow Agent to release the Performance Deposit, together with any interest accrued thereon, to Seller at the Closing.  If this Agreement is terminated without a Closing, then the distribution of the Performance Deposit shall be governed by the provisions of Section 10.2, and Seller and Buyer shall provide a joint written instruction to the Escrow Agent to release the Performance Deposit in accordance therewith.

2.4Closing Payment»

.  At Closing, Buyer shall pay to Seller, in cash by wire transfer of immediately available funds to the account or accounts designated by Seller an amount equal to the Base Purchase Price as adjusted by the Estimated Adjustment Amount (as provided in Section 2.5 below) less the Performance Deposit (together with any interest accrued thereon) received by Seller on or prior to Closing, the Indemnity Deposit, and the Title Defect Deposit, if any (such amount, in the aggregate, the “Closing Payment”).

2.5Closing Statement»

.  Not later than five (5) Business Days prior to the Closing Date, Seller shall prepare and deliver to Buyer a statement (the “Closing Statement”) showing the estimated Adjustment Amount (using actual numbers and amounts where available, and using Seller’s good faith estimate of other amounts, where actual amounts are not available) (the “Estimated Adjustment Amount”).

2.6Closing Deposits»

.  Buyer agrees to pay to the Escrow Agent, at the Closing, in cash by wire transfer of immediately available funds (i) the Indemnity Deposit for deposit to the Indemnity Deposit Escrow Account and (ii) any Title Defect Deposit for deposit into the Title Defect Deposit Escrow Account.  The Indemnity Deposit plus any interest accrued thereon will be available to satisfy certain amounts owed by Seller to Buyer respecting indemnities under this Agreement in accordance with the terms of an escrow agreement substantially in the form attached as Exhibit A-3 (the “Indemnity Deposit Escrow Agreement”) and the Title Defect Deposit plus any interest accrued thereon will be available to satisfy any Title Defect Amounts owed by Seller to Buyer under Exhibit B in respect of claims for Title Defect Amounts that are not finally determined prior to Closing.

2.7Repayment of Company Indebtedness»

.  In connection with the Closing, Seller shall cause the Company to pay the applicable portion of the Payoff Amount to the applicable Persons pursuant to the terms of the Payoff Letters.  If requested by Seller, Buyer shall wire a portion of the Closing Payment directly to the applicable lenders to pay the Payoff Amount.

2.8Closing»

.  The closing of the sale and transfer of the Interests to Buyer as contemplated by this Agreement (the “Closing”) shall take place at the offices of Hilcorp Energy Company, 1201 Louisiana, Suite 1400, Houston, Texas 77002, on the later of (i) the third (3rd) Business Day following the satisfaction or waiver of all conditions to the obligations of the Parties set forth in Section 8.1 and Section 8.2 or (ii) November 1, 2011, or such other date as Buyer and Seller may mutually determine (the date on which the Closing occurs is referred to herein as the “Closing Date”).

2.9Post-Closing Adjustment.

(a)Revised Closing Statement.  On or before the date that is seventy (75) days after the Closing Date, Seller shall prepare and deliver to Buyer a revised Closing Statement setting forth the final Adjustment Amount as of the Closing Date accompanied by an unaudited balance sheet of the Company as of the Closing Date, prepared in accordance with GAAP and the Company’s past practices, consistently applied (the “Closing Balance Sheet”).  Seller shall provide to Buyer such data and information as Buyer may reasonably request supporting the amounts reflected on the revised Closing Statement and the Closing Balance Sheet (and reasonable access to Seller’s personnel, including internal accountants) to permit Buyer to perform or cause to be performed an audit of the Closing Statement and the Closing Balance Sheet, at Buyer’s expense.  The revised Closing Statement and the Closing Balance Sheet shall become final and binding upon the Parties on the date (the “Final Settlement Date”) that is forty-five (45) days following receipt thereof by Buyer unless Buyer gives Notice of its disagreement (“Notice of Disagreement”) to Seller prior to such date.  Any Notice of Disagreement shall specify in reasonable detail the dollar amount, nature, and basis of any disagreement so asserted.  If a Notice of Disagreement is received by Seller by the date specified in the immediately preceding sentence, then the Closing Statement and the Closing Balance Sheet (as revised in accordance with paragraph (b) below) shall become final and binding on the Parties on, and the Final Settlement Date shall be, the earlier of (1) the date upon which Seller and Buyer agree in writing with respect to all matters specified in the Notice of Disagreement and (2) the date upon which the Arbitrator’s Closing Statement and Arbitrator’s Closing Balance Sheet (each hereinafter defined) are issued by the Closing Statement Arbitrator (hereinafter defined).

(b)Final Closing Statement and Final Closing Balance Sheet.  During the forty-five (45) days following the date upon which Seller receives a Notice of Disagreement, Seller and Buyer shall use commercially reasonable efforts to attempt to resolve in writing any differences that they may have with respect to all matters specified in the Notice of Disagreement.  If at the end of such forty-five (45) day period (or earlier by mutual agreement), Buyer and Seller have not reached agreement on such matters, the matters that remain in dispute (and only such matters) shall promptly be submitted to KPMG LLP (the “Closing Statement Arbitrator”) for review and final and binding resolution.  If KPMG LLP is unable or unwilling to serve as an arbitrator hereunder, then Seller and Buyer shall, in good faith, mutually agree upon an independent national accounting firm who has not represented either Party at any time during the five (5) year period of time immediately preceding its designation hereunder, to serve as the Closing Statement Arbitrator.  Buyer and Seller shall, not later than seven (7) days prior to the hearing date set by the Closing Statement Arbitrator, each submit a written brief to the Closing Statement Arbitrator (and a copy thereof to the other Party on the same day) with dollar figures for settlement of the disputes as to the amount of the adjusted Adjustment Amount (together with a proposed Closing Statement and Closing Balance Sheet that reflects such figures) consistent with their respective calculations delivered pursuant to Section 2.9(a).The hearing shall be conducted on a confidential basis.  The Closing Statement Arbitrator shall consider only those items or amounts in the Closing Statement and Closing Balance Sheet which were identified in the Notice of Disagreement and which remain in dispute and the Closing Statement Arbitrator’s decision resolving the matters in dispute shall be based upon and be consistent with the terms and conditions in this Agreement.  In deciding any matter, the Closing Statement Arbitrator (i) shall be bound by the provisions of this Section 2.9 and the related definitions and (ii) may not assign a value to any disputed item greater than the greatest value for such item claimed by either Seller or Buyer or less than the smallest value for such item claimed by Seller or Buyer in their respective calculations delivered pursuant to Section 2.9(a). The Closing Statement Arbitrator shall render a decision resolving the matters in dispute (which decision shall include a written statement of findings and conclusions) promptly after the conclusion of the hearing, unless the Parties reach agreement prior thereto and withdraw the dispute from arbitration.  The Closing Statement Arbitrator shall provide to the Parties explanations in writing of the reasons for its decisions regarding the adjusted Adjustment Amount and shall issue the Final Closing Statement and Final Closing Balance Sheet (each defined below) reflecting such decision.  The decision of the Closing Statement Arbitrator shall be (i) final and binding on the Parties and (ii) final and non-appealable for all purposes hereunder; provided, however, that such decision may be reviewed, corrected or set aside by a court of competent jurisdiction, but only if and to the extent that the Closing Statement Arbitrator is found by such court of competent jurisdiction to have made mathematical errors with respect to its decision.  The cost of any arbitration (including the fees and expenses of the Closing Statement Arbitrator) under this Section 2.9(b) shall be borne entirely by the Party awarded the smaller percentage of the disputed amount by the Closing Statement Arbitrator. The fees and disbursements of Seller’s independent auditors and other costs and expenses incurred in connection with the services performed with respect to the Closing Statement and Closing Balance Sheet shall be borne by Seller and the fees and disbursements of Buyer’s independent auditors and other costs and expenses incurred in connection with their preparation of the Notice of Disagreement shall be borne by Buyer.  As used in this Agreement, the terms “Final Closing Statement” and “Final Closing Balance Sheet” shall mean the revised Closing Statement and the revised Closing Balance Sheet, respectively, described in Section 2.9(a), as prepared by Seller and as may be subsequently adjusted to reflect any subsequent written agreement between the parties with respect thereto, or if submitted to the Closing Statement Arbitrator, the Arbitrator’s Closing Statement (the “Arbitrator’s Closing Statement”) and the Arbitrator’s Closing Balance Sheet (the “Arbitrator’s Closing Balance Sheet”), each as described in this Section 2.9(b).

(c)Final Settlement.  If the amount of the adjusted Adjustment Amount as set forth on the Final Closing Statement exceeds the amount of the Estimated Adjustment Amount paid at Closing, then, within thirty (30) days after the Final Settlement Date, Buyer shall pay to Seller the amount by which the Adjustment Amount as set forth on the Final Closing Statement exceeds the Estimated Adjustment Amount paid at Closing.  If the amount of the adjusted Adjustment Amount as set forth on the Final Closing Statement is less than the Estimated Adjustment Amount paid at Closing, then Seller shall pay to Buyer, within five (5) days after the Final Settlement Date, the amount by which the adjusted Adjustment Amount, as set forth on the Final Closing Statement, is less than the Estimated Adjustment Amount shown in the Closing Statement.  Any post-Closing payment made pursuant to this Section 2.9(c) shall be made by means of a wire transfer of immediately available funds to a bank account designated by the Party receiving the funds

2.10Purchase Price Allocation »

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(a)The Parties agree that the transactions contemplated hereby will be treated for federal income Tax purposes as a purchase and sale of the assets of the Company.  On or prior to Closing, Seller shall provide to Buyer a schedule setting forth a proposal for an allocation of a portion of the Purchase Price (including any assumed liabilities) among the classes of Company Assets on IRS Form 8594 in accordance with Section 1060 of the Code and the U.S. Treasury Regulations promulgated thereunder (the “Allocation”).  If within thirty (30) days after Closing, Buyer notifies Seller in writing that Buyer objects to the allocation set forth in the Allocation, identifying in such writing  Buyer’s detailed objections, Buyer and Seller shall use commercially reasonable efforts to resolve such dispute within fifteen (15) days thereafter.  In the event that Buyer and Seller are unable to resolve such dispute within such  fifteen (15) days, Buyer and Seller shall submit such disputed items for resolution to a mutually agreed internationally recognized national investment banking or accounting firm (“Resolution Firm”); which shall, within thirty (30) days after submission, report to Buyer and Seller its determination on such disputed allocations.  The allocations determined by the Resolution Firm shall be conclusive and binding upon Buyer and Seller.  Each of Buyer and Seller shall bear all fees and costs incurred by it in connection with the disputed allocations, except that all costs and expenses of the Resolution Firm relating to the disputed allocations shall be borne equally by Buyer and Seller.

(b)If an adjustment is made to the Purchase Price pursuant to this Agreement, the Allocation shall be adjusted accordingly in accordance with Section 1060 of the Code and as mutually agreed by  Buyer and Seller based solely on such adjustment. In the event that an agreement with respect to any adjustment is not reached within thirty (30) days after the Final Settlement Date, any disputed items shall be resolved in the manner described in Section 2.10(a).

(c)Seller and Buyer shall report consistently with the Allocation in all Tax Returns, including IRS Form 8594, which Seller and Buyer shall timely file with the IRS, and neither Seller nor Buyer shall take any position in any such return that is inconsistent with the Allocation, as adjusted, in each case, unless required to do so by a final determination as defined in Section 1313 of the Code, or otherwise with the written consent of the other Party.  Not later than ten (10) days prior to the filing of their respective IRS Forms 8594 relating to this transaction, each Party shall deliver to the other Party a copy of its IRS Form 8594.

Article 3.

Representations and Warranties Relating to Seller

Except as disclosed in the Disclosure Schedule, Seller hereby represents and warrants to Buyer as follows:

3.1Organization of Seller»

.  Seller is duly formed, validly existing, and in good standing under the laws of the jurisdiction of its organization or formation.

3.2Authorization; Enforceability»

.  Seller has full capacity, power, and authority to execute and deliver this Agreement and to perform its obligations hereunder.  The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized on the part of Seller, and no other proceeding on the part of Seller is necessary to authorize this Agreement or performance of the transactions contemplated hereby.  This Agreement has been duly and validly executed and delivered by Seller, (and all documents required hereunder to be executed and delivered by Seller at the Closing will be duly executed and delivered by Seller) and this Agreement constitutes, and at the Closing each such document will constitute, a valid and binding obligation of Seller, enforceable against Seller in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium, and similar Laws affecting creditors’ rights generally and subject, as to enforceability, to general principles of equity.

3.3Ownership of Interests»

.  Except as set forth on Schedule 3.3,:

(i)Seller holds of record and owns beneficially the Interests, free and clear of all Liens (other than restrictions under federal and state securities laws).

(ii)Seller is not a party to any option, warrant, purchase right, or other contract or commitment (other than this Agreement) that could require Seller to sell, transfer, or otherwise dispose of the Interests.  Other than this Agreement and the Company LLC Agreement, the Interests are not subject to any voting agreement or other contract, agreement, arrangement, commitment, or understanding restricting or otherwise relating to the voting, dividend rights or disposition of the Interests.

(iii)Upon the occurrence of the Closing, the delivery of the Interests to Buyer in accordance with the terms of this Agreement will transfer good and marketable title to the Interests free and clear of any Liens (other than restrictions under federal and state securities laws).

Article 4.

Representations and Warranties Relating to the Company

Except as disclosed in the Disclosure Schedule, Seller hereby represents and warrants to Buyer as follows:

[Omitted]

Article 5.

Representations and Warranties Relating to Buyer

Buyer hereby represents and warrants to Seller as follows:

5.1Organization of Buyer»

.  Buyer is a corporation, incorporated, validly existing and in good standing under the laws of Ohio.

5.2Authorization; Enforceability»

.  Buyer has all requisite corporate power and authority to execute and deliver this Agreement and to perform its obligations hereunder.  The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby have been duly and validly authorized and approved by Buyer, and no other corporate proceeding on the part of Buyer is necessary to authorize this Agreement.  This Agreement has been duly and validly executed and delivered by Buyer (and all documents required hereunder to be executed and delivered by Buyer at the Closing will be duly executed and delivered by Buyer), and this Agreement constitutes, and at the Closing each such document will constitute, a valid and binding obligation of Buyer, enforceable against Buyer in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and similar Laws affecting creditors’ rights generally and subject, as to enforceability, to general principles of equity.

5.3No Conflict; Consents»

.  Except as would not reasonably be expected to prevent, impede, or materially delay the ability of Buyer to enter into and perform its obligations under this Agreement, the execution and delivery of this Agreement by Buyer and the consummation of the transactions contemplated hereby by Buyer do not and shall not:

(i)violate any Law applicable to Buyer or require any filing with, consent, approval or authorization of, or, notice to, any Governmental Authority;

(ii)violate any Organizational Document of Buyer; or

(iii)require any filing with or permit, consent or approval of, or the giving of any notice to, any Person.

5.4Litigation»

.  Except as would not reasonably be expected to prevent, impede, or materially delay the ability of Buyer to enter into and perform its obligations under this Agreement, Buyer (i) is not subject to any outstanding injunction, judgment, Order, decree, ruling or charge, (ii) is not a party to a Proceeding, and, (iii) to the knowledge of Buyer, has not been threatened with any Proceeding.

5.5Brokers’ Fees»

.  Buyer and its Affiliates have not entered into any Contract with any Person that would require the payment by Seller or its Affiliates of any brokerage fee, finders’ fee, or other commission in connection with the transactions contemplated by this Agreement.

5.6Financial Ability»

.  Buyer has, through a combination of cash on hand and funds available under existing lines of credit, funds sufficient to fund the consummation of the transactions contemplated by this Agreement and satisfy all other costs and expenses in connection herewith.

5.7Securities Law Compliance»

.  Buyer (i) is acquiring the Interests for its own account and not with a view to distribution in violation of applicable securities laws, (ii) has sufficient knowledge and experience in financial and business matters so as to be able to evaluate the merits and risk of an investment in the Interests and is able financially to bear the risks thereof, and (iii) understands that the Interests will, upon purchase, be characterized as “restricted securities” under state and federal securities laws and that under such laws and applicable regulations the Interests may be resold without registration under such laws only in certain limited circumstances.

5.8Buyer’s Independent Investigation»

.  Buyer and its Representatives have undertaken an independent investigation and verification of the Company Assets and the business, operations, and financial condition of the Company.  Except for the representations and warranties made by Seller and the Company in this Agreement, Buyer acknowledges that there are no representations or warranties, express or implied, as to the Company Assets or the condition (financial or otherwise), assets, liabilities, operations, business or prospects of the Company.

Article 6.

Covenants

6.1Conduct of Business

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(a)Operations before Closing.  Except as provided in this Agreement, during the period from and including the date hereof until and including the Closing Date (the “Restricted Period”), without the prior written consent of Buyer, Seller shall cause the Company to, in all material respects, (i) operate the Company Assets in the ordinary course and in a manner substantially consistent with the interim operations plan as set forth in Exhibit E (the “Interim Operations Plan”) and (ii) use reasonable efforts to preserve intact its business and the Company Assets, consistent with available resources (including financial resources), (iii) use commercially reasonable efforts to operate its business and maintain the Company Assets in accordance with all Laws, including Environmental Laws (including Environmental Permits), currently in effect, or as may be amended or come into effect prior to the Closing, (iv) use commercially reasonable efforts to preserve their existing beneficial relationships with agents, vendors, lessors, contractors, suppliers and customers, (v) promptly notify Buyer of any material emergency or other material change in or affecting the Company’s business or the Company Assets, including any material Claim asserted or material Proceeding initiated against Seller with respect to the business of the Company or the Interests or against the Company, and (vi) use its reasonable best efforts to maintain insurance coverage on the Company Assets in the amounts and of the types currently in force.

(b)Restricted Activities. Without the prior written consent of Buyer or as otherwise permitted by the Interim Operations Plan, Seller shall cause the Company not to take any action to:

(i)amend its Organizational Documents;

(ii)adopt a plan of complete or partial liquidation, dissolution, restructuring, recapitalization or other reorganization;

(iii)change its accounting methods, policies, or practices, except as required by applicable Law;

(iv)sell, transfer, abandon, farmout, lease, encumber (other than Permitted Encumbrances or Liens for Indebtedness for Borrowed Money), exchange or otherwise dispose of any of the Company Assets (other than the sale of hydrocarbons produced from wells included in the Company Assets, the sale of worn-out or obsolete equipment, spare parts, or minor or insignificant assets, assignments of Company Assets as required by the terms of applicable agreements in existence as of May 1, 2011 and pooling or unitization of Company Assets with properties of unrelated third parties);

(v)merge or consolidate with, or purchase substantially all of the assets or business of, or equity interests in, or make an investment in any Person (other than extensions of credit to customers in the ordinary course of business);

(vi)issue or sell any equity interests, notes, bonds, or other securities of the Company, or any option, warrant or right to acquire same or declare or pay any dividend or distribution to any Person on or with respect to its equity interests;

(vii)terminate or voluntarily relinquish any material permit, license, or other authorization from any Governmental Authority necessary for the Company’s conduct of its business;

(viii)incur any Indebtedness for Borrowed Money or purchase money indebtedness, whether or not evidenced by a note, bond, debenture or similar instrument (nor enter into any guarantees with respect to any such indebtedness), except any such indebtedness that will be paid in full at or prior to the Closing;

(ix)hire any employees;

(x)enter into any Contract that would have been a Material Contract if it would have been in effect on the date hereof, [Omitted]

(xi)amend, modify or terminate any Material Contract or otherwise waive, release or assign any material rights, Claims or benefits of Seller or the Company under any Material Contract, [Omitted]

(xii) enter into any derivative, option, hedge or futures contracts;

(xiii)make or commit to any operation reasonably anticipated by Seller to require future capital expenditures by the Company in excess of [Omitted], individually, and [Omitted], in the aggregate;

(xiv) grant or create any preferential right to purchase or restrictions or required third party consents applicable to the Company Assets [Omitted] or the transactions contemplated by this Agreement;

(xv)make acreage acquisitions;

(xvi)abandon wells, dismantle or decommission material facilities, close pits and restore the surface of such wells, facilities, and pits, except as required by applicable Laws or Contracts; or

(xvii)agree, whether in writing or otherwise, to do any of the foregoing.

[Omitted]

6.2Transferred and Terminated Contracts»

.  On or before the Closing Date, Seller shall cause (a) each of the Contracts listed in Schedule 6.2(a) to be assigned and transferred to, and assumed by, the Company and (b) each of the Hedge Contracts, [Omitted], and the Contracts listed in Schedule 6.2(b) to be terminated.

6.3Access and Title Examination»

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(a)Access.  From June 8, 2011 through the Closing, Seller shall afford to Buyer and its authorized Representatives (i) reasonable access, during normal business hours and in such manner as not to unreasonably interfere with normal operation of the Company’s business, to the properties, books, contracts, and records of Seller and the Company and to the appropriate officers and employees of Affiliates of Seller and the Company and shall furnish such authorized Representatives with all financial and operating data and other information concerning the affairs of Seller and the Company as Buyer and such Representatives may reasonably request and (ii) such access as is contemplated by the Interim Operations Plan.  Seller shall have the right to have a Representative present at all times during any such inspections, interviews, and examinations.  Additionally, Buyer shall hold in confidence all such information on the terms and subject to the conditions contained in the Confidentiality Agreement.  Notwithstanding the foregoing, Buyer shall have no right of access to, and Seller shall have no obligation to provide to Buyer, information relating to: (i) bids received from others in connection with the transactions contemplated by this Agreement (or similar transactions) and information and analyses (including financial analyses) relating to such bids; (ii) any information the disclosure of which would jeopardize any privilege available to Seller or the Company relating to such information or would cause Seller or the Company to breach a confidentiality obligation; or (iii) any information the disclosure of which would result in a violation of Law.  Further, Buyer shall have no right to perform or conduct any environmental sampling or other invasive environmental investigation on or about any of the Assets without the prior written consent of Seller.All requests for information made under this Section 6.3(a) shall be directed to the Person designated by Seller in a Notice delivered to Buyer, and all such information provided shall be subject to the Confidentiality Agreement.

(b)Title Review.  Buyer shall have the right to examine the title to the Company Assets in accordance with the procedures in Exhibit B.

(c)Indemnity.  Buyer shall indemnify the Seller Indemnified Parties and their Representatives from and against Losses arising out of or in connection with any site visits or inspections of the Company Assets or any other properties of any Seller Indemnified Party by Buyer and its Representatives, even if caused by the sole, joint, and/or concurrent negligence, strict liability, or other fault (except for the gross negligence or willful misconduct) of the Seller Indemnified Parties.

6.4Third Party Approvals»

.  Buyer and Seller shall (and shall each cause their respective Affiliates to) use reasonable efforts to obtain all material consents and approvals of third parties that any of Buyer, Seller, or their Affiliates are required to obtain to consummate the transactions contemplated hereby.

6.5Regulatory Filings »

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(a)HSR Filing.  Promptly, and in any event within fifteen (15) Business Days after the date hereof, the Parties shall make filings required of Buyer, Seller, and the Company to obtain expiration or early termination of the waiting period under the HSR Act in respect of the transactions contemplated hereunder.  The filing fees required under the HSR Act shall be at Buyer’s sole cost and expense.

(b)HSR Actions.  From the date of this Agreement until the Closing, the Parties shall:

(i)comply, as promptly as is reasonably practicable, with any requests received by such Party or any of its Affiliates under the HSR Act and any other Laws for additional information, documents or other materials.

(ii)cooperate with the other Party and furnish all information in such Party’s possession that is necessary in connection with such other Party’s filings;

(iii)promptly inform the other Party of any communication from or to, and any proposed understanding or agreement with, any Governmental Authority in respect of such filings;

(iv)consult and cooperate with the other Party in connection with any analyses, appearances, presentations, memoranda, briefs, arguments and opinions made or submitted by or on behalf of any Party in connection with all meetings, actions and proceedings with Governmental Authorities relating to such filings;

(v)use reasonable best efforts to cause the expiration of the notice or waiting periods under the HSR Act and, if applicable, any other Laws with respect to the transactions contemplated by this Agreement as promptly as is reasonably practicable;

(vi)use reasonable best efforts to resolve any objections as may be asserted by any Governmental Authority with respect to the transactions contemplated by this Agreement (but Seller and Company shall not be required to agree to any undertaking or restriction that would take effect prior to, or not be conditioned upon, consummation of the Closing); and

(vii)use reasonable best efforts to contest and resist any action or proceeding instituted (or threatened in writing to be instituted) by any Governmental Authority challenging the transactions contemplated by this Agreement as in violation of any Law.

(c)Notice.  If a Party intends to participate in any meeting with any Governmental Authority with respect to such filings, it shall give the other Party reasonable prior Notice of such meeting and if commercially practicable, an opportunity to attend such meeting.

6.6Books and Records»

  From and after the Closing:

(a)Seller agrees to use commercially reasonable efforts to deliver to Buyer at or as soon as practicable after the Closing, to the extent permitted by applicable Laws and Contracts, all of the historical books and records of the Company (the “Company Records”), including all data, information, software, books, files, and records of the Company, including production records, operating records, correspondence, Tax Returns (other than Tax Returns relating to income or Texas franchise Taxes) and records, lease records, well logs and other records; prospect files; title records (including abstracts of title, title opinions and memoranda, and title curative documents related to the Company Assets); contract files; and geological and seismic data (including interpretive data), maps, electric logs, core data, pressure data and decline curves.

(b)Seller may retain a copy of any or all of the data room materials and the Company Records.

(c)Buyer shall preserve and keep a copy of all data room materials and the Company Records in Buyer’s possession for a period of at least seven (7) years after the Closing Date.  After such seven (7) year period, before Buyer shall dispose of any such data room materials or Company Records, Buyer shall give Seller at least ninety (90) days’ Notice to such effect, and Seller shall be given an opportunity, at its cost and expense, to remove and retain all or any part of such data room materials and Company Records as Seller may select.  Buyer shall provide to Seller, at no cost or expense to Seller, full access to such data room materials and Company Records as remain in Buyer’s possession and full access to the properties and employees of Buyer and the Company in connection with matters relating to the business or operations of the Company on or before the Closing Date and any disputes relating to this Agreement.

6.7Use of Hilcorp Marks»

.  Hilcorp Marks will appear on some of the Company Assets, including signage on the Company Assets.  Buyer acknowledges and agrees that it obtains no right, title, interest, license, or any other right whatsoever to use the Hilcorp Marks.  Buyer shall, within ninety (90) days after the Closing Date, remove the Hilcorp Marks from the Company Assets, including signage, and provide written verification thereof to Seller promptly after completing such removal.  Buyer agrees never to challenge Seller’s (or its Affiliates’) ownership of the Hilcorp Marks or any application for registration thereof or any registration thereof or any rights of Seller or its Affiliates therein as a result, directly or indirectly, of its ownership of the Company.  Buyer will not do any business or offer any goods or services under the Hilcorp Marks.  Buyer will not send, or cause to be sent, any correspondence or other materials to any Person on any stationery that contains any Hilcorp Marks or otherwise operate the Company in any manner which would or might reasonably be expected to confuse any Person into believing that Buyer has any right, title, interest, or license to use the Hilcorp Marks.  Promptly after Closing, Buyer shall change the name of the Company to remove (and not use) the Hilcorp Marks.

6.8Insurance»

  During the Restricted Period, Buyer and Seller shall cooperate and coordinate to ensure that the insurance policies currently maintained by, or on behalf of, the Company, including the policies set forth on Schedule 4.12, remain in full force and effect (a) throughout the Restricted Period, and (b) following Closing to the extent necessary to satisfy any insurable liabilities in respect of the period prior to Closing that remain with the Company.  Promptly after signing, Seller shall use its reasonable best efforts to name Buyer as an additional insured under the policies set forth on Schedule 4.12.  In addition, during the Restricted Period, Seller shall, and Seller shall cause the Company to, use its commercially reasonable efforts to notice and pursue claims that the Company is entitled to pursue under the policies set forth on Schedule 4.12.  Subject to the transitional insurance coverage arrangements that may be agreed upon between Buyer and Seller, at Closing Seller shall be entitled to terminate or modify the insurance policies described in Schedule 4.12 to exclude coverage of the Company, subject to Buyer’s right to purchase an extended notice endorsement (at Buyer’s cost) under the policies, and Buyer will obtain its own insurance coverage with respect to the Company, except with respect to the Director’s and Officer’s insurance policies shown in Schedule 4.12, which shall not be terminated by Seller unless requested by Buyer.  Further, after Closing, upon reasonable prior written notice from Buyer, Seller will (and will cause its Affiliates to) as reasonably requested by Buyer take all reasonable actions to notice and pursue any claims under the insurance policies currently maintained by, or on behalf of, the Company, including the policies described in Schedule 4.12 (and Buyer shall provide Seller with its reasonable cooperation in connection with such actions) to allow Buyer to benefit from any insurance proceeds payable to the Company as a named insured under such insurance policies.  Buyer shall reimburse Seller and its Affiliates for all costs and expenses to notice and pursue the claims under preceding sentence.

6.9Tag Along Rights»

  Buyer acknowledges and recognizes that certain Company Assets are burdened by the tag along rights described in Schedule 6.9 (the “Tag Along Rights”) which may provide the Person identified therein certain rights to sell such Person’s interests in such Company Assets (the “Tag Along Interests”) in connection with the consummation of the transactions contemplated hereunder.  On or before Closing, if applicable to the consummation of the transactions contemplated hereunder, Buyer agrees to comply with such Tag Along Rights and make an offer to purchase the Tag Along Interests on the terms provided therein, and if such offer is accepted by such Person, to purchase such Tag Along Interests and take such other actions as are necessary to comply with, or to cause the Company to comply with, such Tag Along Rights.

6.10Company»

.  Within the period ending two (2) years after the Closing Date, Buyer will not liquidate, dissolve, merge, or consolidate the Company.

6.11Company Indebtedness»

  In connection with the Closing, Seller shall cause the Company to negotiate and obtain payoff letters with respect to the Company Indebtedness (the “Payoff Letters”).  The Payoff Letters shall (i) indicate the total amount required to be paid to fully satisfy all principal, interest, prepayment premiums, penalties, breakage costs or similar obligations (other than ordinary course and contingent indemnification obligations) related to the Company Indebtedness (the “Payoff Amount”), (ii) state that all Liens in connection therewith relating to the assets of the Company shall be, upon the payment of the Payoff Amount on the Closing Date, released and (iii) authorize the Company to file UCC-3 termination statements and mortgage releases in all applicable jurisdictions to evidence the release and termination of the Company Indebtedness. Seller shall cause the Company to deliver all notices and take all other actions necessary to facilitate the termination of obligations and commitments under the Company Indebtedness, the repayment in full of all obligations then outstanding thereunder, and the release of all Liens in connection therewith on the Closing Date.

6.12Further Assurances»

  Subject to the terms and conditions of this Agreement, each Party will use its reasonable best efforts to take, or cause to be taken, all actions and to do, or cause to be done, all things necessary or desirable, under applicable Law or otherwise, to consummate the transactions contemplated by this Agreement.  The Parties agree to, and Seller, prior to the Closing, and Buyer, after the Closing, agree to cause the Company to, execute and deliver such other documents, certificates, agreements and other writings and to take such other actions as may be necessary or desirable in order to consummate or implement expeditiously the transactions contemplated by this Agreement in accordance with the terms hereof.

6.13Fees and Expenses»

  Except as otherwise provided in this Agreement, all fees and expenses, including fees and expenses of counsel, financial advisors, and accountants, incurred in connection with this Agreement and the transactions contemplated hereby shall be paid by the Party incurring such fee or expense.  For the avoidance of doubt, the Company shall not bear any costs or reimburse Seller for any fees and expenses incurred in connection with this Agreement or the transactions contemplated hereby.

6.14Continuation of Operatorship»

  Seller shall use reasonable best efforts to assist Buyer in transferring operatorship under each applicable operating agreement from HEC to the Company at Closing, but Seller is providing no assurance to Buyer that the Company or the Buyer will become the operator of any or all of the Company Assets at Closing.  As soon as practicable following the Closing, Buyer shall make such filings with the applicable Governmental Authorities as may be required to change the record operator of such Company Assets.

6.15Cooperation with Respect to Financial Statements»

.  During the Restricted Period and after the Closing, Seller shall (and shall cause the Company during the Restricted Period to) provide such reasonable cooperation as may be requested by Buyer with respect to modifications to the Financial Statements and preparation of such other financial information in such form and for such periods as may be required pursuant to the requirements of Regulation S-X of the SEC or other applicable U.S. federal securities Laws relating to Buyer’s acquisition of the Interests.  Any such modifications shall be made, and any such cooperation shall be provided, at Buyer’s expense, including reimbursement for reasonable costs of HEC’s employees and out-of-pocket expenses.

6.16Replacement of Bonds, Letters of Credit, Guarantees, and Security Deposits»

(a)The Parties understand that none of the bonds, letters of credit, guarantees and security deposits, if any, posted by the Company or by Seller on behalf of the Company with any Governmental Authority or third Person and relating to the Company or the Company Assets are to be transferred to Buyer.

(b)On or before the Closing Date, Buyer shall use commercially reasonable efforts to obtain, or cause to be obtained in the name of the Company or Buyer, replacements for such bonds, letters of credit, guarantees and security deposits listed on Schedule 4.15, and shall cause, effective as of the Closing Date, the cancellation or return to Seller of the bonds, letters of credit, guarantees and security deposits posted (or supported) by Seller with respect to the Company or the Company Assets.

(c)In the case of clause (b), Buyer may also provide evidence that such replacements are not necessary as a result of existing bonds, letters of credit, guarantees or security deposits that Buyer has previously posted as long as such existing bonds, letters of credit, guarantees or security deposits are adequate to secure the release of those posted (or supported) by Seller.

6.17Data Transfer»

  After the date hereof, the Parties and any consultants designated by Buyer shall work together to determine the most efficient manner to transfer data relating to the Company and the Company Assets to Buyer, including the delivery of the property records, information, and data set forth on Schedule 6.17.  Seller shall use its reasonable efforts to transfer such data to Buyer during the time frames set forth therein.

6.18Restricted Area »

  Neither HEC nor any of its Affiliates shall, for a period of eighteen (18) months from and after the date hereof, directly or indirectly negotiate to acquire, acquire, or cause any other party to acquire an oil and gas lease or an interest in an oil and gas lease (including but not limited to any “top lease”) covering any of the same Lands within Atascosa, Bee, DeWitt, Gonzales, Karnes, Lavaca, Live Oak and McMullen Counties, Texas (i) in which the Company presently holds title to a Lease or other interest that is of record in the respective County courthouse, (ii) in which the Company presently operates or maintains a Well, or (iii) which are pooled with or directly contiguous to any such Lands as described in clauses (i) and (ii) above.  It is understood and agreed that the restrictions in this Section 6.18 apply only to HEC’s and its Affiliates’ leasing from mineral owners either directly or by third-party land brokerage firms working on behalf of HEC or its Affiliates, and shall not be construed to (x) preclude HEC or its Affiliates from purchasing any leasehold or royalty interests in the area described in this Section 6.18 from a third party engaged in oil and gas exploration and production, or through the acquisition of a company that holds such interests or (y) apply to any interests acquired or held by Seller and its Affiliates under or as contemplated in the [Omitted].

6.19Non-Solicitation»

  Buyer agrees that, for a period beginning on the date of this Agreement and ending on the first anniversary of the Closing Date, it will not, and will cause its Affiliates not to, directly or indirectly, solicit the employment of (including by contracting through an independent contractor, consultant, or other third party) or hire (including as a consultant) any of the employees of the Seller or its Affiliates, except as permitted below, without the prior written consent of Seller.  No later than thirty (30) days prior to the Closing Date, Buyer may present a written list to Seller of the field employees of Seller and its Affiliates involved with the operation of the Company Assets that Buyer would like Seller to make available for employment interviews with Buyer (“Selected Employees”).  Within ten (10) days of receiving Buyer’s request, Seller shall identify to Buyer in writing those Selected Employees that Buyer may interview, solicit for hire, and hire (“Excepted Employees”).  Seller agrees to make the Excepted Employees available to interview with Buyer prior to Closing.  Any Excepted Employee who does not accept Buyer’s offer of employment within ten (10) days after Closing shall thereafter cease to be an Excepted Employee and any further or subsequent solicitation of such employee or hiring of such employee shall be subject to the conditions and restrictions of this Section 6.19. The restrictions above shall not apply to (i) a general advertisement of employment opportunities by Buyer or its Affiliates not specifically directed at any employee of Seller and its Affiliates or (ii) any individual whose employment with Seller and its Affiliates was terminated by Seller and its Affiliates or has not worked for Seller and its Affiliates for at least six (6) months prior to such individual being solicited or hired by Buyer or its Affiliates.

6.20April 2011 Balance Sheet»

.  On or before July 1, 2011, Seller shall deliver to Buyer the unaudited interim balance sheet of the Company as of April 30, 2011 prepared in accordance with GAAP and the Company's past practices, consistently applied.

[Omitted].

Article 7.

Tax Matters

7.1Responsibility for Filing Tax Returns and Paying Taxes»

(a)Seller shall file all Tax Returns required to be filed by or with respect to the Company for a Pre-Closing Tax Period.  Buyer shall file all other Tax Returns required to be filed by or with respect to the Company.

(b)Subject to the limitations of Section 7.6, Seller shall pay and, except to the extent Taxes have been taken into account by the Parties in the determination of the Purchase Price, as adjusted, shall indemnify and hold harmless Buyer and its Affiliates from and against all Taxes with respect to the Company or the Company Assets and attributable to any Pre-Closing Tax Period or portion of any Straddle Period prior to and including (i) the Closing Date, in the case of Specified Taxes, and (ii) April 30, 2011, in the case of all other Taxes.  Buyer shall pay all other Taxes owed with respect to the Company or any of the Company Assets.

(c)For purposes of this Agreement, liability for Taxes with respect to the Company or the Company Assets with respect to any Straddle Period shall be apportioned as follows:  Property and similar ad valorem Taxes shall be apportioned on a ratable daily basis, and all other Taxes, including but not limited to income and Texas franchise Taxes, shall be apportioned based on an interim closing of the books of the Company as of the end of the Closing Date, or April 30, 2011, as applicable.  Buyer and Seller shall each timely provide the other with all information and cooperation reasonably requested by the other to prepare any Tax Returnrelating to the Company, the Company Assets or the transactions contemplated by this Agreement.

7.2Responsibility for Tax Audits»

  Seller shall control any Tax Audit relating to the Company or the Company Assets for any Pre-Closing Tax Period with respect to Taxes for which Seller is liable pursuant to Section 7.1, and Buyer shall control any other Tax Audit relating to the Company or the Company Assets; provided, however, that if a Tax Audit relates to Taxes for which both Parties could be liable under this Agreement, to the extent practicable, the Tax items with respect to such Tax Audit will be distinguished and each Party will have the option to control the defense and settlement of those Taxes for which it could be so liable, but if any Tax item cannot be identified as being a liability of only one Party or cannot be separated from a Tax item for which the other Party is liable, Buyer, at its expense, shall have the option to control the defense and settlement of the Tax Audit, provided that Buyer shall keep Seller notified of any developments in such Tax Audit and Seller shall have the right to participate in such Tax Audit at its own expense; and provided further that no such matter shall be settled without the written consent of Seller, not to be unreasonably withheld, delayed or conditioned.  Buyer and Seller shall each timely provide the other with all information and cooperation reasonably requested to conduct a Tax Audit with respect to Taxesrelating to the Company, the Company Assets or the transactions contemplated by this Agreement.  Each Party shall provide the other with notice of any pending or threatened Tax Audits that could adversely affect the other.

7.3Tax Refunds»

  The Parties shall be entitled to any refund with respect to Taxes for which the Party is responsible pursuant to Section 7.1 or 7.4.  If a Party receives a refund to which the other Party is entitled, the Party receiving the refund shall pay it to the Party entitled to the refund within thirty (30) Business Days after receipt.

7.4Transfer Taxes»

  Buyer shall be responsible for and indemnify Seller against any state or local transfer, sales, use, stamp, registration or other similar Taxes resulting from the transactions contemplated by this Agreement.  The Parties shall reasonably cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such Taxes.

7.5Tax Treatment of Indemnities»

  Any indemnity paid by a Party to another Party pursuant to this Article 7 or Article 9 shall be treated for federal, state and local income Tax purposes, as an adjustment to the Purchase Price, unless otherwise required by Law or as agreed by the Parties.

7.6Survival and Conflict.»

[Omitted]

Article 8.

Conditions to Closing

8.1Conditions to Obligations of Buyer to Closing»

  The obligation of Buyer to consummate the transactions contemplated by this Agreement at the Closing is subject to the satisfaction of the following conditions.

(a)Representations, Warranties, and Covenants.  (i) The representations and warranties of Seller made in this Agreement (disregarding all materiality and Material Adverse Effect qualifications contained therein) will be true and correct as of the date of this Agreement and as of the Closing Date as if made on the Closing Date (except to the extent that such representations and warranties expressly relate to an earlier date, in which case such representations and warranties shall have been true and correct as of such earlier date), except where all such breaches taken collectively would not reasonably be expected to have a Material Adverse Effect, (ii) Seller shall have performed or complied with in all material respects all of the covenants and agreements required by this Agreement to be performed or complied with by Seller on or before the Closing and (iii) Buyer shall have received a certificate of an executive officer of Seller, dated the Closing Date, to such effect.

(b)HSR Approval.  The waiting period under the HSR Act applicable to the consummation of the sale and purchase of the Interests contemplated hereby shall have expired or been terminated.

(c)No Injunction.  No provision of any applicable Law and no Order will be in effect that prohibits or makes illegal the consummation of the Closing.

(d)Resignations of Officers and Directors.  The Company shall have received resignations (or evidence of removal) of each officer or director of the Company effective as of the Closing.

(e)Assignment Agreement, Indemnity Deposit Escrow Agreement, and Title Defect Deposit Escrow Agreement.  Seller shall have deliveredits duly executed signature page counterparts to the Assignment Agreement, the Indemnity Deposit Escrow Agreement, and the Title Defect Deposit Escrow Agreement, if required, to Buyer.

(f)Secretary’s Certificate.  Seller shall have delivered a secretary’s certificate certifying the Organizational Documents of the Company and including an incumbency certificate.

(g)Certification of Non-Foreign Status.  Seller shall have delivered a certification of its non-foreign status in accordance with U.S. Treasury Regulation Section 1.1445-2(b)(2).

(h)Release of Liens.  Seller shall have secured the release of all Liens on Company Assets in connection with the payoff of the Company Indebtedness.

8.2Conditions to the Obligations of Seller to Closing»

  The obligation of Seller to consummate the transactions contemplated by this Agreement at the Closing is subject to the satisfaction of the following conditions.

(a)Representations, Warranties, and Covenants.  (i) The representations and warranties of Buyer made in this Agreement (disregarding all materiality qualifications contained therein) will be true and correct in all material respects as of the date of this Agreement and as of the Closing Date as if made on the Closing Date (except to the extent that such representations and warranties expressly relate to an earlier date, in which case such representations and warranties shall have been true and correct as of such earlier date), (ii) Buyer shall have performed or complied with in all material respects all of the covenants and agreements required by this Agreement to be performed or complied with by Buyer on or before the Closing and (iii) Buyer shall have received a certificate of an executive officer of Seller, dated the Closing Date, to such effect.

(b)HSR Approval.  The waiting period under the HSR Act applicable to the consummation of the sale and purchase of the Interests contemplated hereby shall have expired or been terminated.

(c)No Injunction.  No provision of any applicable Law and no Order will be in effect that prohibits or makes illegal the consummation of the Closing.

(d)Assignment Agreement, Indemnity Deposit Escrow Agreement, and Title Defect Deposit Escrow Agreement.  Buyer shall have deliveredits duly executed signature page counterparts to the Assignment Agreement, the Indemnity Deposit Escrow Agreement, and the Title Defect Deposit Escrow Agreement, if required, to Seller.

Article 9.

Indemnification and Waivers

9.1Indemnification»

[Omitted]

9.2Limitations on Liability»

[Omitted]

9.3Procedures»

  Claims for indemnification under this Agreement shall be asserted and resolved as follows.

(a)Third Party Claim.  If any Person entitled to seek indemnification under Section 9.1 (an “Indemnified Party”) receives Notice of the assertion or commencement of any claim asserted against an Indemnified Party by a third party (“Third Party Claim”) in respect of any matter that is subject to indemnification under Section 9.1, the Indemnified Party shall promptly (i) notify the Party obligated to the Indemnified Party pursuant to Section 9.1 above, (the “Indemnifying Party”) of the Third Party Claim and (ii) transmit to the Indemnifying Party Notice (“Claim Notice”) describing in reasonable detail the nature of the Third Party Claim, a copy of all papers served with respect to such claim (if any), the Indemnified Party’s best estimate of the amount of Losses attributable to the Third Party Claim and the basis of the Indemnified Party’s request for indemnification under this Agreement.  Failure to timely provide such Claim Notice shall not affect the right of the Indemnified Party’s indemnification hereunder, except to the extent the Indemnifying Party is prejudiced by such delay or omission.

(b)Indemnifying Party.  Except with respect to Tax Audits described in Section 7.2, the Indemnifying Party shall have the right to defend the Indemnified Party against such Third Party Claim.  If the Indemnifying Party notifies the Indemnified Party that the Indemnifying Party elects to assume the defense of the Third Party Claim (such election to be without prejudice to the right of the Indemnified Party to dispute whether such claim is an identifiable Loss under this Article 9), then the Indemnifying Party shall have the right to defend such Third Party Claim with counsel selected by the Indemnifying Party (who shall be reasonably satisfactory to the Indemnified Party), by all appropriate proceedings, to a final conclusion or settlement at the discretion of the Indemnifying Party in accordance with this Section 9.3(b).  The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof; provided that the Indemnifying Party shall not enter into any settlement agreement or consent to the entry of any judgment with respect thereto without the written consent of the Indemnified Party (which consent shall not be unreasonably withheld, conditioned, or delayed) that (i) does not result in a final resolution of the Indemnified Parties’ liability to the third party with respect to the claim (including, in the case of a settlement, an unconditional written release of the Indemnified Party from all further liability in respect of such claim) or (ii) may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).  If requested by the Indemnifying Party, the Indemnified Party agrees, at the sole cost and expense of the Indemnifying Party, to cooperate with the Indemnifying Party and its counsel in contesting any Third Party Claim which the Indemnifying Party elects to contest pursuant to this Section 9.3(b), including the making of any related counterclaim against the Person asserting the Third Party Claim or any cross complaint against any Person.  The Indemnified Party may participate in, but not control, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 9.3(b), and the Indemnified Party shall bear its own costs and expenses with respect to such participation.

(c)Indemnified Party.  Except with respect to Tax Audits described in Section 7.2, if the Indemnifying Party does not notify the Indemnified Party that the Indemnifying Party elects to defend the Indemnified Party pursuant to Section 9.3(b), then the Indemnified Party shall have the right to defend, and be reimbursed for its reasonable cost and expense (but only if the Indemnified Party is actually entitled to indemnification hereunder) in regard to the Third Party Claim with counsel selected by the Indemnified Party (who shall be reasonably satisfactory to the Indemnifying Party), by all appropriate proceedings, which proceedings shall be prosecuted diligently by the Indemnified Party.  In such circumstances, the Indemnified Party shall defend any such Third Party Claim in good faith and have full control of such defense and proceedings; provided, however, that the Indemnified Party may not enter into any compromise or settlement of such Third Party Claim if indemnification is to be sought hereunder, without the Indemnifying Party’s consent (which consent shall not be unreasonably withheld, conditioned or delayed).  The Indemnifying Party may participate in, but not control, any defense or settlement controlled by the Indemnified Party pursuant to this Section 9.3(c), and the Indemnifying Party shall bear its own costs and expenses with respect to such participation.

(d)Direct Claim.  Any claim by an Indemnified Party on account of Losses that does not result from a Third Party Claim (a “Direct Claim”) will be asserted by giving the Indemnifying Party reasonably prompt Notice thereof, but in any event not later than thirty (30) days after the Indemnified Party becomes aware of the events that gave rise to such Direct Claim.  Such Notice by the Indemnified Party will describe the Direct Claim in reasonable detail, will include copies of all available material written evidence thereof and will indicate the estimated amount, if reasonably practicable, of damages that has been or may be sustained by the Indemnified Party.  The Indemnifying Party will have a period of ten (10) Business Days within which to respond in writing to such Direct Claim.  If the Indemnifying Party does not so respond within such ten (10) Business Day period, the Indemnifying Party will be deemed to have rejected such Direct Claim, in which event the Indemnified Party will be free to pursue such remedies as may be available to the Indemnified Party on the terms and subject to the provisions of this Agreement.

9.4Waiver of Consequential Damages»

  With respect to any and all Losses for which indemnification may be available hereunder, no Indemnifying Parties shall have any liability for any consequential, indirect, punitive, exemplary, and special damages with respect to any claim for which an Indemnifying Party may have liability pursuant to this Agreement; provided, however, that this waiver shall not apply to the extent such consequential, indirect, punitive, exemplary or special damages are awarded in a Proceeding brought or asserted by a third party against an Indemnified Party.

9.5Waivers and Disclaimers»

(a)Title Matters.  The only representations, warranties, or covenants being made by Seller with respect to the Company’s title to the Company Assets are in Exhibit B and all other representations, warranties, or covenants of title of any kind or nature, either express, implied, or statutory, are hereby waived and disclaimed in their entirety.

(b)No Reliance.  Buyer has reviewed and has access to all contracts, documents, records, and information which it has desired to review in connection with its decision to enter into this Agreement, and to consummate the transactions contemplated hereby.  Buyer has not relied upon any representation, warranty, statement, advice, document, projection, or other information of any type provided by Seller, or its Affiliates, or any of their Representatives, except for the representations and warranties of Seller set forth in this Agreement.  In deciding to enter into this Agreement, and to consummate the transactions contemplated hereby, Buyer has relied solely upon its own knowledge, investigation, and analysis (and that of its Representatives) and not on any disclosure or representation made by, or any duty to disclose on the part of, Seller or its Affiliates, or any of their Representatives, other than the representations and warranties of Seller set forth in this Agreement.

(c)Limited Duties.  Any and all duties and obligations which either Party may have to the other Party with respect to or in connection with the Interests, the Company Assets, this Agreement, or the transactions contemplated hereby are limited to those in this Agreement.  The Parties do not intend (i) that the duties or obligations of either Party, or the rights of either Party, shall be expanded beyond the terms of this Agreement on the basis of any legal or equitable principle or on any other basis whatsoever or (ii) that any equitable or legal principle or any implied obligation of good faith or fair dealing or any other matter requires either Party to incur, suffer, or perform any act, condition, or obligation contrary to the terms of this Agreement and that it would be unfair, and that they do not intend, to increase any of the obligations of any Party under this Agreement on the basis of any implied obligation or otherwise.

(d)Defects.  The Interests and the Company Assets are being conveyed and assigned to and accepted by Buyer in their “as is, where is” condition and state of repair, and with all faults and defects, without, subject to the exception below, any representation, warranty, or covenant of any kind or nature, express, implied, or statutory, including, but not limited to, warranties of marketability, quality, condition, conformity to samples, merchantability, and/or fitness for a particular purpose, all of which are expressly disclaimed by Seller and waived by Buyer, except for the representations and warranties of Seller set forth in this Agreement.  Buyer recognizes that the Company Assets have been used for oil and gas drilling, production, gathering, pipeline, transportation, storage, and related operations.  Physical changes in the Company Assets and in the lands included therein may have occurred as a result of such uses.  The Company Assets also may include buried pipelines and other equipment, the locations of which may not be known by Seller or readily apparent by a physical inspection of the Company Assets.  It is understood and agreed that Buyer shall have inspected prior to Closing (or shall be deemed to have waived its right to inspect) the leases, equipment, pipelines, and the associated premises included in the Company Assets and satisfied itself as to their physical and environmental condition, both surface and subsurface, and that Buyer shall accept all of the same in their “as is, where is” condition and state of repair, and with all faults and defects, including, but not limited to, the presence of naturally occurring radioactive material and man-made material fibers, subject to the representations and warranties of Seller set forth in this Agreement.

(e)Additional Disclaimers.  Seller makes no representation, covenant, or warranty, express, implied, or statutory, (i) as to the accuracy or completeness of any data or records delivered to Buyer with respect to the Company or the Company Assets, or (ii) concerning the quality or quantity of hydrocarbon reserves, if any, attributable to the Company Assets, or the ability of the Company Assets to produce hydrocarbons, or the product prices which the Company is or will be entitled to receive from the sale of any such hydrocarbons.

9.6Exclusive Remedy and Release»

  The indemnification and remedies set forth in Section 6.3, this Article 9, and Exhibit B shall constitute the sole and exclusive post-Closing remedies of the Parties with respect to any breach of representation or warranty or non-performance of any covenant or agreement contained in this Agreement.  Except as provided in this Agreement, if the Closing occurs, each Party hereby waives, releases, acquits, and forever discharges the other Party, its partners, their Affiliates, and its and their officers, directors, members, managers, partners, employees, or agents, or any other Person acting on behalf of such other Party, of and from any and all claims, actions, causes of action, demands, rights, damages, costs, expenses, Losses, or compensation whatsoever, whether direct or indirect, known or unknown, foreseen or unforeseen, which Buyer or the Company or Seller, as applicable, may have or which may arise in the future directly or indirectly arising out of the transactions contemplated hereby, including any of the foregoing that is from or relating to the possession, use, handling, management, disposal, investigation, remediation, cleanup, or release of any Constituents of Concern or any Environmental Law applicable thereto.

Article 10.

Termination

10.1Termination»

  At any time prior to the Closing, this Agreement may be terminated and the transactions contemplated hereby abandoned:

(a)by the mutual written consent of Buyer and Seller;

(b)by Buyer, upon Notice to Seller, if there has been a material breach by Seller of any representation, warranty, or covenant contained in this Agreement that has prevented the satisfaction of any condition to the obligations of Buyer at the Closing and, if such breach is of a character that it is capable of being cured, such breach has not been cured by Seller within thirty (30) days after Notice thereof from Buyer;

(c)by Seller, upon Notice to Buyer, if there has been a material breach by Buyer of any representation, warranty, or covenant contained in this Agreement that has prevented the satisfaction of any condition to the obligations of Seller at the Closing and, if such breach is of a character that it is capable of being cured, such breach has not been cured by Buyer within thirty (30) days after Notice thereof from Seller;

(d)by either Buyer or Seller, upon Notice to the other Party, if any Governmental Authority having competent jurisdiction has issued a final, non-appealable Order, decree, ruling or injunction (other than a temporary restraining order) or taken any other action permanently restraining, enjoining or otherwise prohibiting the transactions contemplated by this Agreement and such injunction shall have become final and non-appealable; or

(e)by either Buyer or Seller, upon Notice to the other Party, if the transactions contemplated at the Closing have not been consummated by February 29, 2012, provided that neither Buyer nor Seller will be entitled to terminate this Agreement pursuant to this Section 10.1(e) if such Person’s breach of this Agreement has prevented the consummation of the transactions contemplated by this Agreement; or

(f)by Seller, upon Notice to Buyer, if the sum of all Title Defect Amounts contained in any Defect Notice less the sum of all Title Benefit Amounts claimed by Seller is equal to or greater than [Omitted] of the Base Purchase Price; or

(g)by Buyer, upon Notice to Seller, if the sum of all Title Defect Amounts contained in any Defect Notice and determined to be valid less the sum of all Title Benefit Amounts claimed by Seller and determined to be valid is equal to or greater than [Omitted] of the Base Purchase Price; provided that for purposes of determining the validity of the Title Defect Amounts and the Title Benefit Amounts for this Section 10.1(g), (i) Seller shall have a Cure Period ending on October 31, 2011, (ii) if there are any unresolved Title Defects, Title Defect Amounts, Title Benefits, or Title Benefit Amounts at the end of the Cure Period, the Parties shall select and engage a Title Arbitrator by November 7, 2011, (iii) the Title Arbitrator shall make its final and binding determination as to any such unresolved Title Defects, Title Defect Amounts, Title Benefits, or Title Benefit Amounts by November 28, 2011, and (iv) the Closing Date shall be postponed hereunder until December 1, 2011 (plus one additional Business Day for each Business Day that the Title Arbitrator’s determination is delayed beyond November 28, 2011).  If the Title Arbitrator determines that the sum of all valid Title Defect Amounts less the sum of all valid Title Benefit Amounts is less than [Omitted] of the Base Purchase Price, (x) the Closing shall occur as scheduled (taking into account any delay caused by the Title Arbitrator), (y) Seller shall be afforded the Cure Period provided in Section 3(d) of Exhibit B, and (z) to the extent there are no new relevant facts or circumstances, the title arbitration process that has already occurred shall not be duplicated.

10.2Effect of Termination»

  Except for this Section 10.2, Section 6.3(c), Section 9.1(d), Section 9.4 and Article 11 except for Section 11.10 (and the definitions related to any of the foregoing), this Agreement shall, upon termination hereof pursuant to Section 10.1, become of no further force or effect.  If this Agreement is terminated (i) by Seller under Section 10.1(c) or (ii) by either Party under Section 10.1(e) if at such time Seller could have terminated this Agreement under Section 10.1(c) (without regard to any cure periods contemplated therein), then, in either case, the Parties shall instruct the Escrow Agent to release to Seller the Performance Deposit and any interest accrued thereon as partial satisfaction of the damages suffered by Seller as a result of such termination, but the acceptance of the Performance Deposit by Seller shall not limit or affect Seller’s rights to pursue any other rights and remedies available to Seller in respect of such termination (including liability for breach of this Agreement prior to such termination).  If this Agreement is terminated under Section 10.1(a), (b), (d), (e) (other than as described in the prior sentence), (f) or (g) then the Parties shall instruct the Escrow Agent to release to Buyer the Performance Deposit and any interest accrued thereon, but the acceptance of the Performance Deposit by Buyer shall not limit or affect Buyer’s rights to pursue any other rights and remedies available to Buyer in respect of such termination (including liability for breach of this Agreement prior to such termination).  Nothing in this Section 10.2 will relieve any Party to this Agreement of liability for breach of this Agreement occurring prior to any termination, or for breach of any provision of this Agreement that specifically survives termination hereunder.  The Confidentiality Agreement shall not be affected by a termination of this Agreement.

Article 11.

Other Provisions

11.1Notices»

.  All notices and other communications between the Parties pursuant to this Agreement (“Notices”) shall be in writing and shall be deemed to have been duly given when (i) delivered in person, (ii) five (5) days after posting in the United States mail having been sent registered or certified mail return receipt requested, or (iii) delivered by telecopy or e-mail and promptly confirmed by delivery in person or post as aforesaid in each case if received during the recipient’s normal business hours, or at the beginning of the recipient’s next Business Day after receipt if not received during the recipient’s normal business hours, with postage prepaid, addressed as follows:

If to Buyer, to:

        Marathon Oil Company

5555 San Felipe

Houston, Texas 77056

Fax: (713) 296-4528

E-mail:spguidry@marathonoil.com

Attention: Steve Guidry

With a copy to:

Baker Botts L.L.P.

910 Louisiana Street

Houston, Texas 77002

Fax: (713) 229-2856

E-mail: hugh.tucker@bakerbotts.com

Attention: Hugh Tucker

If to Seller, to:

Hilcorp Resources Holdings, LP

c/o Hilcorp Energy Company

1201 Louisiana, Suite 1400

Houston, Texas 77002

Fax: (713) 289-2650

E-mail: bswenson@hilcorp.com

Attention: William P. Swenson

With a copy to:

Andrews Kurth LLP

600 Travis Street

Houston, Texas 77002

Fax: (713) 220-4285

E-mail: halhaltom@andrewskurth.com

moleary@andrewskurth.com

Attention: Hal Haltom and Mike O’Leary

or to such other address or addresses as the Parties may from time to time designate in writing.

11.2Assignment»

  Neither Party shall assign this Agreement or any part hereof without the prior written consent of the other Party; provided that Buyer may assign this Agreement to a non-Texas Affiliate without Seller’s consent, but any such assignment shall not relieve Buyer of any of its obligations under this Agreement or delay, impact, or otherwise adversely affect the timely consummation of the transactions contemplated hereunder.  Subject to the foregoing, this Agreement shall be binding upon and inure to the benefit of the Parties and their respective permitted successors and assigns.

11.3Rights of Third Parties»

  Except for the provisions of Article 9, which are intended to be enforceable by the Persons respectively referred to therein, nothing expressed or implied in this Agreement is intended or shall be construed to confer upon or give any Person, other than the Parties, any right or remedies under or by reason of this Agreement.

11.4Counterparts»

  This Agreement may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.  Any facsimile copies hereof or signature hereon shall, for all purposes, be deemed originals.

11.5Entire Agreement»

  This Agreement (together with the Disclosure Schedule and exhibits to this Agreement) and the Confidentiality Agreement constitute the entire agreement among the Parties and supersede any other agreements, whether written or oral, that may have been made or entered into by or among any of the Parties or any of their respective Affiliates relating to the transactions contemplated hereby.

11.6Disclosure Schedule»

  Unless the context otherwise requires, all capitalized terms used in the Disclosure Schedule shall have the respective meanings assigned in this Agreement.  No reference to or disclosure of any item or other matter in the Disclosure Schedule shall be construed as an admission or indication that such item or other matter is material or that such item or other matter is required to be referred to or disclosed in the Disclosure Schedule.  No disclosure in the Disclosure Schedule relating to any possible breach or violation of any agreement or Law shall be construed as an admission or indication that any such breach or violation exists or has actually occurred. The inclusion of any information in the Disclosure Schedule shall not be deemed to be an admission or acknowledgment by Seller, in and of itself, that such information is material to or outside the ordinary course of the business of the Company or required to be disclosed on the Disclosure Schedule.  To the extent reasonably inferable from the reference that it would qualify another representation or warranty, each disclosure in the Disclosure Schedule shall be deemed to qualify all representations and warranties of Seller notwithstanding the lack of a specific cross-reference.

11.7Amendments»

  This Agreement may be amended or modified in whole or in part, and terms and conditions may be waived, only by a duly authorized agreement in writing which makes reference to this Agreement executed by each Party.

11.8Publicity»

.  Buyer, Seller, or any of the partners of Seller may make a press release or other public communication or announcement in connection with the execution of this Agreement, provided that the Person making such release, communication, or announcement provides the other Party reasonable opportunity to review and comment on any such release, communication, or announcement.  Except for the foregoing, all press releases or other public communications of any nature whatsoever relating to the transactions contemplated by this Agreement, and the method of the release for publication thereof, shall be subject to the prior written consent of Buyer and Seller, which consent shall not be unreasonably withheld, conditioned, or delayed by such Party; provided, however, that nothing herein shall prevent a Party from publishing such press releases or other public communications as is necessary to satisfy such Party’s obligations at Law or under the rules of any stock or commodities exchange after consultation with the other Party.  In the event that a Party believes it is required to issue or make any press release or announcement, such Party shall (i) give prompt notice thereof to the other Party, (ii) allow such other Party reasonable opportunity to review and provide comments with respect to the content of such press release or announcement and (iii) use commercially reasonable efforts to incorporate any reasonable comment from any other Party prior to any release or announcement.

11.9Severability»

  If any provision of this Agreement is held invalid or unenforceable by any court of competent jurisdiction, the other provisions of this Agreement shall remain in full force and effect.  The Parties further agree that if any provision contained herein is, to any extent, held invalid or unenforceable in any respect under the Laws governing this Agreement, they shall take any actions necessary to render the remaining provisions of this Agreement valid and enforceable to the fullest extent permitted by Law and, to the extent necessary, shall amend or otherwise modify this Agreement to replace any provision contained herein that is held invalid or unenforceable with a valid and enforceable provision giving effect to the intent of the Parties to the greatest extent legally permissible.

11.10Specific Performance»

  Without limiting the effect of Section 9.6after Closing, the Parties acknowledge and agree, that prior to Closing, (i) each Party would be irreparably harmed by a breach by the other Party of any of their obligations under this Agreement and (ii) the non-breaching Party is entitled to injunctive relief, specific performance, and other equitable remedies against the breaching Party to enforce the performance by the breaching Party of its obligations under this Agreement, and the Parties hereby consent and agree to such injunctive relief, specific performance, and other equitable remedies; provided that, if Buyer is required to consummate the purchase of the Company pursuant to this Section 11.10, the Performance Deposit (together with any interest accrued thereon) shall be applied as a credit against the Closing Payment notwithstanding Buyer’s breach under this Agreement.

11.11Governing Law; Jurisdiction»

(a)Law.  This Agreement shall be governed and construed in accordance with the Laws of the State of Texas, without regard to the Laws that might be applicable under conflicts of laws principles.

(b)Forum.  The Parties agree that the appropriate, exclusive and convenient forum for any disputes between any of the Parties hereto arising out of this Agreement or the transactions contemplated hereby shall be in any state or federal court in Harris County, Texas, and each of the Parties hereto irrevocably submits to the jurisdiction of such courts solely in respect of any legal proceeding arising out of or related to this Agreement.  The Parties further agree that the Parties shall not bring suit with respect to any disputes arising out of this Agreement or the transactions contemplated hereby in any court or jurisdiction other than the above specified courts.  The Parties further agree, to the extent permitted by Law, that a final and nonappealable judgment against a Party in any action or proceeding contemplated above shall be conclusive and may be enforced in any other jurisdiction within or outside the United States by suit on the judgment, a certified or exemplified copy of which shall be conclusive evidence of the fact and amount of such judgment.  Except to the extent that a different determination or finding is mandated due to the applicable law being that of a different jurisdiction, the Parties agree that all judicial determinations or findings by a state or federal court in Harris County, Texas with respect to any matter under this Agreement shall be binding.

(c)Jurisdiction.  To the extent that any Party hereto has or hereafter may acquire any immunity from jurisdiction of any court or from any legal process (whether through service or notice, attachment prior to judgment, attachment in aid of execution, execution or otherwise) with respect to itself or its property, each such party hereby irrevocably (i) waives such immunity in respect of its obligations with respect to this Agreement, and (ii) submits to the personal jurisdiction of any court described in Section 11.11(b).

(d)Waiver.  The Parties hereto agree that they hereby irrevocably waive the right to trial by jury in any action to enforce or interpret the provisions of this Agreement.

[THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]

Purchase and Sale Agreement

5065.1

IN WITNESS WHEREOF this Agreement has been duly executed and delivered by each of the Parties as of the date first above written.

Buyer:

MARATHON OIL COMPANY

By: /s/ Clarence P. Cazalot, Jr

Clarence P. Cazalot, Jr.

President and Chief Executive Officer

Seller:

HILCORP RESOURCES HOLDINGS, LP

By:           HRES GP, LLC

its general partner

By:  /s/ Jeffery D. Hilderbrand

Jeffery D. Hildebrand

President

HEC is executing this Agreement solely for the purpose of evidencing its agreement to the obligations of HEC in Section 6.18 and for no other reason:

HILCORP ENERGY COMPANY

By: /s/ Jeffery D. Hilderbrand

Jeffery D. Hildebrand

President and Chief Executive Officer

Signature Page to

Purchase and Sale Agreement

5065.1

EX-10.4

Exhibit 10.3

AMENDMENT TO EMPLOYEE MATTERS AGREEMENT

This Amendment to Employee Matters Agreement (this “Amendment”), dated as of June 30, 2011, is by and between Marathon Oil Corporation, a Delaware corporation (“Marathon Oil” or “MRO”), and Marathon Petroleum Corporation, a Delaware corporation (“Marathon Petroleum” or “MPC”, and together with Marathon Oil, the “Parties”).

PRELIMINARY STATEMENT

WHEREAS, the Parties are parties to an Employee Matters Agreement dated as of May 25, 2011 (the “Employee Matters Agreement”; capitalized terms used but not defined in this Amendment shall have the respective meanings given such terms in the Employee Matters Agreement); and

WHEREAS, the Employee Matters Agreement contains provisions relating to adjustments to equity-based awards held by MRO Participants, MPC Participants and other grantees, which adjustments are generally designed to preserve the intrinsic values of those awards on the Distribution Date;

WHEREAS, the Parties now desire to amend the Employee Matters Agreement as provided herein, to permit an Alternative Methodology for adjusting certain equity-based awards and provide specific provisions for holders of equity-based awards who are subject to the Income Tax Act (Canada);

NOW, THEREFORE, in consideration of the premises and of the respective agreements and covenants contained in this Amendment, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be legally bound, agree as follows:

1.Section 1.1 of the Employee Matters Agreement is hereby amended to add the following new definitions:

“Adjustment Time” shall have the meaning set forth in Section 13.2(d)(ii).

“Canadian Pre-Distribution Spread” means, for purposes of Section 13.2(d)(ii) and Section 13.3(c)(ii), with respect to a Person's MRO Unvested Options or MRO Vested Options, as applicable, the product of (a) the number of shares of MRO common stock subject to such MRO Unvested Options  or MRO Vested Options immediately prior to the Adjustment Time, and (b) the excess of the MRO Pre-Distribution Stock Value over the per-share exercise price for such MRO Unvested Options or MRO Vested Options immediately prior to the Adjustment Time.

“ITA” shall have the meaning set forth in Section 13.2(d)(ii).

“Post-Distribution Spread” means, (a) for purposes of Section 13.2(d)(ii), with respect to a Person's Remaining MRO Unvested Options or MPC Unvested Options, as applicable, the product of (a) the number of shares of MRO common stock or shares of MPC common stock, as applicable, subject to such Remaining MRO Unvested Options or MPC Unvested Options, as applicable, immediately after the Adjustment Time, and (b) the excess of the MRO Post-Distribution Stock Value or MPC Post-Distribution Stock Value, as applicable, over the per-share exercise price for such Remaining MRO Unvested Options or MPC Unvested Options, as applicable, immediately after the Adjustment Time and  (b) for purposes of Section 13.3(c)(ii), with respect to a Person's Remaining MRO Vested Options and MPC Vested Options, the sum of:  (A) the product of: (w) the number of shares of MRO common stock subject to such Remaining MRO Vested Options, immediately after the Adjustment Time, and (x) the excess of the MRO Post-Distribution Stock Value over the per-share exercise price for such Remaining MRO Vested Options, immediately after the Adjustment Time, and (B) the product of: (y) the number of shares of MPC common stock subject to such MPC Vested Options, immediately after the Adjustment Time, and (x) the excess of the MPC Post-Distribution Stock Value over the per-share exercise price for such MPC Vested Options, immediately after the Adjustment Time.

“Post-Distribution Value” means, with respect to a Person's MRO RSUs or MPC RSUs, as applicable, the product of (a) the number of shares of MRO common stock or shares of MPC common stock, as applicable, subject to such MRO RSUs or MPC RSUs, as applicable, immediately after the Adjustment Time, and (b) the MRO Post-Distribution Stock Value or MPC Post-Distribution Stock Value, as applicable.

“Pre-Distribution Value” means, with respect to a Person's MRO RSUs, the product of (a) the number of shares of MRO common stock subject to such MRO RSUs immediately prior to the Adjustment Time, and (b) the MRO Pre-Distribution Stock Value.

2.           A new Section 13.2(d) is added, as follows:

(d)           Special Rules.

(i)Alternative Conversion Methodology.  Notwithstanding the other provisions of this Section 13.2 respecting the conversion  of each MRO Unvested Option into a Remaining MRO Unvested Option or an MPC Unvested Option, the conversion for administrative convenience may be effected using any other reasonable methodology (an “Alternate Methodology”) recommended by or reasonably acceptable to the recordkeeper for the MRO Stock Plans provided (A) the conversion effected in accordance with the Alternate Methodology results in tax consequences for option holders which are no less favorable than the consequences to such option holders if the conversion was effected in accordance with the express provisions of this Section 13.2, (B) the conversion is (subject to Section 13.2(d)((ii)) effected on a uniform and consistent basis and (C) the difference for each option holder between the aggregate “spread” respecting his or her Remaining MRO Unvested Option (as determined using the MRO Post-Distribution Stock Value) or MPC Unvested Option (as determined using the MPC Stock Value) resulting from a conversion effected in accordance with the Alternative Methodology and the aggregate “spread” resulting from a conversion effected pursuant to the express provisions of this Section 13.2 is no more than one and two/tenths (1.2) percent.

(ii)Canadian Employees.  Notwithstanding the other provisions of this Section 13.2 (including, for greater certainty, Section 13.2(d)(i)), respecting the conversion or adjustment of each MRO Unvested Option into a Remaining MRO Unvested Option or an MPC Unvested Option, as applicable, if MRO Unvested Options are held by a Person who, for the purposes of the Income Tax Act (Canada) (the “ITA”), is a resident of Canada or who was granted such MRO Unvested Options in respect of, in the course of, or by virtue of employment in Canada, the conversion or adjustment of that Person’s MRO Unvested Options shall be effected with such modifications as may be required such that: (A) any action under Section 13.2(b) which is called for at or as of the Effective Time shall be taken or completed at the time that is immediately before the time that is immediately before the Effective Time (in this Section 13.2(d)(ii), the applicable time for the actions under Section 13.2 is the “Adjustment Time”), (B) if the Canadian Pre-Distribution Spread respecting such Person’s MRO Unvested Options is nil or positive, the Post-Distribution Spread of such Person's Remaining MRO Unvested Options or MPC Unvested Options, as applicable, shall be equal to or less than such Canadian Pre-Distribution Spread, and (C) if the Canadian Pre-Distribution Spread respecting such Person’s MRO Unvested Options is negative, the Post-Distribution Spread of such Person's Remaining MRO Unvested Options or MPC Unvested Options, as applicable, shall be less than nil.  Notwithstanding anything herein contained, it is the intention that subsection 7(1.4) of the ITA shall apply to the adjustments and conversions contemplated in this Section 13.2(d)(ii).  Accordingly, if at any time hereafter, for the purposes of the ITA (or any corresponding provincial income tax legislation) and determining the income tax consequences, if any, of the actions taken pursuant to this Section 13.2(d)(ii), it is finally determined, whether by a tribunal or a court of competent jurisdiction, or otherwise that (A) the total value of the shares of common stock which may be acquired pursuant to a Person's Remaining MRO Unvested Options or MPC Unvested Options, as applicable, less the aggregate exercise price payable under such options, as determined immediately after the Adjustment Time, exceeds (B) the total value of the shares of common stock that could be acquired under that Person's MRO Unvested Options, less the aggregate amount payable under such options, as determined immediately before the Adjustment Time, then the results of the adjustment or conversion undertaken pursuant to this Section 13.2 shall be altered in order to ensure that the excess is reduced to nil by changing: (i) the number of shares of common stock subject to the Remaining MRO Unvested Options or MPC Unvested Options, as applicable,  (ii) the exercise price payable under the Remaining MRO Unvested Options or MPC Unvested Options, as applicable,  or (iii) a combination of (i) and (ii).  Any changes made under (i), (ii), or (iii) will be deemed to be effective from and after the Adjustment Time.

3.           Section 13.3(b) is amended to read as follows:

(b)Any MRO Vested Option that is held by an MRO Employee who is an employee of Marathon Oil Canada Corporation (Canada), Marathon Oil Sands (USA) Inc., Marathon Petroleum Company Norway LLC, Marathon Services Company or Marathon Services (G.B.) Limited (England) shall be converted as provided in Section 13.2(a) or 13.2(d)(ii), as applicable, rather than as provided in this Section 13.3, and any MRO Vested Option that is held by an MPC Employee  to whom MRO common stock registered on Form S-8 cannot be issued shall be converted as provided in Section 13.2(b), rather than as provided in this Section 13.3.

4.           A new Section 13.3(c) is added, as follows:

(c)Special Rules.

(i)Alternative Conversion Methodology.  Notwithstanding the other provisions of this Section 13.3 respecting the conversion  of each MRO Vested Option into a Remaining MRO Vested Option or an MPC Vested Option, the conversion for administrative convenience may be effected using any other reasonable methodology (an “Alternate Methodology”) recommended by or reasonably acceptable to the recordkeeper for the MRO Stock Plans provided (A) the conversion effected in accordance with the Alternate Methodology results in tax consequences for option holders which are no less favorable than the consequences to such option holders if the conversion was effected in accordance with the express provisions of this Section 13.3, (B) the conversion is (subject to Section 13.3(b) and Section 13.3(c)((ii)) effected on a uniform and consistent basis and (C) the difference for each Person between the aggregate “spread” respecting such Person’s Remaining MRO Vested  Option (as determined using the MRO Post-Distribution Stock Value) and MPC Vested Option (as determined using the MPC Stock Value) resulting from a conversion effected in accordance with the Alternative Methodology and the aggregate “spread” resulting from a conversion effected pursuant to the express provisions of this Section 13.3 is no more than one and two/tenths (1.2) percent.

(ii)Canadian Employees.  Notwithstanding the express provisions of this Section 13.3, except for Section 13.3(b), respecting the adjustment of each MRO Vested Option into a Remaining MRO Vested Option and an MPC Vested Option, as applicable, if MRO Vested Options are held by a Person who, for the purposes of the ITA, is a resident of Canada or who was granted such MRO Vested Options in respect of, in the course of, or by virtue of employment in Canada, the  adjustment shall be effected with such modifications as may be required such that: (A) any action under this Section 13.3 which is called for at or as of the Effective Time shall be taken or completed at the Adjustment Time, (B) a proportionate number of that Person's MRO Vested Options shall be adjusted to become Remaining MRO Vested Options and a proportionate number of that Person's MRO Vested Options shall be adjusted to become MPC Vested Options, (C) if the Canadian Pre-Distribution Spread respecting such Person’s MRO Vested Options is nil or positive, the Post-Distribution Spread of such Person's Remaining MRO Vested Options and MPC Vested Options shall be equal to or less than such Canadian Pre-Distribution Spread, and (D) if the Canadian Pre-Distribution Spread respecting such Person’s MRO Vested Options is negative, the Post-Distribution Spread of such Person's Remaining MRO Vested Options and  MPC Vested Options shall be less than nil.  Notwithstanding anything herein contained, it is the intention that subsection 7(1.4) of the ITA shall apply to the adjustments contemplated in this Section 13.3(c)(ii).  Accordingly, if at any time hereafter, for the purposes of the ITA (or any corresponding provincial income tax legislation) and determining the income tax consequences, if any, of the actions taken pursuant to this Section 13.3(c)(ii), it is finally determined, whether by a tribunal or a court of competent jurisdiction, or otherwise that (A) the total value of the shares of common stock which may be acquired pursuant to a Person's Remaining MRO Vested Options and MPC Vested Options, less the aggregate exercise price payable under such options, as determined immediately after the Adjustment Time, exceeds (B) the total value of the shares of common stock that could be acquired under that Person's MRO Vested Options, less the aggregate amount payable under such options, as determined immediately before the Adjustment Time, then the results of the adjustment undertaken pursuant to this Section 13.3 shall be altered in order to ensure that the excess is reduced to nil by changing: (i) the number of shares of common stock subject to the Remaining MRO Vested Options or MPC Vested Options, (ii) the exercise price payable under the Remaining MRO Vested Options or MPC Vested Options, as applicable,  or (iii) a combination of (i) and (ii).  Any changes made under (i), (ii), or (iii) will be deemed to be effective from and after the Adjustment Time.

5.           A new Section 13.6(d) is added, as follows:

(d)Special Rule for Canadian RSU Holders.  Notwithstanding the other provisions of this Section 13.6, if MRO RSUs are held by a Person who, for the purposes of the ITA, is a resident of Canada or who was granted such MRO RSUs in respect of, in the course of, or by virtue of employment in Canada, the conversion or adjustment of that Person's MRO RSUs shall be effected such that: (A) any action under Section 13.6(b) which is called for at or as of the Effective Time shall be taken or completed at the Adjustment Time, (B) the Post-Distribution Value of such Person's MRO RSUs as adjusted under Section 13.6(a) or such Person's MPC RSUs, as applicable, shall be equal to or less than the Pre-Distribution Value of such Person's MRO RSUs determined immediately before the Adjustment Time.  Notwithstanding anything herein contained, it is the intention that the adjustments contemplated in this Section 13.6 be completed on a tax-neutral basis under the provisions of the ITA.  Accordingly, if at any time hereafter, for the purposes of the ITA (or any corresponding provincial income tax legislation) and determining the income tax consequences, if any, of the actions taken pursuant to this Section 13.6(c), it is finally determined, whether by a tribunal or a court of competent jurisdiction, or otherwise that (A) the total value of the shares of common stock which may be acquired pursuant to a Person's MRO RSUs (as adjusted under this Section 13.6) or MPC RSUs, as determined immediately after the Adjustment Time, exceeds (B) the total value of the shares of common stock that could be acquired under that Person's MRO RSUs, as determined immediately before the Adjustment Time, then the results of the adjustment undertaken pursuant to this Section 13.6 shall be altered in order to ensure that the excess is reduced to nil by changing the number of shares of common stock subject to the MRO RSUs (as adjusted under this Section 13.6) or MPC RSUs, as applicable.  Any such change will be deemed to be effective from and after the Adjustment Time.

6.           Miscellaneous.

This Amendment may be executed in two or more counterparts, each of which will be deemed an original but all of which together shall be considered one and the same amendment and shall become effective when counterparts have been signed by each of the Parties and delivered to the other Party, it being understood that each of the Parties need not sign the same counterpart.  When this Amendment becomes effective pursuant to the immediately preceding sentence, (i) all references to “this Agreement” in the Employee Matters Agreement shall be deemed to refer to the Employee Matters Agreement as amended by this Amendment, and (ii) all references to the “Employee Matters Agreement” in the Distribution Agreement shall be deemed to refer to the Employee Matters Agreement as amended by this Amendment, unless the context otherwise requires.  Except as amended hereby, all provisions of the Employee Matters Agreement are and will remain in full force and effect.  To the extent not preempted by applicable federal law, this Amendment shall be governed by, and construed and enforced in accordance with, the substantive laws of the State of New York, without regard to any conflicts of law provisions thereof that would result in the application of the laws of any other jurisdiction.

IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be executed by their authorized representatives as of the date first above written.

MARATHON OIL CORPORATION

By:  /s/ Robert L. Sovine, Jr.

Name: Robert L. Sovine, Jr.

Title: Vice President, Human Resources

MARATHON PETROLEUM CORPORATION

By: /s/ Rodney P. Nichols

Name: Rodney P. Nichols

Title:  Vice President, Human Resources

EX-12.1

Exhibit 12.1

Marathon Oil Corporation

Computation of Ratio of Earnings to Fixed Charges

TOTAL ENTERPRISE BASIS - Unaudited

	Six Months Ended
(In millions)	June 30,
	2011		2010
Portion of rentals representing interest,
including discontinued operations	$	39	$	43
Capitalized interest,
including discontinued operations		165		217
Other interest and fixed  charges,
including discontinued operations		129		58
Total fixed charges (A)	$	333	$	318
Earnings-pretax income with
applicable adjustments (B)	$	2,141	$	2,331
Ratio of (B) to (A)		6.43		7.33

EX-31.1

Exhibit 31.1

MARATHON OIL CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Clarence P. Cazalot, Jr., certify that:

1.   I have reviewed this report on Form 10-Q of Marathon Oil Corporation;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2011	/s/ Clarence P. Cazalot, Jr.
	Clarence P. Cazalot, Jr.
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

MARATHON OIL CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Janet F. Clark, certify that:

1.   I have reviewed this report on Form 10-Q of Marathon Oil Corporation;

2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 8, 2011	/s/ Janet F. Clark
	Janet F. Clark
	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Marathon Oil Corporation (the “Company”) on Form 10-Q for the period ending June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Clarence P. Cazalot, Jr., President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1)   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 8, 2011

 /s/ Clarence P. Cazalot, Jr.

Clarence P. Cazalot, Jr.

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Marathon Oil Corporation (the “Company”) on Form 10-Q for the period ending June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Janet F. Clark, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

August 8, 2011

 /s/ Janet F. Clark

Janet F. Clark

Executive Vice President and Chief Financial Officer

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended			3 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2010 Assets Held and Used Powder River Basin [Member]	Jun. 30, 2011 Assets Held And Used Drosky [Member] Boe	Jun. 30, 2011 Fair Value [Member]	Dec. 31, 2010 Fair Value [Member]	Jun. 30, 2011 Carrying Amount [Member]	Dec. 31, 2010 Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement Captions [Line Items]
Fair value of long-lived assets held for use, quarter	$ 226	$ 2				$ 226
Fair value of long-lived assets held for use, year-to-date			226	146	144
Impairment of long-lived assets held for use	282	33	282	439	423	273
Impairment of intangible assets	25		25
Fair value of intangible assets, quarter	0		0
Fair value of intangible assets, year-to-date	0		0
Proved reserves write off						3.4
Financial assets
Other current financial assets							225	226	220	220
Other noncurrent financial assets							243	396	239	231
Total financial assets							468	622	459	451
Financial liabilities
Long-term debt, including current portion							5,504	8,364	4,984	7,527
Deferred credits and other financial liabilities							46	66	47	67
Total financial liabilities							$ 5,550	$ 8,430	$ 5,031	$ 7,594

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Consolidated Statements of Comprehensive Income (unaudited) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Consolidated Statements of Comprehensive Income
Net income	$ 996	$ 709	$ 1,992	$ 1,166
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	0	(1)	1
Derivative hedges, net of tax	(3)	1	2	4
Foreign currency translation and other
Unrealized gain	(1)	0	(1)	0
Income tax provision on foreign currency translation and other	0	0	0	0
Foreign currency translation and other, net of tax	(1)	0	(1)	0
Other comprehensive income	625	70	651	79
Comprehensive income	$ 1,621	$ 779	$ 2,643	$ 1,245

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Consolidated Balance Sheets (unaudited) (USD $) In Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 4,711	$ 3,951
Receivables, less allowance for doubtful accounts of $2 and $7	1,790	5,972
Current 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
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, current	0	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, noncurrent	2,658	3,569
Defined benefit postretirement plan obligations	673	2,171
Asset retirement obligations	1,336	1,354
Deferred credits and other liabilities, noncurrent	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)	0	0
Common stock issued - 770 million shares (par value $1 per share, 1.1 billion shares authorized)	770	770
Common stock, Securities exchangeable into common stock - no shares issued and outstanding (no par value, 29 million shares authorized)	0	0
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

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Derivatives (Details 3) (Commodity [Member], Sales and Other Operating Revenues [Member], USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Commodity [Member] | Sales and Other Operating Revenues [Member]
Gain (Loss) on Derivatives not Designated as Hedges [Line Items]
Gain (loss) on derivative instruments recognized in income	$ 1	$ 81	$ 1	$ 123

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Supplemental Cash Flow Information

6 Months Ended

Jun. 30, 2011

Supplemental Cash Flow Information Disclosure [Abstract]

Supplemental Cash Flow Information

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

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Document and Entity Information	6 Months Ended
	Jun. 30, 2011	Jul. 29, 2011
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Jun. 30, 2011
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2011
Amendment Flag	false
Entity Registrant Name	Marathon Oil Corporation
Entity Central Index Key	0000101778
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well Known Seasoned Issuer	Yes
Entity Common Stock Shares Outstanding		714,008,956

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Property, Plant and Equipment (Details 2) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011
Total Deferred Exploratory Well Costs [Abstract]
Amounts capitalized greater than one year after completion of drilling	$ 386
Increase decrease in capitalized exploratory well costs greater than one year [Line Items]
Change in exploratory well costs capitalized greater than one year	63
Norway Project [Member]
Increase decrease in capitalized exploratory well costs greater than one year [Line Items]
Change in exploratory well costs capitalized greater than one year	(26)
Innsbruckprospect [Member]
Increase decrease in capitalized exploratory well costs greater than one year [Line Items]
Change in exploratory well costs capitalized greater than one year	$ 88

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Spin-Off (Tables)

6 Months Ended

Jun. 30, 2011

Spin Off Note Tables [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Balance Sheet [Table Text Block]

(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

Discontinued Operations Disclosure [Text Block]

		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

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Property, Plant and Equipment (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Total property, plant and equipment	$ 36,383	$ 52,027
Less accumulated depreciation, depletion and amortization	16,243	19,805
Property, plant and equipment, net	20,140	32,222
United States Exploration and Production [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	14,078	13,532
International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	12,105	11,736
Exploration and Production Segment [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	26,183	25,268
Oil Sands Mining Segment [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	9,831	9,631
Integrated Gas Segment [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	48	47
Refining, Marketing and Transportation Segment [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	0	16,624
Corporate [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	321	457
Libya [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	762
Blocked international payments	$ 200
Proved Developed and Undeveloped Reserves, Net		242,000,000

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Income per Common Share

6 Months Ended

Jun. 30, 2011

Income Per Common Share Disclosure [Abstract]

Income Per Common Share

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

	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 andthe first six months of 2010were 12 millionstock options and stock appreciation rights.

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Income per Common Share (Tables)

6 Months Ended

Jun. 30, 2011

Income Per Common Share Note Tables [Abstract]

Schedule of Basic and Diluted Earnings per Share

	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

	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

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Defined Benefit Postretirement Plans (Details) (USD $) In Millions	6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended
	Jun. 30, 2011	Dec. 31, 2011	Jun. 30, 2011 Other Postretirement Benefit Plans [Member]	Jun. 30, 2010 Other Postretirement Benefit Plans [Member]	Jun. 30, 2011 Other Postretirement Benefit Plans [Member]	Jun. 30, 2010 Other Postretirement Benefit Plans [Member]	Jun. 30, 2011 Pension Benefits [Member]	Jun. 30, 2010 Pension Benefits [Member]	Jun. 30, 2011 Pension Benefits [Member]	Jun. 30, 2010 Pension Benefits [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]
Defined Benefit Plan, Service Cost			$ 1	$ 1	$ 2	$ 2	$ 10	$ 11	$ 23	$ 23
Defined Benefit Plan, Interest Cost			4	4	8	8	16	18	33	35
Expected return on plan assets					0	0	16	16	33	32
Amortization:
- prior service cost (credit)			(1)	(1)	(3)	(3)	2	1	3	3
- actuarial loss (gain)					0	0	12	14	25	25
- net settlement/curtailment loss					0	0			0	0
Net periodic benefit cost			4	4	7	7	24	28	51	54
Pension and other postretirement benefit contributions:
Pension Contributions	26
Estimated future pension contributions for remainder of current fiscal year		28
Benefits paid	2
Other postretirement benefits payments	$ 10

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Spin-Off (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Current assets of Discontinued Operations:
Cash and cash equivalents of discontinued operations	$ 1,622		$ 1,622
Receivables of discontinued operations	5,041		5,041
Inventories of discontinued operations	3,679		3,679
Other current assets of discontinued operations	170		170
Total current assets of discontinued operations	10,512		10,512
Noncurrent assets of discontinued operations:
Equity method investments of discontinued operations	323		323
Property, plant, and equipment of discontinued operations	11,935		11,935
Goodwill of discontinued operations	847		847
Other noncurrent assets of discontinued operations	351		351
Total assets of discontinued operations	23,968		23,968
Current liabilities of discontinued operations:
Accounts payable of discontinued operations	7,329		7,329
Payroll and benefits payable of discontinued operations	222		222
Accrued and deferred taxes of discontinued operations	443		443
Other current liabilities of discontinued operations	461		461
Long term debt of discontinued operations, due within one year	12		12
Total current liabilities of discontinued operations	8,467		8,467
Long term debt of discontinued operations	3,262		3,262
Deferred income taxes of discontinued operations	1,576		1,576
Defined benefit postretirement plan obligations of discontinued operations	1,489		1,489
Deferred credits and Other noncurrent liabilities of Discontinued Operations	276		276
Total liabilities of discontinued operations	15,070		15,070
Discontinued Operations Disclosure [Abstract]
Revenues applicable to discontinued operations	20,760	15,795	38,602	29,157
Pretax income from discontinued operations	$ 1,244	$ 646	$ 2,012	$ 248

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Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2011
Basis of presentation note policies [abstract]
Basis Of Accounting	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.

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Inventories

6 Months Ended

Jun. 30, 2011

Inventories Disclosure [Abstract]

Inventories

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		0		1,774
Supplies and sundry items		219		404
Total inventories, at cost	$	343	$	3,453

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Basis of Presentation

6 Months Ended

Jun. 30, 2011

Basis of presentation note policies [abstract]

Organization Consolidation And Presentation Of Financial Statements Disclosure Text Block

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 sixmonths ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year.

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Debt (Tables)

6 Months Ended

Jun. 30, 2011

Debt Note Tables [Abstract]

Schedule of Extinguishment of Debt [Text Block]

(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.

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Segment Information

6 Months Ended

Jun. 30, 2011

Segment Information Disclosure [Abstract]

Segment Information

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.

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

2)       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

3)       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.

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 secondquarter 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		0		0		15
Related parties		14		0		0		14
Segment revenues		3,249		447		13		3,709
Elimination of intersegment revenues		(15)		0		-		(15)
Total revenues	$	3,234	$	447	$	13	$	3,694
Segment income	$	601	$	69	$	43	$	713
Income from equity method investments		66		0		54		120
Depreciation, depletion and amortization		501		49		1		551
Income tax provision		598		23		17		638
Capital expenditures		749		80		0		829

	Three Months Ended June 30, 2010
(In millions)		E&P		OSM		IG		Total
Revenues:
Customer	$	2,570	$	190	$	33	$	2,793
Intersegment		16		0		0		16
Related parties		14		0		0		14
Segment revenues		2,600		190		33		2,823
Elimination of intersegment revenues		(16)		0		-		(16)
Total revenues	$	2,584	$	190	$	33	$	2,807
Segment income (loss)	$	432	$	(60)	$	24	$	396
Income from equity method investments		40		0		43		83
Depreciation, depletion and amortization		391		16		1		408
Income tax provision (benefit)		625		(10)		12		627
Capital expenditures		585		243		0		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)		0		-		(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

	Six Months Ended June 30, 2010
(In millions)		E&P		OSM		IG		Total
Revenues:
Customer	$	5,018	$	370	$	60	$	5,448
Intersegment		29		0		0		29
Related parties		26		0		0		26
Segment revenues		5,073		370		60		5,503
Elimination of intersegment revenues		(29)		0		-		(29)
Total revenues	$	5,044	$	370	$	60	$	5,474
Segment income (loss)	$	934	$	(77)	$	68	$	925
Income from equity method investments		77		0		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

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Fair Value Measurements

6 Months Ended

Jun. 30, 2011

Fair Value Measurements Disclosure [Abstract]

Fair Value Measurements

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 presentsassets and liabilitiesaccounted 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	$	0	$	1	$	81	$	140
Interest rate		0		32		0		0		32
Derivative instruments, assets		58		32		1		81		172
Derivative instruments, liabilities
Commodity		(102)		0		(3)		0		(105)
Derivative instruments, liabilities	$	(102)	$	0	$	(3)	$	0	$	(105)

At December 31, 2010, commodity derivatives in Level 1 are exchange-traded contracts for crude oil, natural gasand 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 lossesof $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	$	0	$	25	$	0	$	0
		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	$	0	$	25	$	0	$	0

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 offand 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, Georgiaregasification 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.

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 liabilitiesapproximate 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-termdebt instrumentsare publicly-traded. A market approach based upon quotesfrom 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.

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Defined Benefit Postretirement Plans

6 Months Ended

Jun. 30, 2011

Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Postretirement Plans

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)		0		0
Amortization:
– prior service cost (credit)		2		1		(1)		(1)
– actuarial loss		12		14		0		0
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)		0		-
Amortization:
– prior service cost (credit)		3		3		(3)		(3)
– actuarial loss		25		25		0		-
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 toan estimated $28 million toour 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 $10million during the first six months of 2011.

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Property, Plant and Equipment (Tables)

6 Months Ended

Jun. 30, 2011

Property Plant And Equipment Note Tables [Abstract]

Schedule of 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

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

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Dispositions

6 Months Ended

Jun. 30, 2011

Dispositions Disclosure [Abstract]

Dispositions

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.

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Derivatives (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended			3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended
	Mar. 31, 2011	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2011 Interest rate [Member] Net Interest and other Financing Costs [Member]	Jun. 30, 2010 Interest rate [Member] Net Interest and other Financing Costs [Member]	Jun. 30, 2011 Interest rate [Member] Net Interest and other Financing Costs [Member]	Jun. 30, 2010 Interest rate [Member] Net Interest and other Financing Costs [Member]	Jun. 30, 2011 Long-Term Debt [Member] Net Interest and other Financing Costs [Member]	Jun. 30, 2010 Long-Term Debt [Member] Net Interest and other Financing Costs [Member]	Jun. 30, 2011 Long-Term Debt [Member] Net Interest and other Financing Costs [Member]	Jun. 30, 2010 Long-Term Debt [Member] Net Interest and other Financing Costs [Member]
Cash Flow Hedges
Pretax unrealized gain (loss) on interest rate derivatives in OCI	$ 10
Interest Rate Derivative [Line Items]
Notional amount of interest rate derivatives		500	1,450
Weighted-average, LIBOR-based, floating rate		3.65%
Interest Rate Swaps	29
Derivative (Fair Value Hedges):
Change in unrealized gain (loss) on fair value hedging instruments				3	19	(1)	24
Hedged Item (Fair Value Hedges):
Change in unrealized gain (loss) on hedged item in fair value hedge								$ (3)	$ (19)	$ 1	$ (24)

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Consolidated Statements of Cash Flows (unaudited) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Net cash provided from 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)	0
Changes in operating capital:
Changes in current receivables	78	(13)
Changes in inventories	46	(41)
Changes in 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 provided by (used in) financing activities	(1,779)	(970)
Effect of exchange rate changes on cash:
Total 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

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Accounting Standards

6 Months Ended

Jun. 30, 2011

Accounting Standards Disclosure [Abstract]

Accounting Standards

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 underU.S. generally accepted accounting principles (“U.S. GAAP”) andInternational Financial Reporting Standards (“IFRS”). Theamendments 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 toeliminate 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 bepresented either in a single continuous statement of comprehensive income or intwo separate but consecutive statements. In the twostatement approach, thefirst statement should present total net income and its components followedconsecutively by a second statement that should present total othercomprehensive income, the components of other comprehensive income, andthe 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.

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Dispositions (Details) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Dispositions Detail [Line Items]
Proceeds from disposal of assets	$ 371	$ 1,354
Angola [Member]
Dispositions Detail [Line Items]
Proceeds from disposal of assets		1,300
Pretax gain (loss) on sale		811
Gudrun [Member]
Dispositions Detail [Line Items]
Proceeds from disposal of assets	85
Pretax gain (loss) on sale	(64)
DJ Basin [Member]
Dispositions Detail [Line Items]
Proceeds from disposal of assets	270
Pretax gain (loss) on sale	$ 39

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Inventories (Tables)

6 Months Ended

Jun. 30, 2011

Inventories Note Tables [Abstract]

Inventories by category

	June 30,		December 31,
(In millions)	2011		2010
Liquid hydrocarbons, natural gas and bitumen	$	124	$	1,275
Refined products and merchandise		0		1,774
Supplies and sundry items		219		404
Total inventories, at cost	$	343	$	3,453

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Supplemental Cash Flow Information (Details) (USD $) In Millions	6 Months Ended
	Jun. 30, 2011	Jun. 30, 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 on our behalf	14	102
Additions to property, plant and equipment	1,702	1,860
Change In capital accruals	(54)	(149)
Capital expenditures	$ 1,648	$ 1,711

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Derivatives (Details) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Interest rate [Member] | Fair Value Hedges [Member] | Other Noncurrent Assets [Member] | Net Asset [Member]
Derivatives at Fair Value on Balance Sheet [Line Items]
Derivative asset designated as hedging instrument fair value	$ 5	$ 32
Derivative net asset designated as hedging instrument fair value	5	32
Interest rate [Member] | Fair Value Hedges [Member] | Deferred Credit and other liabilities [Member] | Net Liability [Member]
Derivatives at Fair Value on Balance Sheet [Line Items]
Derivative liability designated as hedging instrument fair value	3
Derivative net liability designated as hedging instrument fair value	3
Commodity [Member] | Not Designated as Hedges [Member] | Other Current Liabilities [Member] | Net Liability [Member]
Derivatives at Fair Value on Balance Sheet [Line Items]
Derivative asset not designated as hedging instrument fair value		1
Derivative liability not designated as hedging instrument fair value		3
Derivative net liability not designated as hedging instrument fair value		2
Commodity [Member] | Other Current Assets [Member] | Net Asset [Member]
Derivatives at Fair Value on Balance Sheet [Line Items]
Derivative asset not designated as hedging instrument fair value		58
Derivative liability not designated as hedging instrument fair value		102
Derivative net asset not designated as hedging instrument fair value		(44)
Not Designated as Hedges [Member] | Net Liability [Member]
Derivatives at Fair Value on Balance Sheet [Line Items]
Derivative asset not designated as hedging instrument fair value		1
Derivative liability not designated as hedging instrument fair value		3
Derivative net liability not designated as hedging instrument fair value		2
Net Asset [Member]
Derivatives at Fair Value on Balance Sheet [Line Items]
Derivative asset designated as hedging instrument fair value		32
Derivative asset not designated as hedging instrument fair value		58
Derivative fair value of derivative asset		90
Derivative liability not designated as hedging instrument fair value		102
Derivative fair value of derivative liability		102
Derivative net asset designated as hedging instrument fair value	5	32
Derivative net asset not designated as hedging instrument fair value		(44)
Fair value of derivative net asset		(12)
Net Liability [Member]
Derivatives at Fair Value on Balance Sheet [Line Items]
Derivative fair value of derivative asset		1
Derivative fair value of derivative liability		3
Derivative net liability designated as hedging instrument fair value	3
Fair value of derivative net liability		$ 2

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Spin-Off

6 Months Ended

Jun. 30, 2011

Spin Off Disclosure [Abstract]

Spin Off Disclosure [Text Block]

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 ourrelationship 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.

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-offon 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

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Segment Information (Details 2) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Reconciliation of segment income to net income:
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 taxes	(3)	37	(17)	70
Impairments	(195)	(9)	(195)	(271)
Loss on early extinguishment of debt, after-tax	0	(57)	(176)	(57)
Tax effect of subsidiary restructuring	(122)		(122)
Deferred income tax items	(50)		(50)
Deferred tax asset write-off due to health care reform acts				(45)
Water Abatement Costs	(48)		(48)
Gain on dispositions, not allocated to segments	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
Reconciliation of total revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:
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

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2011

Segment Information Note Tables [Abstract]

Various segment information

	Three Months Ended June 30, 2011
(In millions)		E&P		OSM		IG		Total
Revenues:
Customer	$	3,220	$	447	$	13	$	3,680
Intersegment		15		0		0		15
Related parties		14		0		0		14
Segment revenues		3,249		447		13		3,709
Elimination of intersegment revenues		(15)		0		-		(15)
Total revenues	$	3,234	$	447	$	13	$	3,694
Segment income	$	601	$	69	$	43	$	713
Income from equity method investments		66		0		54		120
Depreciation, depletion and amortization		501		49		1		551
Income tax provision		598		23		17		638
Capital expenditures		749		80		0		829

	Three Months Ended June 30, 2010
(In millions)		E&P		OSM		IG		Total
Revenues:
Customer	$	2,570	$	190	$	33	$	2,793
Intersegment		16		0		0		16
Related parties		14		0		0		14
Segment revenues		2,600		190		33		2,823
Elimination of intersegment revenues		(16)		0		-		(16)
Total revenues	$	2,584	$	190	$	33	$	2,807
Segment income (loss)	$	432	$	(60)	$	24	$	396
Income from equity method investments		40		0		43		83
Depreciation, depletion and amortization		391		16		1		408
Income tax provision (benefit)		625		(10)		12		627
Capital expenditures		585		243		0		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)		0		-		(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

	Six Months Ended June 30, 2010
(In millions)		E&P		OSM		IG		Total
Revenues:
Customer	$	5,018	$	370	$	60	$	5,448
Intersegment		29		0		0		29
Related parties		26		0		0		26
Segment revenues		5,073		370		60		5,503
Elimination of intersegment revenues		(29)		0		-		(29)
Total revenues	$	5,044	$	370	$	60	$	5,474
Segment income (loss)	$	934	$	(77)	$	68	$	925
Income from equity method investments		77		0		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

Reconciliation of segment income to net 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.

Reconciliation of revenues to sales as presented on the income statement

	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

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Fair Value (Tables)

6 Months Ended

Jun. 30, 2011

Fair Value Measurements Note Tables [Abstract]

Derivative fair value assets and liabilities table - Recurring

	December 31, 2010
(In millions)		Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	58	$	0	$	1	$	81	$	140
Interest rate		0		32		0		0		32
Derivative instruments, assets		58		32		1		81		172
Derivative instruments, liabilities
Commodity		(102)		0		(3)		0		(105)
Derivative instruments, liabilities	$	(102)	$	0	$	(3)	$	0	$	(105)

Derivative fair value level 3 rollforward table - Recurring

	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)

Nonrecurring fair value table

		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	$	0	$	25	$	0	$	0
		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	$	0	$	25	$	0	$	0

Financial instruments fair value table

	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.

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Segment Information (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Revenues:
Customer revenues	$ 3,680	$ 2,793	$ 7,336	$ 5,448
Intersegment revenues	15	16	41	29
Related parties	14	14	29	26
Segment revenues, total	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
Segment income (loss)	713	396	1,473	925
Income from equity method investments, segment	120	83	237	168
Depreciation, depletion and amortization, segment	551	408	1,176	829
Income tax provision (benefit), segment	638	627	1,287	1,180
Capital expenditures, segment	829	828	1,618	1,697
Crude Oil Intersegment Sales Reclass	787	349	1,395	647
Exploration and Production Segment [Member]
Revenues:
Customer revenues	3,220	2,570	6,506	5,018
Intersegment revenues	15	16	41	29
Related parties	14	14	29	26
Segment revenues, total	3,249	2,600	6,576	5,073
Elimination of intersegment revenues	(15)	(16)	(41)	(29)
Total revenues	3,234	2,584	6,535	5,044
Segment income (loss)	601	432	1,269	934
Income from equity method investments, segment	66	40	124	77
Depreciation, depletion and amortization, segment	501	391	1,087	788
Income tax provision (benefit), segment	598	625	1,211	1,162
Capital expenditures, segment	749	585	1,417	1,188
Oil Sands Mining Segment [Member]
Revenues:
Customer revenues	447	190	753	370
Intersegment revenues	0	0	0	0
Related parties	0	0	0	0
Segment revenues, total	447	190	753	370
Elimination of intersegment revenues	0	0	0	0
Total revenues	447	190	753	370
Segment income (loss)	69	(60)	101	(77)
Income from equity method investments, segment	0	0	0	0
Depreciation, depletion and amortization, segment	49	16	86	39
Income tax provision (benefit), segment	23	(10)	33	(17)
Capital expenditures, segment	80	243	200	508
Integrated Gas Segment [Member]
Revenues:
Customer revenues	13	33	77	60
Intersegment revenues	0	0	0	0
Related parties	0	0	0	0
Segment revenues, total	13	33	77	60
Elimination of intersegment revenues	0	0	0	0
Total revenues	13	33	77	60
Segment income (loss)	43	24	103	68
Income from equity method investments, segment	54	43	113	91
Depreciation, depletion and amortization, segment	1	1	3	2
Income tax provision (benefit), segment	17	12	43	35
Capital expenditures, segment	$ 0	$ 0	$ 1	$ 1

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2011

Income Taxes Note Tables [Abstract]

Effective Tax Rate Reconciliation Table

	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		0
Adjustments to valuation allowances	0		1
Tax law change	2		2
Effective income tax rate for continuing operations	60	%	55	%

Summary of 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

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Property, Plant and Equipment

6 Months Ended

Jun. 30, 2011

Property Plant And Equipment Disclosure [Abstract]

Property, Plant and Equipment

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

• 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 theWaha concession in eastern Libya. As of June 30, 2011, our net property, plant and equipment investment in Libya is approximately $762millionand our net proved reserves in Libya were 242million 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 $63million 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.

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Stock-Based Compensation (Details 2) (USD $)	6 Months Ended
	Jun. 30, 2011
Stock Options
Stock options outstanding at beginning of period	24,912,237
Stock options granted	7,610,911
Stock options exercised	(3,465,679)
Stock options canceled	(219,052)
Reduction in stock options outstanding as a result of spin-off	(6,996,298)
Stock options outstanding at end of period	21,842,119
Weighted average exercise price of stock options outstanding at beginning of period	$ 24.85
Weighted average exercise price per share of award options granted	$ 41.51
Weighted average exercise price per share of options exercised	$ 15.02
Weighted average exercise price of stock options canceled	$ 23.03
Weighted average exercise price of stock options no longer outstanding due to spin-off	$ 31.21
Weighted average exercise price of stock options outstanding at end of period	$ 24.43

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Variable Interest Entities

6 Months Ended

Jun. 30, 2011

Variable Interest Entities Disclosure [Abstract]

Variable Interest Entities

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.

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Debt

6 Months Ended

Jun. 30, 2011

Debt Disclosure [Abstract]

Debt

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 orunder our U.S. commercial paper program that is backed by the revolving credit facility.

In February and March 2011, we retiredthe 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.

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Income per Common Share (Details) (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Income Per Common Share Note Details [Abstract]
Income loss from continuing operations	$ 298	$ 374	$ 753	$ 991
Discontinued operations	698	335	1,239	175
Net income	$ 996	$ 709	$ 1,992	$ 1,166
Weighted average number of shares outstanding, basic	713	710	712	709
Effect of dilutive securities	4	2	4	2
Diluted	717	712	716	711
Basic:
Income from continuing operations, per basic share	$ 0.42	$ 0.53	$ 1.06	$ 1.39
Discontinued operations, per basic share	$ 0.98	$ 0.47	$ 1.74	$ 0.25
Net income, per basic share	$ 1.40	$ 1.00	$ 2.80	$ 1.64
Diluted:
Income from continuing operations, per diluted share	$ 0.42	$ 0.53	$ 1.05	$ 1.39
Discontinued operations, per diluted share	$ 0.97	$ 0.47	$ 1.73	$ 0.25
Net income, per diluted share	$ 1.39	$ 1.00	$ 2.78	$ 1.64
Antidilutive securities excluded from computation of earnings per share	5	12	6	12

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Defined Benefit Postretirement Plans (Tables)

6 Months Ended

Jun. 30, 2011

Defined Benefit Postretirement Plans Note Tables [Abstract]

Schedule of Net Periodic Benefit Cost and Other Comprehensive Income

	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)		0		0
Amortization:
– prior service cost (credit)		2		1		(1)		(1)
– actuarial loss		12		14		0		0
Net periodic benefit cost	$	24	$	28	$	4	$	4

Schedule Of Defined Benefit Plans Disclosures [Text Block]

	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)		0		-
Amortization:
– prior service cost (credit)		3		3		(3)		(3)
– actuarial loss		25		25		0		-
Net periodic benefit cost	$	51	$	54	$	7	$	7

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Consolidated Balance Sheets Parentheticals (unaudited) (USD $) In Millions, except Share data	Jun. 30, 2011	Dec. 31, 2010
Consolidated Balance Sheets Parenthetical [Abstract]
Allowance for doubtful accounts	$ 2	$ 7
Less accumulated depreciation, depletion and amortization	$ 16,243	$ 19,805
Preferred stock, no par value	$ 0	$ 0
Preferred stock shares authorized	26,000,000	26,000,000
Preferred stock shares issued	0	0
Preferred stock shares outstanding	0	0
Common stock, par value per share	$ 1	$ 1
Common stock shares authorized	1,100,000,000	1,100,000,000
Common stock, shares issued	770,000,000	770,000,000
Common stock, shares outstanding	770,000,000	770,000,000
Common stock, securities exchangeable, no par value	$ 0	$ 0
Common stock, securities exchangeable, shares authorized	29,000,000	29,000,000
Common stock, securities exchangeable, shares issued	0	0
Common stock, securities exchangeable, shares outstanding	0	0
Held in treasury, shares	56,000,000	60,000,000

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Stock-Based Compensation Plans

6 Months Ended

Jun. 30, 2011

Stock Based Compensation Plans Disclosure [Abstract]

Stock-Based Compensation Plans

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 were 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 sixmonths 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.

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011	Jun. 30, 2010
Effective Tax Rate Reconciliation [Abstract]
Statutory U.S. income tax rate		35.00%	35.00%
Effects of foreign operations, including foreign tax credits		11.00%	17.00%
Change in permanent reinvestment assertion		12.00%
Adjustments to valuation allowance			1.00%
Tax law change		2.00%	2.00%
Effective income tax rate for continuing operations		60.00%	55.00%
Deferred tax asset write-off due to health care reform acts			$ (45)
Statutory Income Tax rate in Libya	in excess of 90 percent
Tax Adjustments, Settlements, and Unusual Provisions	716
Deferred tax asset write-off due to state tax law change	32
United States tax credit on foreign tax		(448)
Effects of foreign operations	$ 122

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2011

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 ofguarantees 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 andthere 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 beenrecorded 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$1,486million. 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.

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Consolidated Statements of Stockholders Equity (unaudited) (USD $) In Millions	Total	Preferred Stock [Member]	Common Stock [Member]	Common Stock Securities Exchangable [Member]	Treasury Stock [Member]	Additional Paid In Capital [Member]	Retained Earnings [Member]	Other Comprehensive Income [Member]	Total Line Item [Member]
Balance at Dec. 31, 2010	$ 23,771	$ 0	$ 770	$ 0	$ (2,665)	$ 6,756	$ 19,907	$ (997)
Shares Balance at Dec. 31, 2010			770		(60)
Shares issued - stock based compensation	117				175	(58)
Shares issued - stock based compensation, shares					4
Shares repurchased	(3)				(3)
Stock-based compensation	20					20
Net income	1,992						1,992
Other comprehensive income (loss)	651							64	64
Dividends paid	(356)						356
Distribution related to spin-off of downstream businesses	(8,898)					5	(9,490)	587
Balance at Jun. 30, 2011	$ 16,707	$ 0	$ 770	$ 0	$ (2,493)	$ 6,723	$ 12,053	$ (346)
Shares Balance at Jun. 30, 2011			770		(56)

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Income Taxes

6 Months Ended

Jun. 30, 2011

Income Taxes Disclosure [Abstract]

Income Taxes

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		0
Adjustments to valuation allowances	0		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.

We reduced our valuation allowance related to foreign tax creditsof $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 anexpense 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 $13million 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.

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Stock-Based Compensation Plans (Details) (USD $)	6 Months Ended
	Jun. 30, 2011
Schedule Of Weighted Average Grant Date Fair Value Of Stock Option Awards [Abstract]
Weighted average grant date fair value of stock option awards granted	$ 10.40

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Commitments and Contingencies (Details) (USD $) In Millions	Jun. 30, 2011
Guarantee Obligations [Line Items]
Commitments to acquire property, plant and equipment	$ 1,486
Supply Agreements Of Spinee [Member]
Guarantee Obligations [Line Items]
Maximum potential undiscounted payments under guarantees	$ 381

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Derivatives (Tables)

6 Months Ended

Jun. 30, 2011

Derivatives Note Tables [Abstract]

Derivatives as they appear on the Balance Sheet

	December 31, 2010
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	32	$	0	$	32	Other noncurrent assets
Total Designated Hedges		32		0		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

Effects of derivatives designated as fair value hedges

		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)

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Derivatives

6 Months Ended

Jun. 30, 2011

Derivatives Disclosure [Abstract]

Derivatives

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	$	0	$	32	Other noncurrent assets
Total Designated Hedges		32		0		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 $10million 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 $1,450million. 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)

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.

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Consolidated Statements of Income (unaudited) (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 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
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
Impairments	307	5	307	439
Income from operations	928	922	2,217	2,311
Net interest and other	(13)	(15)	(32)	(37)
Loss on early extinguishment of debt	0	(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
Basic:
Income from continuing operations, per basic share	$ 0.42	$ 0.53	$ 1.06	$ 1.39
Discontinued operations, per basic share	$ 0.98	$ 0.47	$ 1.74	$ 0.25
Net income, per basic share	$ 1.40	$ 1.00	$ 2.80	$ 1.64
Diluted:
Income from continuing operations, per diluted share	$ 0.42	$ 0.53	$ 1.05	$ 1.39
Discontinued operations, per diluted share	$ 0.97	$ 0.47	$ 1.73	$ 0.25
Net income, per diluted share	$ 1.39	$ 1.00	$ 2.78	$ 1.64
Dividends paid, per share	$ 0.25	$ 0.25	$ 0.50	$ 0.49
Weighted average number of shares
Basic	713	710	712	709
Diluted	717	712	716	711

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Supplemental Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2011

Supplemental Cash Flow Information Note Tables [Abstract]

Schedule of interest paid, income taxes paid, and significant noncash items

	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

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Fair Value Measurements (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets	$ 5		$ 5		$ 172
Derivative instruments, liabilities	3		3		(105)
Reconciliation of net beginning and ending balances recorded for derivative instruments classified as Level 3 in the fair value hierarchy
Beginning balance, net Level 3 fair value asset (liability)	(1)	8	(2)	9
Total realized and unrealized gains (losses):
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 businesses	2	0	2	0
Ending balance, net Level 3 fair value asset (liability)	0	(3)	0	(3)
Unrealized gains(losses) included in net income related to Level 3 derivative instruments		2		4
Fair Value, Inputs, Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets					58
Derivative instruments, liabilities					(102)
Fair Value, Inputs, Level 1 [Member] | Commodity [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets					58
Derivative instruments, liabilities					(102)
Fair Value Inputs Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets					32
Fair Value Inputs Level 2 [Member] | Interest rate [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets	5		5		32
Derivative instruments, liabilities	3		3
Fair Value, Inputs, Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets					1
Derivative instruments, liabilities					(3)
Fair Value, Inputs, Level 3 [Member] | Commodity [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets					1
Derivative instruments, liabilities					(3)
Fair Value (no inputs) Collateral [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets					81
Fair Value (no inputs) Collateral [Member] | Commodity [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets					81
Commodity [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets					140
Derivative instruments, liabilities					(105)
Interest rate [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Derivative instruments, assets					$ 32

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Stock-Based Compensation Plans (Details 3) (USD $)	6 Months Ended
	Jun. 30, 2011
Restricted Stock
Restricted stock outstanding at beginning of period	2,084,680
Restricted stock granted	564,583
Restricted stock vested	(335,781)
Restricted stock canceled	(66,424)
Reduction in restricted stock outstanding as a result of spin-off	(286,450)
Restricted stock outstanding at end of period	1,960,608
Weighted average grant date fair value of restricted stock at beginning of period	$ 23.03
Weighted average grant date fair value of restricted stock granted	$ 30.53
Weighted average grant date fair value of restricted stock vested	$ 27.24
Weighted average grant date fair value of restricted stock canceled	$ 24.09
Weighted average grant date fair value of restricted stock no longer outstandiing due to spin- off	$ 21.24
Weighted average grant date fair value of restricted stock outstanding at end of period	$ 24.70

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Income Taxes (Details) FIN 48 (USD $) In Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011	Jun. 30, 2010
Unrecognized Tax Benefit Rollforward [Abstract]
Unrecognized Tax Benefits, Beginning Balance		$ 103	$ 75
Unrecognized Tax Benefits Increases Resulting From Current Period Tax Positions		2	4
Unrecognized Tax Benefits Decreases Resulting From Current Period Tax Positions		(2)	(4)
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions		53	15
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions		(8)	(20)
Unrecognized Tax Benefits Increases Resulting From Settlements With Taxing Authorities		(9)
Unrecognized Tax Benefits Decreases Resulting From Settlements With Taxing Authorities			(1)
Unrecognized Tax Benefits, Ending Balance	139	139	69
Unrecognized Tax Benefits That Would Impact Effective Tax Rate	132	132
Significant Change In Unrecognized Tax Benefits Is Reasonably Possible Amount Of Unrecorded Benefit	13	13
Valuation Allowance Abstract
Change in foreign valuation allowances	(228)
Change in state valuation allowances	$ 18

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Inventories (Details) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Inventories Note Details [Abstract]
Liquid hydrocarbons, natural gas and bitumen	$ 124	$ 1,275
Refined products and merchandise	0	1,774
Supplies and sundry items	219	404
Total inventories, at cost	$ 343	$ 3,453

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Debt (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Debt Instrument [Line Items]
Extinguishment of debt amount			$ 2,498
Loss on early extinguishment of debt	0	(92)	(279)	(92)
Outstanding Short Term Debt [Abstract]
Commercial paper outstanding	0		0
Borrowings against revolving credit facility outstanding	0		0
Notes Due 2012 [A] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.125%		6.125%
Extinguishment of debt amount			450
Debt Instrument, Maturity Date			Mar. 15, 2012
Notes Due 2012 [B] [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.00%		6.00%
Extinguishment of debt amount			400
Debt Instrument, Maturity Date			Jul. 01, 2012
Debentures Due 2014 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%		6.50%
Extinguishment of debt amount			700
Debt Instrument, Maturity Date			Feb. 15, 2014
Notes Due 2018 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.90%		5.90%
Extinguishment of debt amount			40
Debt Instrument, Maturity Date			Mar. 15, 2018
Debentures Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.50%		7.50%
Extinguishment of debt amount			460
Debt Instrument, Maturity Date			Feb. 15, 2019
Consolidated Subsidiaries Secured Notes Due 2012 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.375%		8.375%
Extinguishment of debt amount			$ 448
Debt Instrument, Maturity Date			May 12, 2012

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Stock-Based Compensation Plans (Tables)

6 Months Ended

Jun. 30, 2011

Stock Based Compensation Plans Note Tables [Abstract]

Schedule of Stock based Compensation

	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