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

form10q2011q1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended March 31, 2011

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

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)

Delaware	25-0996816
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

5555 San Felipe Road, Houston, TX 77056-2723

(Address of principal executive offices)

(713) 629-6600

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes Ö No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes Ö No

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

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

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

There were 712,088,523 shares of Marathon Oil Corporation common stock outstanding as of April 29, 2011.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended March 31, 2011

	INDEX
		Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)		2
	Consolidated Balance Sheets (Unaudited)		3
	Consolidated Statements of Cash Flows (Unaudited)		4
	Consolidated Statements of Comprehensive Income (Unaudited)		5
	Notes to Consolidated Financial Statements (Unaudited)		6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		30
Item 4.	Controls and Procedures		30
	Supplemental Statistics (Unaudited)		31
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		34
Item 1A.	Risk Factors		34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		34
Item 6.	Exhibits		35
	Signatures		36

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

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


	Three Months Ended March 31,
(In millions, except per share data)	2011			2010
Revenues and other income:

Sales and other operating revenues (including consumer excise taxes)	$	20,867		$	15,694
Sales to related parties		37			20
Income from equity method investments		126			105
Net gain on disposal of assets		6			813
Other income		35			33

Total revenues and other income		21,071			16,665

Costs and expenses:
Cost of revenues (excludes items below)		16,023			12,726
Purchases from related parties		179			133
Consumer excise taxes		1,209			1,212
Depreciation, depletion and amortization		852			649
Long-lived asset impairments		-			434
Selling, general and administrative expenses		353			298
Other taxes		122			115
Exploration expenses		230			98

Total costs and expenses		18,968			15,665

Income from operations		2,103			1,000
Net interest and other		(65	)		(30	)
Loss on early extinguishment of debt		(279	)		-

Income from continuing operations before income taxes		1,759			970
Provision for income taxes		763			513

Net income	$	996		$	457

Per Share Data

Basic:
Net income	$	1.40		$	0.64

Diluted:
Net income	$	1.39		$	0.64

Dividends paid	$	0.25		$	0.24

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	March 31,			December 31,
(In millions, except per share data)	2011			2010
Assets
Current assets:
Cash and cash equivalents	$	5,716		$	3,951
Receivables, less allowance for doubtful accounts of $7 and $7		6,498			5,972
Receivables from related parties		59			58
Inventories		3,088			3,453
Other current assets		414			395

Total current assets		15,775			13,829

Equity method investments		1,846			1,802
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $20,692 and $19,805		32,189			32,222
Goodwill		1,376			1,380
Other noncurrent assets		679			781

Total assets	$	51,865		$	50,014
Liabilities
Current liabilities:
Accounts payable	$	8,341		$	8,000
Payables to related parties		63			49
Payroll and benefits payable		359			418
Accrued taxes		1,744			1,447
Deferred income taxes		333			324
Other current liabilities		593			580
Long-term debt due within one year		349			295

Total current liabilities		11,782			11,113

Long-term debt		7,992			7,601
Deferred income taxes		3,333			3,569
Defined benefit postretirement plan obligations		2,199			2,171
Asset retirement obligations		1,368			1,354
Deferred credits and other liabilities		486			435

Total liabilities		27,160			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 and 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 – 58 million and 60 million shares		(2,582	)		(2,665	)
Additional paid-in capital		6,763			6,756
Retained earnings		20,725			19,907
Accumulated other comprehensive loss		(971	)		(997	)

Total stockholders' equity		24,705			23,771

Total liabilities and stockholders' equity	$	51,865		$	50,014

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended March 31,
(In millions)	2011			2010
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	996		$	457
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on early extinguishment of debt		279			-
Deferred income taxes		(242	)		(25	)
Depreciation, depletion and amortization		852			649
Long-lived asset impairments		-			434
Pension and other postretirement benefits, net		61			50
Exploratory dry well costs and unproved property impairments		173			52
Net gain on disposal of assets		(6	)		(813	)
Equity method investments, net		(49	)		(42	)
Changes in:
Current receivables		(630	)		(193	)
Inventories		366			(235	)
Current accounts payable and accrued liabilities		700			448
All other operating, net		92			67
Net cash provided by operating activities		2,592			849
Investing activities:
Additions to property, plant and equipment		(1,062	)		(1,348	)
Disposal of assets		212			1,342
Investments - loans and advances		(24	)		(7	)
Investments - repayments of loans and return of capital		28			14
All other investing, net		13			(11	)
Net cash used in investing activities		(833	)		(10	)
Financing activities:
Borrowings		2,989			-
Debt issuance costs		(46	)		-
Debt repayments		(2,783	)		(2	)
Dividends paid		(178	)		(172	)
All other financing, net		20			2
Net cash provided by (used in) financing activities		2			(172	)
Effect of exchange rate changes on cash:
Total effect of exchange rate changes on cash		4			(6	)
Net increase in cash and cash equivalents		1,765			661
Cash and cash equivalents at beginning of period		3,951			2,057
Cash and cash equivalents at end of period	$	5,716		$	2,718

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended March 31,
(In millions)	2011			2010
Net income	$	996		$	457
Other comprehensive income

Post-retirement and post-employment plans
Change in actuarial gain		33			30
Income tax provision on post-retirement and post-employment plans		(12	)		(24	)
Post-retirement and post-employment plans, net of tax		21			6

Derivative hedges
Net unrecognized gain		9			2
Income tax benefit (provision) on derivatives		(4	)		1
Derivative hedges, net of tax		5			3


Other comprehensive income		26			9

Comprehensive income	$	1,022		$	466

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

These consolidated financial statements are unaudited; however, in the opinion of management these statements reflect all adjustments necessary for a fair presentation of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including 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.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation (“Marathon”) 2010 Annual Report on Form 10-K. The results of operations for the quarter ended March 31, 2011, are not necessarily indicative of the results to be expected for the full year.

On January 13, 2011, the Board of Directors of Marathon announced that it has approved moving forward with plans to spin-off Marathon’s downstream (Refining, Marketing and Transportation) business, creating two independent energy companies: Marathon Petroleum Corporation (“MPC”) and Marathon Oil Corporation (“MRO”). To affect the spin-off, Marathon intends to distribute one share of MPC for every two shares of Marathon held at a record date to be determined. The transaction is expected to be effective June 30, 2011, with distribution of MPC shares shortly thereafter. A tax ruling request was submitted to the U.S. Internal Revenue Service (“IRS”) regarding the tax-free nature of the spin-off and Marathon anticipates a response during the second quarter of 2011.

2. Variable Interest Entities

The owners of 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 mine, 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 March 31, 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. 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 $785 million as of March 31, 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.

In December 2010, we closed the sale of most of our Minnesota assets, plus related inventories. Certain terms of the transaction resulted in the creation of variable interests in a VIE that owns the Minnesota assets. These variable interests include our ownership of a preferred equity interest in the VIE, operating margin support in the form of a capped liquidity guarantee, and reimbursements to us for costs incurred in connection with transition services provided to the buyer. Our preferred equity interest in this VIE was reflected at $80 million in other noncurrent assets on the consolidated balance sheets as of March 31, 2011 and December 31, 2010. At December 31, 2010, there was an additional $107 million receivable due from the buyer related to a portion of the inventories sold that was fully collected by March 31, 2011.

We are not the primary beneficiary of this VIE and therefore do not consolidate it; we lack the power to control or direct the activities that impact the VIE’s operations and economic performance. Our preferred equity does not allow us to appoint a majority of the Board of Managers and limits our ability to vote on only certain matters. Also, individually and cumulatively, none of our other variable interests expose us to residual returns or expected losses that are significant to the VIE. Our maximum exposure to loss due to this VIE is $151 million as of March 31, 2011, based on contractual arrangements related to the sale. We did not provide any financial assistance to the buyer outside of our contractual arrangements related to the sale.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

3. Income per Common Share

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

	Three Months Ended March 31,
	2011						2010
(In millions, except per share data)	Basic			Diluted			Basic		Diluted

Net income		$	996		$	996	$	457		$	457

Weighted average common shares outstanding			711			711		709			709
Effect of dilutive securities			-			4		-			2
Weighted average common shares, including
dilutive effect			711			715		709			711

Per share:
Net income		$	1.40		$	1.39	$	0.64		$	0.64

The per share calculations above exclude 5 million and 12 million stock options and stock appreciation rights for the first three months of 2011 and 2010, that were antidilutive.

4. Dispositions

In March 2011, we closed the sale of our Exploration and Production (“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.

5. Segment Information

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

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

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

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

Refining, Marketing and Transportation (“RM&T”) – refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Gulf Coast and southeastern regions of the U.S.

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 but not corporate administrative activities.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Three Months Ended March 31, 2011
(In millions)	E&P			OSM			IG		RM&T			Total

Revenues:
Customer	$	2,707		$	277		$	64	$	17,819		$	20,867
Intersegment		660			29			-		1			690
Related parties		15			-			-		22			37
Segment revenues		3,382			306			64		17,842			21,594
Elimination of intersegment revenues		(660	)		(29	)		-		(1	)		(690	)
Total revenues	$	2,722		$	277		$	64	$	17,841		$	20,904
Segment income	$	668		$	32		$	60	$	527		$	1,287
Income from equity method investments		58			-			59		9			126
Depreciation, depletion and amortization		586			37			2		216			841
Income tax provision		612			10			26		294			942
Capital expenditures		668			120			1		200			989

	Three Months Ended March 31, 2010
(In millions)	E&P			OSM			IG		RM&T			Total

Revenues:
Customer	$	2,153	(a)	$	176	(b)	$	27	$	13,338		$	15,694
Intersegment		386	(c)		10	(c)		-		16			412
Related parties		12			-			-		8			20
Segment revenues		2,551			186			27		13,362			16,126
Elimination of intersegment revenues		(386	)		(10	)		-		(16	)		(412	)
Total revenues	$	2,165		$	176		$	27	$	13,346		$	15,714
Segment income (loss)	$	502		$	(17	)	$	44	$	(237	)	$	292
Income from equity method investments		37			-			48		20			105
Depreciation, depletion and amortization		397			23			1		220			641
Income tax provision (benefit)		538			(7	)		23		(153	)		401
Capital expenditures		603			265			1		310			1,179

(a)	We have revised 2010 amounts. (See 2010 Form 10-K) E&P segment customer revenues were reduced by $184 million in the first quarter of 2010; however segment income did not change because an offsetting amount is in cost of revenues.

(b)	We have revised 2010 amounts. (See 2010 Form 10-K) OSM segment customer revenues were increased by $29 million in the first quarter of 2010; however segment income did not change because an offsetting amount is in cost of revenues.

(c)	We have revised 2010 amounts. (See 2010 Form 10-K) E&P segment intersegment revenues increased by $214 million in the first quarter of 2010 and OSM intersegment revenues decreased by $8 million; however, consolidated income did not change because intersegment activity eliminates in consolidation.

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

	Three Months Ended March 31,
(In millions)	2011			2010
Segment income	$	1,287		$	292
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(90	)		(10	)
Foreign currency remeasurement of taxes		(14	)		33
Loss on extinguishment of debt		(176	)		-
Gain on disposition		-			449
Long-lived asset impairment		-			(262	)
Deferred income taxes - tax legislation changes		-			(45	)
Spin-off related costs		(11	)		-
Net income	$	996		$	457

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

	Three Months Ended March 31,
(In millions)	2011			2010
Total revenues		$	20,904	$	15,714
Less: Sales to related parties			37		20
Sales and other operating revenues (including consumer excise taxes)		$	20,867	$	15,694

6. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Three Months Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2011			2010			2011			2010
Service cost	$	31		$	29		$	6		$	5
Interest cost		45			45			11			10
Expected return on plan assets		(41	)		(40	)		-			-
Amortization:
– prior service cost (credit)		3			3			(2	)		(1	)
– actuarial loss (gain)		30			25			-			(1	)
Net periodic benefit cost	$	68		$	62		$	15		$	13

During the first three months of 2011, we made contributions of $11 million to our funded international pension plans. We expect to make additional contributions up to an estimated $145 million to our funded pension plans over the remainder of 2011. Current benefit payments related to unfunded pension and other postretirement benefit plans were $4 million and $8 million during the first three months of 2011.

7. Income Taxes

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

	Three Months Ended March 31,
	2011			2010
Statutory U.S. income tax rate		35	%		35	%
Effects of foreign operations, including foreign tax credits		2			14
Adjustments to valuation allowances		6			1
State and local income taxes, net of federal income tax effects		1			(1	)
Tax law change		-			5
Other tax effects		(1	)		(1	)
Effective income tax rate for continuing operations		43	%		53	%

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 5.

The effects of foreign operations on our effective tax rate decreased in the first quarter of 2011 as compared to the first quarter of 2010, primarily due to the suspension of all production operations in Libya, where the statutory tax rate is in excess of 90 percent. The valuation allowance on our deferred tax assets increased because it is more likely than not that we will be unable to realize all recorded foreign tax credit benefits being accrued in 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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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. As a result, we 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:

	Three Months Ended March 31,
(In millions)	2011			2010
Beginning balance	$	103		$	75
Additions based on tax positions related to the current year		1			1
Reductions based on tax positions related to the current year		(1	)		(1	)
Additions for tax positions of prior years		36			11
Reductions for tax positions of prior years		(6	)		(18	)
Settlements		-			(1	)
Ending balance	$	133		$	67

If the unrecognized tax benefits as of March 31, 2011 were recognized, $123 million would affect our effective income tax rate. There were $17 million of uncertain tax positions as of March 31, 2011 for which it is reasonably possible that the amount of unrecognized tax benefits would decrease during the next twelve months.

8. Inventories

Inventories are carried at the lower of cost or market value. The cost of inventories of crude oil, refined products and merchandise is determined primarily under the last-in, first-out (“LIFO”) method.

	March 31,		December 31,
(In millions)	2011		2010
Liquid hydrocarbons, natural gas and bitumen	$	1,067	$	1,275
Refined products and merchandise		1,621		1,774
Supplies and sundry items		400		404
Total inventories, at cost	$	3,088	$	3,453

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

9. Property, Plant and Equipment

	March 31,			December 31,
(In millions)	2011			2010
E&P
United States	$	13,774		$	13,532
International		11,977			11,736
Total E&P		25,751			25,268
OSM		9,752			9,631
IG		47			47
RM&T		16,868			16,624
Corporate		463			457
Total property, plant and equipment		52,881			52,027
Less accumulated depreciation, depletion and amortization		(20,692	)		(19,805	)
Net property, plant and equipment	$	32,189		$	32,222

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 March 31, 2011, our net property, plant and equipment investment in Libya is approximately $761 million. 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 March 31, 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 $296 million as of March 31, 2011, a decrease of $27 million from December 31, 2010 related to the resumption of our offshore Norway exploration project in 2011.

10. Fair Value Measurements

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis, as of March 31, 2011 and December 31, 2010 by fair value hierarchy level.

	March 31, 2011
(In millions)	Level 1			Level 2			Level 3			Collateral		Total
Derivative instruments, assets
Commodity	$	143		$	2		$	4		$	105		254
Derivative instruments, assets		143			2			4			105		254
Derivative instruments, liabilities
Commodity	$	(188	)	$	(1	)	$	(5	)	$	-		(194	)
Interest rate		-			(2	)		-			-		(2	)
Derivative instruments, liabilities		(188	)		(3	)		(5	)		-		(196	)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	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	)

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 and interest rate swaps 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 various third-party services such as Platt’s and price assessments from other independent brokers. Since we are unable to independently verify information from the third-party service providers to active markets, these measures are considered Level 3.

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 March 31,
(In millions)	2011			2010
Beginning balance	$	(2	)	$	9
Included in net income		(1	)		(1	)
Included in other comprehensive income		-			2
Purchases		-			2
Settlements		2			(4	)
Ending balance	$	(1	)	$	8

Net income for the quarters ended March 31, 2011, and 2010 included unrealized losses of $1 million related to instruments held on those dates. See Note 11 for the impacts of our derivative instruments on our consolidated statements of income. There were no transfers of fair value estimates among hierarchy levels in the first quarters of 2011 and 2010.

Fair Values – Nonrecurring

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

	Three Months Ended March 31,
	2011					2010
(In millions)		Fair Value		Impairment			Fair Value		Impairment

Long-lived assets held for use			-		-		$	144	$	434

In the first quarter of 2010, we recorded property impairments of $434 million. 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. The field’s fair value was measured at $144 million, using an estimate of future cash flows with Level 3 inputs. This resulted in an impairment of $423 million. The remaining E&P segment impairments of $11 million in the first quarter of 2010 used the future cash flows method and were primarily a result of reduced drilling expectations. There were no significant impairments in the first quarter of 2011.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Fair Values – Reported

The following table summarizes financial instruments, excluding the derivative financial instruments reported above, by individual balance sheet line item at March 31, 2011, and December 31, 2010.


	March 31, 2011				December 31, 2010
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other current assets	$	226	$	219	$	226	$	220
Other noncurrent assets		451		281		396		231

Total financial assets		677		500		622		451

Financial liabilities
Long-term debt, including current portion(a)		8,475		8,007		8,364		7,527
Deferred credits and other liabilities		68		69		66		67

Total financial liabilities	$	8,543	$	8,076	$	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:

·	the current portion of receivables from United States Steel Corporation (“United States Steel”), which is 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 the market they are considered Level 3 inputs. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

11. Derivatives

For information regarding the fair value measurement of derivative instruments see Note 10. 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 March 31, 2011 and December 31, 2010.

	March 31, 2011
(In millions)	Asset			Liability			Net Asset				Balance Sheet Location
Not Designated as Hedges
Commodity		$	147		$	188		$	(41	)	Other current assets
Total Not Designated as Hedges			147			188			(41	)

Total		$	147		$	188		$	(41	)

	March 31, 2011
(In millions)		Asset			Liability			Net Liability			Balance Sheet Location
Fair Value Hedges
Interest rate		$	-		$	2		$	2		Deferred credits and other liabilities
Total Designated Hedges			-			2			2

Not Designated as Hedges

Commodity		$	2		$	6		$	4		Other current liabilities

Total Not Designated as Hedges			2			6			4
Total		$	2		$	8		$	6

	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 March 31, 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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Derivatives Designated as Fair Value Hedges

In connection with the debt retired in February and March 2011 discussed in Note 12, 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 March 31, 2011, we had multiple interest rate swap agreements with a total notional amount of $200 million at a weighted average, LIBOR-based, floating rate of 2.49 percent. One-half of the notional amount relates to the 3.500% notes due March 1, 2016 that were issued on February, 1, 2011 (see Note 12).

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 March 31,
(In millions)	Income Statement Location	2011			2010
Derivative
Commodity	Sales and other operating revenues	$	-		$	(1	)
Interest rate	Net interest and other		(4	)		5
			(4	)		4
Hedged Item
Commodity	Sales and other operating revenues		-			1
Interest rate	Long-term debt		4			(5	)
		$	4		$	(4	)

Derivatives not Designated as Hedges

The table below summarizes the significant open commodity derivative contracts of our RM&T segment at March 31, 2011 that are not designated as hedges. These contracts enable us to effectively correlate our commodity price exposure to the relevant market indicators, thereby mitigating fixed price risk.

	Position	Bbls per Day			Weighted Average Price (Dollars per Bbl)		Benchmark
Crude Oil
Exchange-traded	Long(a)		41,208		$	102.70	CME and ICE Crude(b)(c)
Exchange-traded	Short(a)		(76,482	)	$	101.59	CME and ICE Crude(b)(c)

	Position	Bbls per Day			Weighted Average Price (Dollars per Gallon)		Benchmark
Refined Products
Exchange-traded	Long(d)		12,488		$	3.02	CME Heating Oil and RBOB(b)(e)
Exchange-traded	Short(d)		(4,608	)	$	3.01	CME Heating Oil and RBOB(b)(e)

(a) 91 percent of these contracts expire in the second quarter of 2011.

(b) Chicago Mercantile Exchange (“CME”).

(d) 99.5 percent of these contracts expire in the second quarter of 2011.

(e) Reformulated Gasoline Blendstock for Oxygenate Blending (“RBOB”).

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table summarizes the effect of all derivative instruments not designated as hedges in our consolidated statements of income for the three months ended March 31, 2011 and 2010.

		Gain (Loss)
		Three Months Ended March 31,
(In millions)	Income Statement Location	2011				2010
Commodity	Sales and other operating revenues		$	(15	)		$	48
Commodity	Cost of revenues			(43	)			(29	)
Commodity	Other income			1				2
			$	(57	)		$	21

12. Debt

At March 31, 2011, we had no borrowings outstanding, and no borrowings were made during the first quarter of 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.

(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 are senior secured notes of Marathon Oil Canada Corporation.

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.

On February 1, 2011, MPC, currently a wholly owned subsidiary of Marathon, completed a private placement of the following Senior Notes (the “Notes”):

(In millions)
3.500% notes due March 1, 2016	$	750
5.125% notes due March 1, 2021		1,000
6.500% notes due March 1, 2041		1,250
	$	3,000

The Notes are intended to establish a minimum $750 million initial cash balance for MPC upon completion of the spin-off. All cash above that level will be used to repay existing intercompany debt with Marathon, and any remaining proceeds will be distributed to Marathon on or before June 30, 2011. The Notes are unsecured and unsubordinated obligations of MPC which are guaranteed by Marathon on a senior unsecured basis. Marathon’s guarantees will terminate upon completion of the spin-off.

The holders of the Notes are entitled to the benefits of a registration rights agreement. Within 360 days, MPC and MRO will be obligated to use commercially reasonable efforts to file a registration statement with respect to a registered exchange offer to exchange the Notes for new notes that are guaranteed by MRO, if applicable, with terms substantially identical in all material respects to the Notes. Alternatively, if the exchange offer cannot be completed, we will be required to file a shelf registration statement to cover resale of the Notes under the Securities Act. If we do not comply with these obligations, we will be required to pay additional interest on the Notes. The additional interest shall accrue on the principal amount of the Notes at a rate of 0.25 per annum, which rate will be increased by an additional 0.25 percent per annum for each subsequent 90-day period that such additional interest continues to accrue, provided that the rate at which such additional interest accrues may not exceed 1.00 percent per annum. Marathon’s obligations under the registration rights agreement will terminate upon termination of the Marathon guarantees in connection with the completion of the spin-off.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

13. Supplemental Cash Flow Information

	Three Months Ended March 31,
(In millions)	2011			2010
Net cash provided from operating activities:
Interest paid (net of amounts capitalized)		$	69		$	39
Income taxes paid to taxing authorities			605			406

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.

	Three Months Ended March 31,
(in millions)	2011				2010
Additions to property, plant and equipment		$	1,062			$	1,348
Change in capital accruals			(67	)			(169	)
Capital expenditures		$	995			$	1,179

14. 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.

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.

Contractual commitments – At March 31, 2011, our contract commitments to acquire property, plant and equipment totaled $2,353 million. The decrease in our contract commitments from December 31, 2010 is due to the disposition of some of our outside-operated offshore Norway assets, discussed in Note 4.

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

We are a global integrated energy company with significant operations in the North America, Africa and Europe. Our operations are organized into four 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.
w	Refining, Marketing & Transportation (“RM&T”) which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Gulf Coast and southeastern regions of the United States.

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.

Plan to Create Independent Downstream Company

On January 13, 2011, the Board of Directors of Marathon Oil Corporation (“Marathon”) announced that it has approved moving forward with plans to spin-off Marathon’s downstream (Refining, Marketing and Transportation) business, creating two independent energy companies: Marathon Petroleum Corporation (“MPC”) and Marathon Oil Corporation (“MRO”). To affect the spin-off, Marathon intends to distribute one share of MPC for every two shares of Marathon held at a record date to be determined. The transaction is expected to be effective June 30, 2011, with distribution of MPC shares shortly thereafter. A tax ruling request was submitted to the U.S. Internal Revenue Service (“IRS”) regarding the tax-free nature of the spin-off and Marathon anticipates a response during the second quarter of 2011. The above discussion of the plans to create an independent downstream company includes forward looking statements. Factors which could affect the plans include board approval, receipt of a favorable private letter ruling from the IRS and a registration statement declared effective by the Securities and Exchange Commission (“SEC”).

Overview and Outlook

Exploration and Production

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 March 31, 2011, our net property, plant and equipment investment in Libya is approximately $761 million and we are in an underlift position of 847 thousand barrels of liquid hydrocarbons, net to our interest. Sales from Libya in 2010 averaged 46,000 barrels of oil equivalent per day. 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 March 31, 2011, such amounts, primarily related to taxes and royalties due on our January and February 2011 sales, totaled approximately $200 million.

Production

Net liquid hydrocarbon and natural gas sales averaged 400 thousand barrels of oil equivalent per day (“mboepd”) during the first quarter of 2011 compared to 361 mboepd in the same quarter of 2010. Sales volumes increased in the U.S., primarily due to the Droshky development in the Gulf of Mexico which commenced production mid-year 2010. Internationally, increased liquid hydrocarbon sales volumes in Norway were partially offset by the impact of Libyan production operations being suspended during the first quarter of 2011. Natural gas sales from Equatorial Guinea are

higher as our operations were not producing for a portion of the first quarter of 2010 due to a planned turnaround at our production facilities.

Exploration

We commenced drilling our first operated exploration well in the Eagle Ford shale in Texas during the first quarter of 2011. As we continue our strategy of focusing on unconventional, liquids-rich resource plays we have increased our holdings in the Eagle Ford shale to approximately 29,000 acres, with rights to acquire an additional 61,000 acres.

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, or $5,000 per acre. As operator of this jointly owned leasehold, we are currently acquiring seismic data and expect to drill eight to twelve gross wells by yearend.

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.

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.

We announced a discovery on the Atrush block in the Iraqi Kurdistan Region. We have a 16 percent ownership in this outside operated block. 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 of more than 6,000 gross barrels per day were limited by tubing sizes and testing equipment.

We have 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 include well costs incurred through March 31, 2011. Additionally, approximately $25 million will be charged to exploration expense in the second quarter of 2011.

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.

Divestitures

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.

The above discussions include forward-looking statements with respect to an agreement pursuant to which we will farm-out a portion of our interest in Poland’s shale play, the timing and levels of future production, and anticipated future exploratory drilling activity. Some factors that could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorists acts and the governmental or military response, and other geological, operating and economic considerations. The completion of the agreement to farm-out a portion of our interest in Poland’s shale play is subject to customary closing conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Oil Sands Mining

Our net synthetic crude oil sales were 37 thousand barrels per day (“mbpd”) in the first quarter of 2011 compared to 25 mbpd in the same quarter of 2010, reflecting the impact of the Jackpine mine in 2011, which commenced production in 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.

The upgrader operation of the Athabasca Oil Sands Project (“AOSP”) Expansion 1 began commissioning as scheduled late in the fourth quarter of 2010 and continued through the first quarter of 2011. In May 2011, the operator announced the successful start of commercial production at the upgrader expansion. With production capacity at the AOSP now at 255,000 gross barrels per day, the focus will be on improving operating efficiencies and adding capacity through debottlenecking. We hold a 20 percent working interest in the AOSP.

Integrated Gas

Our share of LNG sales worldwide totaled 7,822 metric tonnes per day (“mtpd”) for the first quarter of 2011 compared to 5,792 mtpd in the first quarter 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 LNG plant in Alaska will close later in 2011 than previously announced because some sales have been contracted into the summer. LNG and methanol sales from Equatorial Guinea are conducted through equity method investees that purchase dry gas from our E&P assets in Equatorial Guinea. The sales increase in the

first quarter of 2011 compared to the first quarter of 2010 is 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 to the LNG and methanol facilities.

Refining, Marketing and Transportation

Our total refinery throughputs were 20 percent higher in the first quarter of 2011 than in the first quarter of 2010. The higher refinery throughputs were a result of improved refinery utilization and decreased turnaround activity in the first quarter of 2011 as compared to the same period in 2010, primarily at our Garyville, Louisiana refinery. Crude oil refined increased 11 percent for the same period and other charge and blendstocks increased 113 percent.

During the first quarter of 2011, we initiated a turnaround at the Canton, Ohio refinery which was completed in April 2011. This compares to the turnarounds we completed at both the Garyville, Louisiana and the Texas City, Texas refineries in the first quarter of 2010. We also initiated a turnaround at our Catlettsburg, Kentucky refinery in the first quarter of 2010 which was completed in April 2010.

Ethanol volumes sold in blended gasoline increased to an average of 67 mbpd in the first quarter of 2011 compared to 63 mbpd in the same period of 2010. The future expansion or contraction of our ethanol blending program will be driven by the economics of ethanol supply and government regulations.

First quarter 2011 Speedway LLC (“Speedway”) same store gasoline sales volumes were comparable to the first quarter of 2010, while same store merchandise sales increased 2 percent for the same period. During the first quarter, Speedway was ranked the nation’s top retail gasoline brand for the third consecutive year, according to the 2011 EquiTrend® Brand Study conducted by Harris Interactive®.

As of March 31, 2011, the heavy oil upgrading and expansion project at our Detroit, Michigan, refinery was approximately 55 percent complete and on schedule for an expected completion in the second half of 2012.

In April 2011, Speedway was the winning bidder at an auction for 23 retail outlets in Illinois and Indiana for approximately $70 million. We expect to close on this purchase in May 2011, subject to customary closing conditions.

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

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 first quarter in 2011, when compared to the same period in 2010.

		Three Months Ended March 31,
		2011		2010
West Texas Intermediate ("WTI") crude oil	(Dollars per barrel)	$	94.60	$	78.88
Dated Brent crude oil	(Dollars per barrel)	$	105.43	$	76.36
Henry Hub natural gas	(Dollars per million British thermal units)(a)	$	4.11	$	5.30

(a)	First-of-month price index.

Crude oil prices increased consistently during the first three months of 2011, resulting in a higher quarterly average for the first quarter of 2011 compared to the first quarter of 2010.

Our domestic crude oil production was about 70 percent sour in the first quarter 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.

Natural gas prices for the first quarter of 2011 were lower compared to the same quarter of prior year. 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 first quarter of 2011 compared to first quarter of 2010.

		Three Months Ended March 31,
Benchmark		2011		2010
WTI crude oil	(Dollars per barrel)	$	94.60	$	78.88
Western Canadian Select	(Dollars per barrel)(a)	$	71.24	$	69.67
AECO natural gas sales index	(Dollars per mmbtu)(b)	$	3.85	$	4.80

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

(b)	Monthly average 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.

Refining, Marketing and Transportation

RM&T segment income depends largely on our refining and wholesale marketing gross margin, refinery throughputs and retail marketing gross margins for gasoline, distillates and merchandise.

Our refining and wholesale marketing gross margin is the difference between the prices of refined products sold and the costs of crude oil and other charge and blendstocks refined, including the costs to transport these inputs to our refineries, the costs of purchased products and manufacturing expenses, including depreciation. The crack spread is a measure of the difference between market prices for refined products and crude oil, commonly used by the industry as a proxy for the refining margin. Crack spreads can fluctuate significantly, particularly when prices of refined products do not move in the same relationship as the cost of crude oil. As a performance benchmark and a comparison with other industry participants, we calculate Midwest (Chicago) and U.S. Gulf Coast crack spreads that we feel most closely track our operations and slate of products. Posted Light Louisiana Sweet (“LLS”) crude oil prices and a 6-3-2-1 ratio of products (6 barrels of crude oil refined into 3 barrels of gasoline, 2 barrels of distillate and 1 barrel of residual fuel) are used for the crack spread calculation.

Our refineries can process significant amounts of sour crude oil which typically can be purchased at a discount to sweet crude oil. The amount of this discount, the sweet/sour differential, can vary significantly causing our refining and wholesale marketing gross margin to differ from the crack spreads which are based upon sweet crude. In general, a larger sweet/sour differential will enhance our refining and wholesale marketing gross margin.

The following table lists calculated average crack spreads for the Midwest and Gulf Coast markets and the sweet/sour differential for the first quarters of 2011 and 2010:

	Three Months Ended March 31,
(Dollars per barrel)	2011			2010
Chicago LLS 6-3-2-1 crack spread	$	0.16		$	2.68
U.S. Gulf Coast LLS 6-3-2-1 crack spread	$	1.32		$	3.50
Sweet/Sour differential	$	12.57	(a)	$	5.23	(b)

(a)	Calculated using the following mix of crude types: 15% Arab Light, 20% Kuwait, 10% Maya, 10% Western Canadian Select and 45% Mars compared to LLS.

(b)	Calculated using the following mix of crude types: 15% Arab Light, 20% Kuwait, 10% Maya, 15% Western Canadian Select and 40% Mars compared to LLS.

Our realized refining and wholesale gross marketing margin in first quarter of 2011 improved despite the lower LLS 6-3-2-1 crack spread in the first quarter of 2011 compared to the first quarter of 2010. The increased margin is primarily due to a 140 percent widening of the sweet/sour differential and the wider than normal differentials between WTI and other light sweet crudes such as LLS and Dated Brent. Within our refining system, sour crude accounted for 54 percent of the crude oil processed in the first quarter of 2011 compared to 52 percent in the comparable period in 2010.

In addition to the market changes indicated by the crack spreads and sweet/sour differential, our refining and wholesale marketing gross margin is impacted by factors such as:

∙	the types of crude oil and other charge and blendstocks processed
∙	the selling prices realized for refined products
∙	the impact of commodity derivative instruments used to manage price risk
∙	the cost of products purchased for resale and
∙	changes in manufacturing costs which include depreciation.

Manufacturing costs are primarily driven by the cost of energy used by our refineries and the level of maintenance costs. Planned major maintenance activities, or turnarounds, requiring temporary shutdown of certain refinery operating units are periodically performed at each refinery.

Our retail marketing gross margin for gasoline and distillates, which is the difference between the ultimate price paid by consumers and the cost of refined products, including secondary transportation and consumer excise taxes, also impacts RM&T segment profitability. There are numerous factors including local competition, seasonal demand fluctuations, the available wholesale supply, the level of economic activity in our marketing areas and weather conditions that impact gasoline and distillate demand throughout the year. The gross margin on merchandise sold at retail outlets has been historically less volatile.

Results of Operations

Consolidated Results of Operations

Consolidated net income in the first quarter of 2011 was 118 percent higher than in the same quarter of 2010. Increasing liquid hydrocarbon prices and the RM&T segment refining and wholesale marketing gross margin contributed significantly to the income increase.


Revenues are summarized by segment in the following table:

	Three Months Ended March 31,
(In millions)	2011			2010
E&P	$	3,382		$	2,551
OSM		306			186
IG		64			27
RM&T		17,842			13,362
Segment revenues		21,594			16,126
Elimination of intersegment revenues		(690	)		(412	)
Total revenues	$	20,904		$	15,714

Items included in both revenues and costs and expenses:
Consumer excise taxes on petroleum products and merchandise	$	1,209		$	1,212

E&P segment revenues increased $831 million in the first quarter of 2011 from the comparable prior-year period primarily a result of higher liquid hydrocarbon realizations. Liquid hydrocarbon realizations averaged $95.79 per barrel in the first quarter of 2011 compared to $74.35 in the first quarter of 2010. Revenues in the first quarter of 2010 included gains on derivatives of $51 million. All derivative positions closed in December 2010.

Net sales volumes during the quarter averaged 400 mboepd, compared to 361 mboepd for the same period last year. This 11 percent increase in sales volumes reflects the liquid hydrocarbon and natural gas production increases previously discussed.

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


	Three Months Ended March 31,
	2011		2010

E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbpd)
United States		78		58

Europe		111		85
Africa		58		83
Total International		169		168
Worldwide		247		226

Natural Gas Sales (mmcfd)
United States		368		351

Europe(a)		102		109
Africa		446		353
Total International		548		462
Worldwide		916		813

Total Worldwide Sales (mboepd)
Worldwide		400		361

	Three Months Ended March 31,
	2011		2010

E&P Operating Statistics
Average Realizations (b)
Liquid Hydrocarbons (per bbl)
United States	$	86.42	$	72.46

Europe		109.85		78.95
Africa		81.47		70.96
Total International		100.10		75.01
Worldwide	$	95.79	$	74.35

Natural Gas (per mcf)
United States	$	5.15	$	5.49

Europe		10.29		6.17
Africa		0.25		0.25
Total International		2.12		1.65
Worldwide	$	3.34	$	3.31

(a)	Includes natural gas acquired for injection and subsequent resale of 15 mmcfd and 25 mmcfd for the first three months of 2011 and 2010.

(b)	Excludes gains and losses on derivative instruments.

OSM segment revenues increased $120 million in the first quarter of 2011 from the comparable prior-year period. The increase was driven primarily by a 15 percent increase in average realizations. Net synthetic crude sales for the first quarter of 2011 were 37 mbpd at an average realized price of $84.98 per barrel compared to 25 mbpd at $73.76 in the same period of 2010. The increased sales volumes are a result of the start-up of the Jackpine Mine in the fourth quarter of 2010.

Revenues in 2010 included a net loss of $10 million on derivative instruments intended to mitigate price risk related to future sales of synthetic crude. All derivative positions closed in December 2010.

IG segment revenues increased $37 million in the first quarter of 2011 from the comparable prior-year period, predominantly as a result of increased realizations.

RM&T segment revenues increased $4,480 million in the first quarter of 2011 from the comparable prior-year period, as a result of increased refined product selling prices and volumes. The wholesale benchmark prices are listed on the table below.

	Three Months Ended March 31,
(Dollars per gallon)	2011		2010
Chicago Spot Unleaded regular gasoline	$	2.57	$	2.02
Chicago Spot Ultra-low sulfur diesel		2.80		2.04
U.S. Gulf Coast Spot Unleaded regular gasoline		2.60		2.05
U.S. Gulf Coast Spot Ultra-low sulfur diesel	$	2.84	$	2.06

Income from equity method investments increased $21 million in the first quarter of 2011 from the comparable prior-year period. Higher commodity prices in the first quarter of 2011 compared to the same period of 2010 positively impacted the earnings of many of our equity method investees.

Net gain on disposal of assets in the first quarter of 2010 was primarily 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 $3,297 million in the first quarter of 2011 from the comparable prior-year period. The increase resulted primarily from higher acquisition costs and increased volumes of crude oil and refinery charge and blendstocks in the RM&T segment. Additionally, turnaround costs in the first quarter of 2011 were $180 million lower than in the same period of 2010 due to the timing of such projects in our RM&T and OSM segments.

Depreciation, depletion and amortization (“DD&A”) increased $203 million in the first quarter of 2011 compared to the same quarter of 2010. Increased DD&A related to the higher sales volumes in our E&P and OSM segments, as previously discussed.

Long-lived asset impairments in the first quarter of 2010 were primarily related to the Powder River Basin. In March 2010, our reservoir study concluded and a portion of our Powder River Basin field was removed from our plans for future development, resulting in a $423 million impairment (see Note 10).

Selling, general and administrative expenses increased during the first quarter of 2011 from the comparable prior year period primarily due to increased incentive compensation expense.

Exploration expenses were $230 million in the first quarter of 2011, including expenses related to dry wells of $159 million, primarily in the Gulf of Mexico and Indonesia. Exploration expenses were $98 million in the first quarter of 2010, including expenses related to dry wells of $32 million, primarily related to Alaska and Equatorial Guinea.

Provision for income taxes increased $250 million in the first quarter of 2011 from the comparable period of 2010 primarily due to the increase in pretax income. As discussed in Note 9 to the consolidated financial statements, we have suspended production operations in Libya, where the statutory tax rate is in excess of 90 percent. As a result, our effective income tax rate for the first quarter of 2011 was significantly lower than it was in the comparable period of 2010.

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

	Three Months Ended March 31,
	2011			2010
Statutory U.S. income tax rate		35	%		35	%
Effects of foreign operations, including foreign tax credits		2			14
Adjustments to valuation allowances		6			1
State and local income taxes, net of federal income tax effects		1			(1	)
Tax law change		-			5
Other tax effects		(1	)		(1	)
Effective income tax rate for continuing operations		43	%		53	%

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.”

Segment Results

Segment income is summarized in the following table:

	Three Months Ended March 31,
(In millions)	2011			2010
E&P

United States	$	30		$	109
International		638			393
E&P segment		668			502
OSM		32			(17	)
IG		60			44
RM&T		527			(237	)
Segment income		1,287			292
Corporate and other unallocated items		(90	)		(10	)
Foreign currency remeasurement of taxes		(14	)		33
Loss on extinguishment of debt		(176	)		-
Gain on disposition		-			449
Long-lived asset impairment		-			(262	)
Deferred income taxes - tax legislation changes		-			(45	)
Spin-off related costs		(11	)		-
Net income	$	996		$	457

United States E&P income decreased $79 million in the first quarter of 2011 compared to the same period of 2010. Increased realizations and sales volumes were offset by higher DD&A and exploration expense in the first quarter of 2011. In addition, the first quarter of 2010 benefited from a $51 million derivative gain. The commodity derivative contracts expired in December 2010.

International E&P income increased $245 million in the first quarter of 2011 compared to the same period of 2010. This increase in income is primarily related to a 33 percent increase in liquid hydrocarbon realizations. Partially offsetting the impact of realizations was higher DD&A and exploration expenses, including the dry well costs previously discussed.

OSM segment reported income of $32 million in the first quarter of 2011 compared to a loss of $17 million in the first quarter of 2010. The segment income increase in the first quarter of 2011 is primarily a result of the previously discussed higher realizations and increased volumes. The first quarter of 2010 included costs of $30 million related to a turnaround that began in March 2010 and a net loss on derivatives of $10 million. The derivative contracts expired in December 2010.

IG segment income increased $16 million in the first quarter of 2011 compared to the same period of 2010, primarily as a result of higher realizations and LNG sales volumes. LNG sales volumes in the first quarter of 2010 were impacted by the planned turnaround at our production facilities in Equatorial Guinea.

RM&T segment income increased $764 million in the first quarter of 2011 compared to the same period of 2010. The income increase was primarily a result of a higher refining and wholesale marketing gross margin, which was a positive 16.24 cents per gallon in the first quarter of 2011 compared to a negative 5.69 cents per gallon in the comparable period of 2010. Several factors contributed to the higher first quarter 2011 refining and wholesale marketing gross margin, including a wider sweet/sour differential, favorable crude acquisition costs resulting from wider than normal differentials between WTI and other light, sweet crudes such as LLS and Dated Brent, an increase in sour crude processed and lower planned turnaround and major maintenance costs of approximately $150 million, pretax.

Our refining and wholesale marketing gross margin also included pretax derivative losses of $58 million in the first quarter of 2011 compared to losses of $23 million in the first quarter of 2010.

Cash Flows and Liquidity

Cash Flows

Net cash provided by operating activities totaled $2,592 million in the first three months of 2011, compared to $849 million in the first three months of 2010 reflecting primarily the impact of higher liquid hydrocarbon and refined product prices on operating income.

Net cash used in investing activities totaled $833 million in the first three months of 2011, compared to $10 million in the first three months of 2010. Significant investing activities are additions to property, plant and equipment

and disposal of assets. In the first quarter 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 quarter of 2010 which was more focused upon the U.S., particularly the Gulf of Mexico. Spending has slowed compared to 2010 in our OSM segment as the upgrader portion of AOSP Expansion 1 began operations in May 2011. In the RM&T segment, the expansion and upgrading of our Detroit, Michigan refinery continues. In the first quarter of 2010, proceeds from the sale of a portion of our interest in Block 32 offshore Angola approximated spending on property, plant and equipment additions in the quarter.

Net cash provided by financing activities was $2 million in the first three months of 2011, compared to net cash used in financing activities of $172 million in the first three months of 2010. Dividends paid were a significant use of cash in both periods. During the first quarter of 2011, we issued $3 billion in Senior Notes and retired $2.5 billion principal amount of our debt.

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.

Activities Related to Plan to Create Independent Downstream Company

On February 1, 2011, MPC, currently a wholly owned subsidiary of Marathon, completed a private placement of three series of Senior Notes aggregating $3 billion (the "Notes"). The Notes are intended to establish a minimum $750 million initial cash balance for MPC upon the planned spin-off of Marathon's downstream business. All cash above that level will be used to repay existing intercompany debt with Marathon, and any remaining proceeds will be distributed to Marathon on or before June 30, 2011. The Notes are unsecured and unsubordinated obligations of MPC which are guaranteed by Marathon on a senior unsecured basis. Marathon's guarantees will terminate upon completion of the spin-off.

In February and March 2011, we retired $2.5 billion principal amount of debt at a weighted average price equal to 112 percent of face value, recognizing a $279 million loss on the early extinguishment of debt.

See Note 12 to the consolidated financial statements for more information about these transactions.

Capital Resources

At March 31, 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.

During the third quarter of 2010, we filed a universal shelf registration statement with the Securities and Exchange Commission, under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 10 percent at March 31, 2011, compared to 14 percent at December 31, 2010. This includes $231 million of debt that is serviced by United States Steel.

	March 31,			December 31,
(In millions)	2011			2010
Long-term debt due within one year	$	349		$	295
Long-term debt		7,992			7,601

Total debt	$	8,341		$	7,896

Cash	$	5,716		$	3,951
Equity	$	24,705		$	23,771

Calculation:

Total debt	$	8,341		$	7,896
Minus cash		5,716			3,951

Total debt minus cash	$	2,625		$	3,945

Total debt		8,341			7,896
Plus equity		24,705			23,771
Minus cash		5,716			3,951

Total debt plus equity minus cash	$	27,330		$	27,716

Cash-adjusted debt-to-capital ratio		10	%		14	%

Capital Requirements

On April 27, 2011, our Board of Directors approved a 25 cents per share dividend, payable June 10, 2011 to stockholders of record at the close of business on May 18, 2011.

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. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially are changes in prices of and demand for crude oil, natural gas and refined products, actions of competitors, disruptions or interruptions of our production, refining and mining operations due to unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other operating and economic considerations.

Contractual Cash Obligations

As of March 31, 2011, our consolidated contractual cash obligations have increased by $2,761 million from December 31, 2010. Our purchase obligations under crude oil, refinery feedstock, refined product and ethanol contracts, which are primarily short term, increased $2,497 million due to increased prices and volumes for crude oil when comparing March 31, 2011 to December 31, 2010. Long-term debt increased by $501 million due to the issuance of the $3 billion in Senior Notes and retirement of $2.5 billion principal amount of debt. Our obligations under contracts to acquire property, plant and equipment decreased $297 million due to the disposition of some of our outside-operated assets offshore Norway. There have been no other significant changes to our obligations to make future payments under existing contracts subsequent to December 31, 2010. The portion of our obligations to make future payments under existing contracts that have been assumed by United States Steel has not changed significantly subsequent to December 31, 2010.

Nonrecourse Indebtedness of Investees

Certain of our investees have incurred indebtedness that we do not support through guarantees or otherwise. If we were obligated to share in this debt on a pro rata ownership basis, our share would have been $248 million as of March 31, 2011.

Receivable from United States Steel

We remain obligated (primarily or contingently) for $231 million of certain debt and other financial arrangements for which United States Steel Corporation (“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 March 31, 2011 that it believes that its liquidity will be adequate to satisfy its obligations for the foreseeable future.

Critical Accounting Estimates

There have been no changes to our critical accounting estimates subsequent to December 31, 2010.

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.

We have finalized our strategic approach to comply with Mobile Source Air Toxics II (“MSAT II”) regulations related to benzene content in refined products and updated the project cost estimates to comply with these requirements. We estimate that we may spend approximately $650 million over a four-year period that began in 2008. Our actual MSAT II expenditures have totaled $555 million through March 31, 2011, with $33 million in the first quarter of 2011. We expect total year 2011 spending will be approximately $100 million. The cost estimates are forward-looking statements and are subject to change as further work is completed in 2011.

On January 21, 2011, the U.S. Environmental Protection Agency (“U.S. EPA”) issued a second waiver for the use of E15 under the Clean Air Act to allow for an increase in the amount of ethanol permitted to be blended into gasoline from 10 percent (“E10”) to 15 percent (“E15”) in vehicle model years 2001-2006. The first partial waiver was issued on October 13, 2010, for 2007 and newer light-duty motor vehicles. There are numerous issues, including state and federal regulatory issues, which would need to be addressed before E15 can be marketed for use in any traditional gasoline engines.

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

Other Contingencies

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 10 and Note 11 to the consolidated financial statements.

Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent increases and decreases in commodity prices on our open commodity derivative instruments as of March 31, 2011 is provided in the following table.


	Incremental Change in IFO from a Hypothetical Price Increase of						Incremental Change in IFO from a Hypothetical Price Decrease of
(In millions)		10	%		25	%		10	%		25	%
E&P Segment
Natural gas	$	(1	)	$	(3	)	$	1		$	3
RM&T Segment
Crude oil	$	(110	)	$	(283	)	$	129		$	324
Refined products		41			103			(42	)		(104	)

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective. During the quarter ended March 31, 2011, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended March 31,
(In millions)	2011			2010

Segment Income (Loss)
Exploration and Production
United States	$	30		$	109
International		638			393
E&P segment		668			502
Oil Sands Mining		32			(17	)
Integrated Gas		60			44
Refining, Marketing and Transportation		527			(237	)
Segment income		1,287			292
Items not allocated to segments, net of income taxes		(291	)		165
Net income	$	996		$	457
Capital Expenditures(a)
Exploration and Production
United States	$	349		$	458
International		319			145
E&P segment		668			603
Oil Sands Mining		120			265
Integrated Gas		1			1
Refining, Marketing and Transportation		200			310
Corporate		6			-
Total	$	995		$	1,179
Exploration Expenses
United States	$	151		$	46
International		79			52
Total	$	230		$	98

(a)	Capital expenditures include changes in accruals.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended March 31,
	2011		2010

E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbpd)
United States		78		58

Europe		111		85
Africa		58		83
Total International		169		168
Worldwide		247		226

Natural Gas Sales (mmcfd)
United States		368		351

Europe(b)		102		109
Africa		446		353
Total International		548		462
Worldwide		916		813

Total Worldwide Sales (mboepd)		400		361

Average Realizations
Liquid Hydrocarbons (per bbl)
United States	$	86.42	$	72.46

Europe		109.85		78.95
Africa		81.47		70.96
Total International		100.10		75.01
Worldwide	$	95.79	$	74.35

Natural Gas (per mcf)
United States	$	5.15	$	5.49

Europe		10.29		6.17
Africa(c)		0.25		0.25
Total International		2.12		1.65
Worldwide	$	3.34	$	3.31

(b)	Includes natural gas acquired for injection and subsequent resale of 15 mmcfd and 25 mmcfd for the first three 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.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended March 31,
(In millions, except as noted)	2011		2010

OSM Operating Statistics
Net Synthetic Crude Oil Sales (mbpd) (d)		37		25
Synthetic Crude Oil Average Realization (per bbl)(e)	$	84.98	$	73.76

IG Operating Statistics
Net Sales (mtpd) (f)
LNG		7,822		5,792
Methanol		1,318		1,158

RM&T Operating Statistics
Refinery Runs (mbpd)
Crude oil refined		1,114		1,003
Other charge and blendstocks		207		97
Total		1,321		1,100
Refined Product Yields (mbpd)
Gasoline		731		576
Distillates		408		306
Propane		24		20
Feedstocks and special products		116		116
Heavy fuel oil		21		14
Asphalt		49		77
Total		1,349		1,109

Refined Products Sales Volumes (mbpd) (g)		1,562		1,355

Refining and Wholesale Marketing Gross Margin (per gallon) (h)	$	0.1624	$	(0.0569	)
Speedway
Retail outlets		1,353		1,598
Gasoline and distillate sales (millions of gallons)		693		783
Gasoline and distillate gross margin (per gallon)	$	0.1308	$	0.1195
Merchandise sales	$	663	$	731
Merchandise gross margin	$	158	$	178

(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.

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

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

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 that 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.

Environmental Proceedings

In January 2011, the U.S. EPA notified us of 18 alleged violations of various statutory and regulatory provisions related to motor fuels, some of which we had previously self-reported to the U.S. EPA. No formal enforcement action has been commenced and no demand for penalties has been asserted by the U.S. EPA in connection with these alleged violations. However, it is possible that the U.S. EPA could seek penalties in excess of $100,000 in connection with one or more of the alleged violations. We met with the U.S. EPA on March 7, 2011 at their request, to provide additional information concerning one of the allegations.

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.

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

01/01/11 – 01/31/11		1,278		$	37.46		-	$	2,080,366,711
02/01/11 – 02/28/11		28,643		$	48.04		-	$	2,080,366,711
03/01/11 – 03/31/11		30,897	(c)	$	49.07		-	$	2,080,366,711
Total		60,818		$	48.34		-

(a)	30,018 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.

(b)

Under the terms of the transaction whereby 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 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 first 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)

30,794 shares were purchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon.

(d)

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 March 31, 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. No shares have been repurchased under this program since August 2008.

Item 6. Exhibits

Exhibit Number

Incorporated by Reference

Filed Herewith

Furnished Herewith

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

3.1

Amended By-laws of Marathon Oil Corporation

12.1

Computation of Ratio of Earnings to Fixed Charges.

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase.

101.DEF

XBRL Taxonomy Extension Definition Linkbase.

101.LAB

XBRL Taxonomy Extension Label Linkbase.

SIGNATURES

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

May 6, 2011	MARATHON OIL CORPORATION

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