Edgar Filing: MARATHON OIL CORP

form10q2012q1.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, 2012

[ ]	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 Street, 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 ü 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 ü 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 ü	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 ü

There were 705,319,440 shares of Marathon Oil Corporation common stock outstanding as of March 31, 2012

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended March 31, 2012

	INDEX
		Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)		2
	Consolidated Statements of Comprehensive Income (Unaudited)		3
	Consolidated Balance Sheets (Unaudited)		4
	Consolidated Statements of Cash Flows (Unaudited)		5
	Notes to Consolidated Financial Statements (Unaudited)		6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		26
Item 4.	Controls and Procedures		26
	Supplemental Statistics (Unaudited)		27
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		29
Item 1A.	Risk Factors		29
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		29
Item 4.	Mine Safety Disclosures		29
Item 6.	Exhibits		30
	Signatures		32

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

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)	2012			2011
Revenues and other income:

Sales and other operating revenues	$	3,777		$	3,656
Sales to related parties		14			15
Income from equity method investments		78			117
Net gain on disposal of assets		166			5
Other income		5			16

Total revenues and other income		4,040			3,809

Costs and expenses:
Cost of revenues (excludes items below)		1,407			1,404
Purchases from related parties		63			56
Depreciation, depletion and amortization		574			635
Impairments		262			-
General and administrative expenses		120			137
Other taxes		78			58
Exploration expenses		142			230

Total costs and expenses		2,646			2,520

Income from operations		1,394			1,289
Net interest and other		(50	)		(19	)
Loss on early extinguishment of debt		-			(279	)

Income from continuing operations before income taxes		1,344			991
Provision for income taxes		927			536

Income from continuing operations		417			455

Discontinued operations		-			541

Net income	$	417		$	996


Per Share Data

Basic:
Income from continuing operations	$	0.59		$	0.64
Discontinued operations	$	-		$	0.76
Net income	$	0.59		$	1.40

Diluted:
Income from continuing operations	$	0.59		$	0.64
Discontinued operations	$	-		$	0.75
Net income	$	0.59		$	1.39

Dividends paid	$	0.17		$	0.25

Weighted average shares:
Basic		706			711
Diluted		710			715

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)	2012			2011
Net income	$	417		$	996
Other comprehensive income

Postretirement and post-employment plans
Change in actuarial gain		13			33
Income tax provision on postretirement and post-employment plans		(5	)		(12	)
Postretirement and post-employment plans, net of tax		8			21

Derivative hedges
Net unrecognized gain		-			9
Income tax provision on derivatives		-			(4	)
Derivative hedges, net of tax		-			5

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

Other comprehensive income		9			26

Comprehensive income	$	426		$	1,022

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)	2012			2011
Assets
Current assets:
Cash and cash equivalents	$	513		$	493
Receivables, less allowance for doubtful accounts of zero		2,198			1,917
Receivables from related parties		35			35
Inventories		296			361
Prepayments		83			96
Deferred tax assets		87			99
Other current assets		233			223

Total current assets		3,445			3,224

Equity method investments		1,353			1,383
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $17,184 and $17,248		25,365			25,324
Goodwill		525			536
Other noncurrent assets		1,163			904

Total assets	$	31,851		$	31,371
Liabilities
Current liabilities:
Accounts payable	$	2,029		$	1,864
Payables to related parties		10			18
Payroll and benefits payable		165			193
Accrued taxes		2,065			2,015
Other current liabilities		207			163
Long-term debt due within one year		197			141

Total current liabilities		4,673			4,394

Long-term debt		4,559			4,674
Deferred income taxes		2,540			2,544
Defined benefit postretirement plan obligations		747			789
Asset retirement obligations		1,437			1,510
Deferred credits and other liabilities		389			301

Total liabilities		14,345			14,212

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 – 65 million and 66 million shares		(2,652	)		(2,716	)
Additional paid-in capital		6,658			6,680
Retained earnings		13,084			12,788
Accumulated other comprehensive loss		(361	)		(370	)
Total equity of Marathon Oil's stockholders		17,499			17,152
Noncontrolling interest		7			7
Total stockholders' equity		17,506			17,159

Total liabilities and stockholders' equity	$	31,851		$	31,371

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)	2012			2011
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	417		$	996
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations		-			(541	)
Loss on early extinguishment of debt		-			279
Deferred income taxes		(22	)		(220	)
Depreciation, depletion and amortization		574			635
Impairments		262			-
Pension and other postretirement benefits, net		(29	)		14
Exploratory dry well costs and unproved property impairments		58			173
Net gain on disposal of assets		(166	)		(5	)
Equity method investments, net		(21	)		(47	)
Changes in:
Current receivables		(296	)		(158	)
Inventories		7			29
Current accounts payable and accrued liabilities		213			361
All other operating, net		(24	)		117
Net cash provided by continuing operations		973			1,633
Net cash provided by discontinued operations		-			959
Net cash provided by operating activities		973			2,592
Investing activities:
Additions to property, plant and equipment		(1,017	)		(819	)
Disposal of assets		208			87
Investments - return of capital		15			8
Investing activities of discontinued operations		-			(122	)
All other investing, net		(12	)		13
Net cash used in investing activities		(806	)		(833	)
Financing activities:
Debt repayments		(53	)		(2,809	)
Dividends paid		(121	)		(178	)
Financing activities of discontinued operations		-			2,939
All other financing, net		17			50
Net cash provided by (used in) financing activities		(157	)		2
Effect of exchange rate changes on cash		10			4
Net increase in cash and cash equivalents		20			1,765
Cash and cash equivalents at beginning of period		493			3,951
Cash and cash equivalents at end of period	$	513		$	5,716

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

These consolidated financial statements are unaudited; however, in the opinion of management these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America for complete financial statements.

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

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation (“Marathon Oil”) 2011 Annual Report on Form 10-K. The results of operations for the quarter ended March 31, 2012, are not necessarily indicative of the results to be expected for the full year.

2. Spin-off Downstream Business

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

The following table presents selected financial information regarding the results of operations of our downstream business reported as discontinued operations.

(In millions)	Three Months Ended March 31, 2011
Revenues applicable to discontinued operations	$	17,842
Pretax income from discontinued operations		768

3. Accounting Standards

Recently Adopted

In September 2011, the Financial Accounting Standards Board (“FASB”) amended accounting standards to simplify how entities test goodwill for impairment. The amendment reduces complexity by allowing an entity the option to make a qualitative evaluation of whether it is necessary to perform the two-step goodwill impairment test. The amendment is effective for our interim and annual periods beginning with the first quarter of 2012. Adoption of this amendment did not have a significant impact on our consolidated results of operations, financial position or cash flows.

The FASB amended the reporting standards for comprehensive income in June 2011 to eliminate the option to present the components of Other Comprehensive Income (“OCI”) as part of the statement of changes in stockholders' equity. All non-owner changes in stockholders’ equity are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of OCI, and total comprehensive income. The presentation of items that are reclassified from OCI to net income on the income statement is also required. The amendments did not change the items that must be reported in OCI or when an item of OCI must be reclassified to net income. The amendments are effective for us beginning with the first quarter of 2012, except for the presentation of reclassifications, which has been deferred. Adoption of these amendments did not have a significant impact on our consolidated results of operations, financial position or cash flows.

In May 2011, the FASB issued an update amending the accounting standards for fair value measurement and disclosure, resulting in common principles and requirements under accounting principles generally accepted in the U.S. (“U.S. GAAP”) and International Financial Reporting Standards (“IFRS”). The amendments change the wording used to describe certain of the U.S. GAAP requirements either to clarify the intent of existing requirements, to change measurement or expand disclosure principles or to conform to the wording used in IFRS. The amendments are to be applied prospectively for our interim and annual periods beginning with the first quarter of 2012. The adoption of the amendments did not have a significant impact on our consolidated results of operations, financial position or cash flows. To the extent they were necessary in this quarter, we have made the expanded disclosures in Note 13.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

4. 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 and Jackpine mines, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with a $3 million current liability recorded at March 31, 2012. 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 $724 million as of March 31, 2012. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.

5. Income per Common Share

Basic income per share is based on the weighted average number of common shares outstanding, 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,
	2012						2011
(In millions, except per share data)	Basic			Diluted			Basic		Diluted

Income from continuing operations		$	417		$	417	$	455		$	455
Discontinued operations			-			-		541			541
Net income		$	417		$	417	$	996		$	996

Weighted average common shares outstanding			706			706		711			711
Effect of dilutive securities			-			4		-			4
Weighted average common shares, including
dilutive effect			706			710		711			715

Per share:
Income from continuing operations		$	0.59		$	0.59	$	0.64		$	0.64
Discontinued operations		$	-		$	-	$	0.76		$	0.75
Net income		$	0.59		$	0.59	$	1.40		$	1.39

The per share calculations above exclude 7 million and 5 million stock options and stock appreciation rights for the first three months of 2012 and 2011, that were antidilutive.

6. Acquisitions

In April 2012, we entered into agreements to acquire approximately 20,000 net acres in the core of the Eagle Ford shale formation in transactions valued at $767 million, subject to closing adjustments. The majority of these transactions in terms of value are expected to close in the third quarter of 2012.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

7. Dispositions

2012

On January 3, 2012, we closed on the sale of our Exploration and Production (“E&P”) segment’s interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million. This includes our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system. A pretax gain of $166 million was recorded in the first quarter of 2012.

In April 2012, we entered into agreements to sell all of our E&P segment’s assets in Alaska. The transactions are expected to close in the second half of 2012, pending regulatory approval and closing conditions. Substantially all of these assets are reflected as held for sale in the March 31, 2012 balance sheet as follows:

(In millions)
Other current assets	$	59
Other noncurrent assets		185
Total assets		244

Deferred credits and other liabilities		87
Total liabilities	$	87

2011

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 of 2010.

8. Segment Information

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

·	E&P – explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis;

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

·	Integrated Gas (“IG”) – produces and markets products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, in Equatorial Guinea.

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). 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. Impairments, gains or losses on disposal of assets or other items that affect comparability (as determined by the CODM) also 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. Total capital expenditures include accruals but not corporate activities.

As discussed in Note 2, our downstream business was spun-off on June 30, 2011 and has been reported as discontinued operations in 2011.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Three Months Ended March 31, 2012
(In millions)	E&P		OSM		IG		Total

Revenues:
Customer	$	3,398	$	379	$	-	$	3,777
Related parties		14		-		-		14
Total revenues	$	3,412	$	379	$	-	$	3,791
Segment income	$	477	$	41	$	4	$	522
Income from equity method investments		64		-		14		78
Depreciation, depletion and amortization		516		49		-		565
Income tax provision		1,036		14		1		1,051
Capital expenditures		1,001		52		-		1,053

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

Revenues:
Customer	$	3,286		$	306	$	64	$	3,656
Intersegment		26			-		-		26
Related parties		15			-		-		15
Segment revenues		3,327			306		64		3,697
Elimination of intersegment revenues		(26	)		-		-		(26	)
Total revenues	$	3,301		$	306	$	64	$	3,671
Segment income	$	668		$	32	$	60	$	760
Income from equity method investments		58			-		59		117
Depreciation, depletion and amortization		586			37		2		625
Income tax provision		612			10		26		648
Capital expenditures		668			120		1		789

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

	Three Months Ended March 31,
(In millions)	2012			2011
Segment income	$	522		$	760
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(29	)		(115	)
Foreign currency remeasurement of taxes		(15	)		(14	)
Loss on early extinguishment of debt		-			(176	)
Impairment(a)		(167	)		-
Gain on dispositions(b)		106			-
Income from continuing operations		417			455
Discontinued operations		-			541
Net income	$	417		$	996

(a)	Significant impairments are further discussed, on a pretax basis, in Note 13.

(b)	Significant dispositions are further discussed, on a pretax basis, in Note 7.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

	Three Months Ended March 31,
(In millions)	2012			2011
Total revenues		$	3,791	$	3,671
Less: Sales to related parties			14		15
Sales and other operating revenues		$	3,777	$	3,656

9. 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)	2012			2011			2012			2011
Service cost	$	12		$	13		$	1		$	1
Interest cost		16			17			4			4
Expected return on plan assets		(16	)		(17	)		-			-
Amortization:
– prior service cost (credit)		2			1			(2	)		(2	)
– actuarial loss		12			13			-			-
Net periodic benefit cost	$	26		$	27		$	3		$	3

During the first three months of 2012, we made contributions of $51 million to our funded pension plans. We expect to make additional contributions up to an estimated $62 million to our funded pension plans over the remainder of 2012. Current benefit payments related to unfunded pension and other postretirement benefit plans were $5 million and $4 million during the first three months of 2012.

10. Income Taxes

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. 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 8.

Our effective tax rate in the first quarter of 2012 is 69 percent. This rate is higher than the U.S. statutory rate of 35 percent primarily due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax rate is in excess of the U.S. statutory rate. An increase in earnings and associated taxes from foreign jurisdictions, primarily Norway, as compared to prior periods caused an increase in our valuation allowance on current year foreign tax credits. In Libya, where the statutory tax rate is in excess of 90 percent, limited production resumed in the fourth quarter of 2011 and liquid hydrocarbon sales resumed in the first quarter of 2012. A reliable estimate of 2012 annual ordinary income from our Libyan operations cannot be made and the range of possible scenarios when including ordinary income from our Libyan operations in the worldwide annual effective tax rate calculation demonstrates significant variability. As such, for the three months ended March 31, 2012, an estimated annual effective tax rate was calculated excluding Libya and applied to consolidated ordinary income excluding Libya and the tax provision applicable to Libyan ordinary income was recorded as a discrete item in the period. Excluding Libya, the effective tax rate would be 64 percent for the first quarter of 2012.

Our effective tax rate in the first quarter of 2011 was 54 percent which is higher than the U.S. statutory tax rate of 35 percent primarily due to earnings from foreign jurisdictions where the tax rate is in excess of the U.S. statutory rate and the valuation allowance recorded against 2011 foreign tax credits.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table summarizes the activity in unrecognized tax benefits:

	Three Months Ended March 31,
(In millions)	2012			2011
Beginning balance	$	157		$	103
Additions based on tax positions related to the current year		1			1
Reductions based on tax positions related to the current year		-			(1	)
Additions for tax positions of prior years		52			36
Reductions for tax positions of prior years		(55	)		(6	)
Settlements		(1	)		-
Ending balance	$	154		$	133

If the unrecognized tax benefits as of March 31, 2012 were recognized, $104 million would affect our effective income tax rate. There were $21 million of uncertain tax positions as of March 31, 2012 for which it is reasonably possible that the amount of unrecognized tax benefits would decrease during the next twelve months.

11. Inventories

Inventories are carried at the lower of cost or market value.

	March 31,			December 31,
(In millions)	2012			2011
Liquid hydrocarbons, natural gas and bitumen		$	73		$	147
Supplies and sundry items			223			214
Total inventories		$	296		$	361

12. Property, Plant and Equipment

	March 31,			December 31,
(In millions)	2012			2011
E&P
United States	$	19,422		$	19,679
International		12,717			12,579
Total E&P		32,139			32,258
OSM		9,988			9,936
IG		37			37
Corporate		385			341
Total property, plant and equipment		42,549			42,572
Less accumulated depreciation, depletion and amortization		(17,184	)		(17,248	)
Net property, plant and equipment	$	25,365		$	25,324

In the first quarter 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed and during the first quarter of 2012, sales volumes were 17 thousand barrels per day. The return of our operations in Libya to pre-conflict levels is unknown at this time; however, we and our partners in the Waha concessions are assessing the condition of our assets and determining when the full resumption of operations will be viable.

Exploratory well costs capitalized greater than one year after completion of drilling were $255 million as of March 31, 2012 an increase of $33 million from December 31, 2011, primarily related to the Caterpillar discovery in Norway which was drilled in the first quarter of 2011. Data from the Boyla development, which is being submitted to the Norwegian government for approval, will be used to determine the best plan of development for the Caterpillar discovery.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

13. Fair Value Measurements

Fair Values – Recurring

As of March 31, 2012 and December 31, 2011, balances related to interest rate swaps accounted for at fair value on a recurring basis were noncurrent assets of $4 million and $5 million. Foreign currency forwards accounted for at fair value on a recurring basis were current liabilities of $8 million at March 31, 2012.

Interest rate swaps are measured at fair value using actionable broker quotes which are Level 2 inputs. Foreign currency forwards are measured at fair value with a market approach using third-party pricing services, such as Bloomberg L.P., which have been corroborated with data from active markets for similar assets and liabilities, and are Level 2 inputs.

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)	2012		2011
Beginning balance	$	-	$	(2	)
Included in net income		-		(1	)
Settlements		-		2
Ending balance	$	-	$	(1	)

Net income for the quarter ended March 31, 2011 included unrealized losses of $1 million related to Level 3 derivatives held on that date. See Note 14 for the impacts of all derivative instruments on our consolidated statements of income.

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,
	2012					2011
(In millions)		Fair Value		Impairment			Fair Value		Impairment

Long-lived assets held for use			75		262		$	-	$	-

Our E&P segment’s Ozona development in the Gulf of Mexico began production in December 2011. During the first quarter of 2012, production rates declined significantly and have remained below initial expectations. Accordingly, our reserve engineers performed an evaluation of our future production as well as our reserves which concluded in early April 2012. This resulted in a 2 million barrel of oil equivalent reduction in proved reserves and a $261 million impairment charge in the first quarter of 2012. The fair value of the Ozona development was determined using an income approach based upon internal estimates of future production levels, prices and discount rate, all Level 3 inputs. Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated liquid hydrocarbon prices based on the Louisiana Light Sweet 12-month price range, as we think production will not be significant beyond twelve months, adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

Included in the total impairments above are an additional $1 million in impairments relating to other long-lived assets held for use in our E&P segment that were a result of reduced drilling expectations, reduction of estimated reserves or declining natural gas prices. The fair values of those assets were measured using an income approach based upon internal estimates of future production levels, commodity prices and discount rate, which are Level 3 inputs. Natural gas prices began declining in September 2011 and have continued to decline in 2012. Should natural gas prices remain depressed, impairment charges related to our natural gas assets may be necessary.

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, 2012, and December 31, 2011.

	March 31, 2012				December 31, 2011
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other current assets	$	142	$	143	$	146	$	148
Other noncurrent assets		107		107		68		68
Total financial assets		249		250		214		216
Financial liabilities
Long-term debt, including current portion(a)		5,431		4,700		5,479		4,753
Deferred credits and other liabilities		54		53		36		38
Total financial liabilities	$	5,485	$	4,753	$	5,515	$	4,791

(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 these 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. An exception to this assessment is the current portion of our long-term debt, which is reported with long-term debt above and discussed below.

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.

14. Derivatives

For information regarding the fair value measurement of derivative instruments see Note 13. The following table presents the gross fair values of derivative instruments and where they appear on the consolidated balance sheet as of March 31, 2012.

	March 31, 2012
(In millions)	Asset			Liability			Net Asset			Balance Sheet Location
Fair Value Hedges
Interest rate		$	4		$	-		$	4	Other noncurrent assets
Total Designated Hedges			4			-			4
Total		$	4		$	-		$	4

	March 31, 2012
(In millions)		Asset			Liability			Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency		$	-		$	8		$	8	Other current liabilities
Total Designated Hedges			-			8			8
Total		$	-		$	8		$	8

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

As of December 31, 2011, our only derivatives outstanding were interest rate swaps that were fair value hedges, which had an asset value of $5 million and are located on the consolidated balance sheet in Other noncurrent assets.

Derivatives Designated as Cash Flow Hedges

As of March 31, 2012, no derivatives were designated as cash flow hedges.

Derivatives Designated as Fair Value Hedges

As of March 31, 2012, we had multiple interest rate swap agreements with a total notional amount of $600 million at a weighted average, London Interbank Offered Rate (“LIBOR”) based, floating rate of 4.73 percent.

Foreign currency forwards designated as fair value hedges at March 31, 2012 had an aggregate notional amount of 3,954 million Norwegian Kroner at a weighted average forward rate of 5.642. These forwards hedge our current Norwegian tax liability and have settlement dates April through August 2012.

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	2012			2011
Derivative
Interest rate	Net interest and other	$	(1	)	$	(4	)
Foreign currency	Provision for income taxes		(8	)		-
			(9	)		(4	)
Hedged Item
Long-term debt	Net interest and other		1			4
Accrued taxes	Provision for income taxes		8			-
		$	9		$	4

Derivatives not Designated as Hedges

As of March 31, 2012, commodity derivatives not designated as hedges included a gain of $2 million that appears on the sales and other operating revenues line of our consolidated income statement.

15. Debt

At March 31, 2012, we had no borrowings outstanding against our existing $3 billion revolving credit facility or under our U.S. commercial paper program backed by the revolving credit facility. During the first quarter of 2012, $100 million of commercial paper was issued and repaid.

During the first quarter of 2012, $53 million principal amount of debt carrying a 9.375 percent interest rate was repaid at maturity.

In April 2012, we terminated our $3.0 billion five-year revolving credit facility and replaced it with a new $2.5 billion unsecured five-year revolving credit facility (the “Credit Facility”). The Credit Facility matures in April 2017 but allows us to request two, one-year extensions. It contains an option to increase the commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, and includes sub-facilities for swing-line loans and letters of credit up to an aggregate amount of $100 million and $500 million, respectively. Fees on the unused commitment of each lender range from 10 basis points to 25 basis points per year depending on our credit ratings. Borrowings under the Credit Facility bear interest, at our option, at either (a) the adjusted LIBOR plus a margin ranging from 87.5 basis points to 162.5 basis points per year depending on our credit ratings or (b) the Base Rate plus a margin ranging from 0.0 basis points to 62.5 basis points depending on our credit ratings. Base Rate is defined as a per annum rate equal to the greatest of (a) the prime rate, (b) the federal funds rate plus one-half of one percent and (c) LIBOR for a one-month interest period plus 1 percent.

The agreement contains a covenant that requires our ratio of total debt to total capitalization not exceed 65 percent as of the last day of each fiscal quarter. If an event of default occurs, the lenders may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited

In February and March 2011, we retired $2,948 million principle amount of debt at a weighted average price equal to 1.12 percent of face value. A $279 million loss on early extinguishment of debt was recognized in the first quarter of 2011. The loss included related deferred financing and premium costs partially offset by the gain on settled interest rate swaps.

16. Incentive Based Compensation

The following table presents a summary of stock option award and restricted stock award activity for the three-month period ended March 31, 2012:

	Stock Options					Restricted Stock
				Weighted					Weighted
	Number of			Average		Number of			Average Grant
	Shares			Exercise Price		Awards			Date Fair Value
Outstanding at December 31, 2011		21,370,715		$	24.41		3,703,978		$	25.88
Granted (a)		1,462,779			35.06		1,167,013			34.95
Options exercised/Stock vested		(720,897	)		19.55		(208,135	)		18.42
Canceled		(131,524	)		27.05		(51,966	)		25.54
Outstanding at March 31, 2012		21,981,073		$	25.27		4,610,890		$	28.51

(a) The weighted average grant date fair value of stock option awards granted was $11.62 per share.

Performance unit awards

During the first quarter of 2012, we granted 13 million performance units to executive officers. These units have a 36-month performance period.

17. Supplemental Cash Flow Information

	Three Months Ended March 31,
(In millions)	2012			2011
Net cash provided from operating activities:
Interest paid (net of amounts capitalized)	$	50		$	69
Income taxes paid to taxing authorities		828			605
Commercial paper and revolving credit arrangements, net:
Commercial paper - issuances	$	100		$	-
- repayments		(100	)		-
Total	$	-		$	-
Noncash investing activities:
Change in capital expenditure accrual	$	46		$	(24	)

18. Commitments and Contingencies

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

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

Contractual commitments – At March 31, 2012, our contract commitments to acquire property, plant and equipment totaled $2,775 million.

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

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

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

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2011 Annual Report on Form 10-K.

Key Operating and Financial Activities

In the first quarter of 2012, notable items were:

·	Net liquid hydrocarbon and natural gas sales volumes of 383 thousand barrels of oil equivalent per day (“mboed”), of which 62 percent was liquid hydrocarbons

·	Net international liquid hydrocarbon sales volumes, for which average realizations have exceeded West Texas Intermediate (“WTI”) crude oil, were 62 percent of total liquid hydrocarbon sales

·	Resumed liftings from Libya for average net sales of 17 mboed and production available for sale of 35 mboed

·	Net synthetic crude oil sales of 44 thousand barrels per day (“mbbld”), a 19 percent increase over the same period of last year

·	Average net sales volumes of 26 mboed from the Bakken shale, an 86 percent increase over the same quarter of last year

·	Average net sales volumes of 14 mboed from the Eagle Ford shale, with 17 dedicated drilling rigs and 4 dedicated hydraulic fracturing crews working in the Eagle Ford shale

·	Gulf of Mexico Ozona development impairment of $261 million due to a 2 million barrels of oil equivalent (“mmboe”) reduction in estimated proved reserves

·	Cash-adjusted debt-to-capital ratio of 20 percent

·	Disposed of our interests in several Gulf of Mexico crude oil pipeline systems for a pretax gain of $166 million

Some significant April 2012 activities include:

·	Replaced existing revolving credit facility with a new $2.5 billion facility maturing April 2017

·	Entered an agreement to dispose of all of our assets in Alaska

·	Entered multiple agreements to expand holdings in the core of the Eagle Ford shale by approximately 20,000 net acres

Overview and Outlook

Exploration and Production

Production

Net liquid hydrocarbon and natural gas sales averaged 383 mboed during the first quarter of 2012 compared to 400 mboed in the same quarter of 2011. Net liquid hydrocarbon sales volumes increased in the U.S., reflecting the impact of the Eagle Ford shale assets acquired in the fourth quarter of 2011 and our ongoing development programs in the Eagle Ford, Bakken and other U.S. unconventional resource plays. Net liquid hydrocarbon sales volumes from the U.K. were lower in the first quarter of 2012 than in the same period of 2011 due to unplanned repairs at Foinaven and the timing of liftings.

In the Eagle Ford shale, we had 17 operated rigs drilling and four hydraulic fracturing crews working as of March 31, 2012. Net liquid hydrocarbon sales were 14 mboed for the first quarter of 2012. To complement drilling and completions activity, we continue to build infrastructure to support production growth across the operating area. Approximately 90 miles of gathering lines were installed in the first quarter of 2012, in addition to two new central gathering and treating facilities, with six additional facilities currently under construction.

First quarter 2012 average net sales volumes from the Bakken shale were 26 mboed compared to 14 mboed in the same quarter of 2011. Our Bakken liquid hydrocarbon volumes average approximately 95 percent crude oil. We have eight drilling rigs and three hydraulic fracturing crews working in the play. Additionally, our drilling pace has exceeded expectations this year with improved “spud-to-spud” drilling times.

In the Anadarko Woodford shale, net sales volumes averaged 5 mboed during the first quarter of 2012 compared to 1 mboed in the same quarter of 2011. We have six drilling rigs working in the Anadarko Woodford play, where performance is being driven by continued strong results in the Cana core area, and additional operated activity on our Knox acreage position. We are planning to begin an 80-acre infill project in the Knox area in May 2012.

In the first quarter 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed and during the first quarter of 2012, sales volumes were 17 mboed. The return of our operations in Libya to pre-conflict levels is unknown at this time; however, we and our partners in the Waha concessions are assessing the condition of our assets.

A 28-day turnaround began at our production operations in Equatorial Guinea on March 23, 2012. It was completed in April 2012 seven days ahead of schedule and below budget.

Exploration

During the first quarter of 2012, on the Birchwood oil sands lease located in Alberta, Canada, we conducted a seismic survey and drilled six water wells. We also submitted a regulatory application for a proposed 12 mbbld steam assisted gravity drainage (“SAGD”) project at Birchwood. Pending regulatory approval, construction is expected to begin in 2014, with first oil projected in 2016. We have a 100 percent working interest in Birchwood.

Acquisitions and Divestitures

On January 3, 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million. This includes our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system. A pretax gain of $166 million was recorded in the first quarter of 2012.

In April 2012, we entered agreements to sell all our assets in Alaska. The transactions are expected to close in the second half of 2012, pending regulatory approval and closing conditions.

In April 2012, we entered multiple agreements to acquire approximately 20,000 net acres in the core of the Eagle Ford shale formation in transactions valued at $767 million, subject to closing adjustments. The majority of the transactions in terms of value are expected to close in the third quarter of 2012. In addition to undeveloped acreage, on the date of the agreements, these transactions included 13 gross wells producing 7 net mboed. Approximately 45 percent of the acreage is held by production.

The above discussions include forward-looking statements with respect to the timing of the commencement of construction and first oil on the SAGD project, the sale of the Alaska assets, and acquisitions in the Eagle Ford shale. The timing of the commencement of construction and first oil on the SAGD project can be affected by delays in obtaining and conditions imposed by necessary government and third-party approvals, board approval, transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, and other risks associated with construction projects. The completion of the sale of substantially all of the Alaska assets is subject to necessary government and regulatory approvals and customary closing conditions. The sale of the Alaska drilling rig is subject to the buyer’s exercise of its purchase right under the purchase and sale agreement. The acquisitions in the Eagle Ford shale are 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 OSM operations consist of a 20 percent non-operated working interest in the Athabasca Oil Sands Project (“AOSP”). Our net synthetic crude oil sales were 44 mbbld in the first quarter of 2012 compared to 37 mbbld in the same quarter of 2011. This sales increase is primarily due to less downtime for planned and unplanned maintenance in the 2012 period.

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.

Integrated Gas

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. Our share of LNG sales totaled 6,291 metric tonnes per day (“mtd”) for the first quarter of 2012 compared to 7,822 mtd in the first quarter of 2011. LNG sales volumes are down because the first quarter of 2011 also included LNG sales from Alaska which were conducted through a consolidated subsidiary. LNG sales from Alaska ceased when our interest was sold in the third quarter of 2011. Also, a 30-day turnaround began at the LNG facility in Equatorial Guinea on March 23, 2012. Full production resumed ahead of schedule on April 17, 2012.

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 2012 compared to the same period in 2011.

	Three Months Ended March 31,
	2012		2011
West Texas Intermediate ("WTI") crude oil (Dollars per bbl)	$	103.03	$	94.60
Brent (Europe) crude oil (Dollars per bbl)	$	118.49	$	104.96
Henry Hub natural gas (Dollars per million British thermal units ("mmbtu"))(a)	$	2.74	$	4.11

(a)	Settlement date average.

In the first quarter of 2012, average crude oil benchmark prices increased compared to the same quarter of 2011. The average differential of Brent to WTI was a premium of approximately $15 per barrel in the first quarter of 2012. Our international crude oil production is relatively sweet and a majority is sold in relation to the Brent crude oil benchmark.

Our domestic crude oil production was about 47 percent sour in the first quarter of 2012 compared to 70 percent in the first quarter of 2011. Reduced production from the Gulf of Mexico and increased onshore production from the Bakken and Eagle Ford shales contributed to the lower sour crude percentage. 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.

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. Average Henry Hub settlement prices for natural gas were lower for the first quarter of 2012 compared to the same quarter of the prior year. A decline in average settlement date Henry Hub natural gas prices began in September 2011 and has continued beyond the first quarter of 2012 with April averaging $2.19 per mmbtu. Should U.S. natural gas prices remain depressed, impairment charges related to our natural gas assets may be necessary.

Our other major natural gas-producing regions are Europe and Equatorial Guinea. Natural gas prices in Europe have been higher than the U.S. in recent periods. In the case of Equatorial Guinea, our natural gas sales are subject to term contracts, making realized prices in these areas less volatile. The natural gas sales from Equatorial Guinea are 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. Recently AECO prices have declined, much as Henry Hub prices have. We would expect a significant, continued decline in natural gas prices to have a favorable impact on OSM operating costs.

The table below shows benchmark prices that impacted both our revenues and variable costs for the first quarter of 2012 compared to first quarter of 2011.

	Three Months Ended March 31,
Benchmark	2012		2011
WTI crude oil (Dollars per barrel)	$	103.03	$	94.60
Western Canadian Select (Dollars per barrel)(a)	$	81.51	$	71.24
AECO natural gas sales index (Dollars per mmbtu)(b)	$	2.18	$	3.85

(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, in Equatorial Guinea

We have a 60 percent ownership in an LNG production facility in Equatorial Guinea, which sells LNG under a long-term contract at prices tied to Henry Hub natural gas 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 2 percent of 2011 estimated world demand.

Results of Operations

Consolidated Results of Operations

Due to the spin-off of our downstream business on June 30, 2011, which is reported as discontinued operations, income from continuing operations is more representative of Marathon Oil as an independent energy company. Consolidated income from continuing operations before income taxes in the first quarter of 2012 was 36 percent higher than in the same quarter of 2011 primarily due to increased liquid hydrocarbon prices. As a result of increased income from continuing operations before tax in higher tax jurisdictions, primarily Norway, the effective tax rate was 69 percent in the first quarter of 2012 compared to 54 percent in the first quarter of 2011.

Revenues are summarized by segment in the following table:

	Three Months Ended March 31,
(In millions)	2012		2011
E&P	$	3,412	$	3,327
OSM		379		306
IG		-		64
Segment revenues		3,791		3,697
Elimination of intersegment revenues		-		(26	)
Total revenues	$	3,791	$	3,671

E&P segment revenues increased $85 million in the first quarter of 2012 from the comparable prior-year period. Included in our E&P segment are supply optimization activities which include the purchase of commodities from third parties for resale. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points. See the Cost of revenues discussion as revenues from supply optimization approximate the related costs. Higher average crude oil prices in the first quarter of 2012 increased revenues related to supply optimization.

Revenues from the sale of our U.S. production are higher in the first quarter of 2012 primarily as a result of higher liquid hydrocarbon sales volumes and price realizations, partially offset by decreased natural gas sales volumes and price realizations. The following table gives details of net sales and average realizations of our U.S. operations.

	Three Months Ended March 31,
	2012		2011
United States Operating Statistics
Net liquid hydrocarbons sales (mbbld) (a)		90		78
Liquid hydrocarbon average realizations (per bbl) (b)	$	93.63	$	86.42

Net natural gas sales (mmcfd)		344		368
Natural gas average realizations (per mcf) (b)	$	4.13	$	5.15

(a)	Includes crude oil, condensate and natural gas liquids.

(b)	Excludes gains and losses on derivative instruments.

Liquid hydrocarbon sales volumes increased in the first quarter of 2012, reflecting our ongoing development programs primarily in the Eagle Ford and Bakken shale plays, partially offset by decreased production in the Gulf of Mexico.

The following table gives details of net sales and average realizations of our international operations.

	Three Months Ended March 31,
	2012		2011
International Operating Statistics
Net liquid hydrocarbon sales (mbbld)(a)
Europe		97		111
Africa		52		58
Total International		149		169
Liquid hydrocarbon average realizations (per bbl) (b)
Europe	$	123.76	$	109.85
Africa		94.41		81.47
Total International	$	113.55	$	100.10

Net natural gas sales (mmcfd)
Europe(c)		104		102
Africa		418		446
Total International		522		548
Natural gas average realizations (per mcf) (b)
Europe	$	9.99	$	10.29
Africa		0.24		0.25
Total International	$	2.19	$	2.12

(a)	Includes crude oil, condensate and natural gas liquids. The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

(b)	Excludes gains and losses on derivative instruments.

(c)	Includes natural gas acquired for injection and subsequent resale of 14 mmcfd and 15 mmcfd in the first quarters of 2012 and 2011.

Compared to the first quarter of 2011, international liquid hydrocarbon sales volumes were lower for the first quarter of 2012 primarily in the U.K. This was due to unplanned downtime at Foinaven and the timing of liftings.

OSM segment revenues increased $73 million in the first quarter of 2012 from the comparable prior-year period. The increase was driven primarily by a 7 percent increase in average realizations and an 18 percent increase in sales volumes as shown in the table below.

	Three Months Ended March 31,
	2012		2011
OSM Operating Statistics
Net synthetic crude oil sales (mbbld)(a)		44		37
Synthetic crude oil average realizations (per bbl)	$	90.88	$	84.98

(a)	Includes blendstocks.

The increased sales volumes are a result of the upgrader expansion which was completed in the second quarter of 2011 and longer periods of downtime for planned and unplanned maintenance in the first quarter of 2011.

IG segment revenues decreased $64 million in the first quarter of 2012 compared to the same period of 2011. Sales of LNG from our Alaska operations ceased completely in the third quarter of 2011 because we sold our equity interest in the facility.

Income from equity method investments decreased $39 million in the first quarter of 2012 from the comparable prior-year period. The decline is a result of lower natural gas prices and lower volumes as a result of a scheduled turnaround at our LNG facility in Equatorial Guinea.

Net gain on disposal of assets in the first quarter of 2012 was primarily the $166 million gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems.

Cost of revenues increased $3 million in the first quarter of 2012 from the comparable prior-year period, primarily due to our supply optimization activities. Costs related to supply optimization were $775 million in the first quarter of 2012 compared to $738 million in the first quarter of 2011. Excluding costs related to supply optimization, the overall decrease in costs is primarily the result of lower liquid hydrocarbon sales in the U.K. due to the timing of liftings.

Depreciation, depletion and amortization (“DD&A”) decreased $61 million in the first quarter of 2012 compared to the same quarter of 2011. Because both our E&P and OSM segments apply the units-of-production method to the majority of their assets, the previously discussed increases or decreases in sales volumes generally result in similar changes in DD&A. Decreased DD&A in the first quarter reflects the impact of lower E&P segment sales volumes, partially offset by increases in the OSM segment. The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in reserves and capitalized costs, can also cause changes in our DD&A. Lower DD&A rates per barrel in our E&P operations contributed to the overall lower DD&A. The following table provides DD&A rates for our E&P and OSM segments.

	Three Months Ended March 31,
($ per boe)	2012		2011
DD&A rate
E&P Segment
United States	$	24	$	28
International	$	9	$	10
OSM Segment	$	18	$	16

Impairments in the first quarter of 2012 relate to the Ozona development in the Gulf of Mexico (see Note 13 to the consolidated financial statements).

General and administrative expenses decreased during the first quarter of 2012 from the comparable prior year period primarily due to decreased incentive compensation expense.

Exploration expenses were lower in the first quarter of 2012 than in the same period of 2011, primarily due to higher dry well costs in the prior period. Dry well costs in the first quarter of 2011 primarily related to the Flying Dutchman in the Gulf of Mexico and the Romeo prospect in Indonesia.

The following table summarizes the components of exploration expenses.

	Three Months Ended March 31,
(In millions)	2012		2011
Dry well and unproved property impairment	$	58	$	172
Geological, geophysical, seismic		43		15
Other		41		43
Total exploration expenses	$	142	$	230

Provision for income taxes increased $391 million in the first quarter of 2012 from the comparable period of 2011 primarily due to the increase in pretax income and the resumption of sales in Libya in the first quarter of 2012.

Segment Results

Segment income is summarized in the following table.

	Three Months Ended March 31,
(In millions)	2012			2011
E&P
United States	$	109		$	30
International		368			638
E&P segment		477			668
OSM		41			32
IG		4			60
Segment income		522			760
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(29	)		(115	)
Foreign currency remeasurement of taxes		(15	)		(14	)
Loss on early extinguishment of debt		-			(176	)
Impairment		(167	)		-
Gain on dispositions		106			-
Income from continuing operations		417			455
Discontinued operations		-			541
Net income	$	417		$	996

United States E&P income increased $79 million in the first quarter of 2012 compared to the same period of 2011. Increased liquid hydrocarbon sales volumes and price realizations and, lower dry well costs and DD&A in the Gulf of Mexico, were partially offset by higher operating costs associated with increased activities in the Eagle Ford and Bakken shale plays in the first quarter of 2012.

International E&P income decreased $270 million in the first quarter of 2012 compared to the same period of 2011. As previously discussed, increased income before tax in higher tax jurisdictions resulted in a higher effective tax rate in the first quarter of 2012 compared to the same period of 2011. Increased liquid hydrocarbon price realizations were mostly offset by the declines in sales volumes previously discussed. DD&A was lower in the first quarter of 2012 as a result of lower sales volumes, as well as lower exploration costs in Indonesia.

OSM segment income increased $9 million in the first quarter of 2012 compared to the same period of 2011 primarily as a result of the higher realizations and increased sales volumes.

IG segment income decreased $56 million in the first quarter of 2012 compared to the same period of 2011, primarily as a result of weaker natural gas prices in 2012 and lower LNG sales volumes due to the sale of the Alaska LNG facility in the third quarter of 2011.

Cash Flows and Liquidity

Cash Flows

Net cash provided by continuing operations was $973 million in the first three months of 2012, compared to $1,633 million in the first three months of 2011 reflecting primarily the lower E&P segment sales volumes, lower natural gas realizations and a negative change in working capital.

Net cash used in investing activities totaled $806 million in the first quarter of 2012, compared to $711 million related to continuing operations in the first quarter of 2011. Significant investing activities are additions to property, plant and equipment and disposal of assets. In the first quarter of 2012, most additions to property, plant and equipment were related to our increased spending in U.S. unconventional resource plays, particularly the Eagle Ford shale and the resumption of drilling in the Gulf of Mexico. This compares to the first quarter of 2011, when spending on U.S. unconventional resource plays and drilling in Norway, Indonesia and the Iraqi Kurdistan Region accounted for most of the property, plant and equipment additions. In the first quarter of 2012, proceeds from the sale of assets were $208 million, primarily related to the sale of our interests in several Gulf of Mexico crude oil pipeline systems.

Net cash used in financing activities was $157 million in the first quarter of 2012, compared to net cash used of $2,937 million related to continuing operations in the first quarter of 2011. During the first quarter of 2012, we repaid $53 million of debt upon its maturity. During the first quarter of 2011, we retired $2.5 billion principal amount of our debt before it was due. Dividends paid were a significant use of cash in both periods.

Liquidity and Capital Resources

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, the issuance of notes, our committed revolving credit facility and sales of non-core assets. Our working capital requirements are supported by these sources and we may issue commercial paper backed by our $2.5 billion revolving credit facility to meet short-term cash requirements. We issued and repaid $100 million of commercial paper in the first quarter of 2012. Because of the alternatives available to us, including internally generated cash flow and access to capital markets, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, share repurchase program, and other amounts that may ultimately be paid in connection with contingencies.

Capital Resources

At March 31, 2012, 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.

In April 2012, we terminated our $3.0 billion five-year revolving credit facility and replaced it with a new $2.5 billion unsecured five-year revolving credit facility (the “Credit Facility”). The Credit Facility matures in April 2017 but allows us to request two, one-year extensions. It contains an option to increase the commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, and includes sub-facilities for swing-line loans and letters of credit up to an aggregate amount of $100 million and $500 million, respectively. Fees on the unused commitment of each lender range from 10 basis points to 25 basis points per year depending on our credit ratings. Borrowings under the Credit Facility bear interest, at our option, at either (a) the adjusted London Interbank Offered Rate (LIBOR) plus a margin ranging from 87.5 basis points to 162.5 basis points per year depending on our credit ratings or (b) the Base Rate plus a margin ranging from 0.0 basis points to 62.5 basis points depending on our credit ratings. Base Rate is defined as a per annum rate equal to the greatest of (a) the prime rate, (b) the federal funds rate plus one-half of one percent and (c) LIBOR for a one-month interest period plus 1 percent.

We have a universal shelf registration statement filed 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 20 percent at March 31, 2012 and December 31, 2011.

	March 31,			December 31,
(In millions)	2012			2011
Long-term debt due within one year	$	197		$	141
Long-term debt		4,559			4,674
Total debt	$	4,756		$	4,815
Cash	$	513		$	493
Equity	$	17,506		$	17,159
Calculation:
Total debt	$	4,756		$	4,815
Minus cash		513			493
Total debt minus cash	$	4,243		$	4,322
Total debt		4,756			4,815
Plus equity		17,506			17,159
Minus cash		513			493
Total debt plus equity minus cash	$	21,749		$	21,481
Cash-adjusted debt-to-capital ratio		20	%		20	%

Capital Requirements

On April 25, 2012, our Board of Directors approved a 17 cents per share dividend, payable June 11, 2012 to stockholders of record at the close of business on May 16, 2012.

As discussed in Note 6 to the consolidated financial statements, the majority of the transactions, in terms of value, related to the Eagle Ford shale are expected to close in the third quarter of 2012, at which time the purchase price of approximately $767 million, before closing adjustments, will be paid.

We have increased our capital, investment and exploration budget, excluding acquisition costs, from $4.8 billion to $5.0 billion, of which $4.6 billion will be used for capital expenditures. The increase is a result of the additional acreage being acquired in the Eagle Ford shale and other adjustments.

Our opinions concerning liquidity, our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements, and the capital, investment and exploration budget are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Estimates may differ from actual results. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The statements about our capital, investment and exploration budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially are changes in prices of and demand for crude oil and natural gas, actions of competitors, disruptions or interruptions of our production 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.

The above discussion also contains forward-looking statements with respect to acquisitions in the Eagle Ford shale. These acquisitions are subject to customary closing conditions. The failure to satisfy these closing conditions could cause actual results to differ materially from those set forth in the forward-looking statements.

Contractual Cash Obligations

As of March 31, 2012, our consolidated contractual cash obligations have increased by $128 million from December 31, 2011, primarily related to contracts to acquire property, plant and equipment.

Critical Accounting Estimates

There have been no changes to our critical accounting estimates subsequent to December 31, 2011.

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 and production processes.

There have been no other significant changes to our environmental matters subsequent to December 31, 2011.

Other 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.

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

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 2011 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 13 and Note 14 to the consolidated financial statements.

Sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of March 31, 2012 is provided in the following table.

				Incremental Change in Fair Value
(In millions)	Fair Value
Financial assets (liabilities): (a)
Interest rate swap agreements		$	4 (b)		$	4
Long-term debt, including amounts due within one year		$	(5,431)(b)		$	(226)

(a)	Fair values of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.

(b)	Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.

The aggregate cash flow effect on foreign currency derivative contracts of a hypothetical 10 percent change in exchange rates at March 31, 2012 would be $63 million.

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

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective. During the quarter ended March 31, 2012, 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)	2012			2011

Segment Income (Loss)
Exploration and Production
United States	$	109		$	30
International		368			638
E&P segment		477			668
Oil Sands Mining		41			32
Integrated Gas		4			60
Segment income		522			760
Items not allocated to segments, net of income taxes		(105	)		(305	)
Income from continuing operations		417			455
Discontinued Operations(a)		-			541
Net income	$	417		$	996
Capital Expenditures(b)
Exploration and Production
United States	$	862		$	349
International		139			319
E&P segment		1,001			668
Oil Sands Mining		52			120
Integrated Gas		-			1
Corporate		42			6
Total	$	1,095		$	795
Exploration Expenses
United States	$	93		$	151
International		49			79
Total	$	142		$	230

(a)	The spin-off of our downstream business was completed on June 30, 2011, and has been reported as discontinued operations in 2011.

(b)	Capital expenditures include changes in accruals.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Three Months Ended March 31,
	2012		2011

E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbbld)
United States		90		78

Europe		97		111
Africa		52		58
Total International		149		169
Worldwide		239		247

Natural Gas Sales (mmcfd)(c)
United States		344		368

Europe		104		102
Africa		418		446
Total International		522		548
Worldwide		866		916

Total Worldwide Sales (mboed)		383		400

Average Realizations (d)
Liquid Hydrocarbons (per bbl)
United States	$	93.63	$	86.42

Europe		123.76		109.85
Africa		94.41		81.47
Total International		113.55		100.10
Worldwide	$	106.06	$	95.79

Natural Gas (per mcf)
United States	$	4.13	$	5.15

Europe		9.99		10.29
Africa(e)		0.24		0.25
Total International		2.19		2.12
Worldwide	$	2.96	$	3.34
OSM Operating Statistics
Net Synthetic Crude Oil Sales (mbbld) (f)		44		37
Synthetic Crude Oil Average Realizations (per bbl)(d)	$	90.88	$	84.98

IG Operating Statistics
Net Sales (mtd) (g)
LNG		6,291		7,822
Methanol		1,312		1,318

(c)	Includes natural gas acquired for injection and subsequent resale of 14 mmcfd and 15 mmcfd for the first three months of 2012 and 2011.

(d)	Excludes gains and losses on derivative instruments.

(e)

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.

(f)	Includes blendstocks.

(g)

Includes both consolidated sales volumes and our share of the sales volumes of equity method investees. LNG sales from Alaska, conducted through a consolidated subsidiary, ceased when these operations were sold in the third quarter of 2011. LNG and methanol sales from Equatorial Guinea are conducted through equity method investees.

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. There have been no significant changes in legal or environmental proceedings during the first quarter of 2012.

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 2011 Annual Report on Form 10-K.

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

The following table provides information about purchases by Marathon Oil and its affiliated purchaser during the quarter ended March 31, 2012, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934.

	Column (a)		Column (b)		Column (c)		Column (d)
					Total Number of		Approximate Dollar
					Shares Purchased as		Value of Shares that
					Part of Publicly		May Yet Be Purchased
	Total Number of		Average Price Paid		Announced Plans or		Under the Plans or
Period	Shares Purchased (a)(b)		per Share		Programs (c)		Programs (c)

01/01/12 – 01/31/12		4,959	$	30.52		-	$	1,780,609,536
02/01/12 – 02/29/12		49,757	$	34.65		-	$	1,780,609,536
03/01/12 – 03/31/12		32,482	$	33.56		-	$	1,780,609,536
Total		87,198	$	34.01		-

(a)	58,812 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

(b)

In March 2012, 28,386 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon Oil.

(c)

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, 2012, 78 million common shares had been acquired at a cost of $3,222 million, which includes transaction fees and commissions that are not reported in the table above. Of this total, 66 million shares had been acquired at a cost of $2,922 million prior to the spin-off of the downstream business (see Note 2 to the consolidated financial statements).

Item 4. Mine Safety Disclosures

Not applicable.

Item 6. Exhibits

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

4.1

Credit Agreement, dated as of April 5, 2012, among Marathon Oil Corporation, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and UBS Securities LLC, as documentation agents, JP Morgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions named therein.

8-K

4.1

4/10/2012

10.1

Marathon Oil Corporation 2012 Incentive Compensation Plan.

DEF 14A

App. III

3/8/2012

10.2

Form of Performance Unit Award Agreement (2012-2014 Performance Cycle) granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan.

10.3

First Amendment to the Marathon Oil Corporation Executive Change in Control Severance Benefits Plan, effective October 26, 2011.

10.4

Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (For Officers Hired or Promoted after October 26, 2011).

12.1

Computation of Ratio of Earnings to Fixed Charges.

31.1

Certification of Chairman, 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 Chairman, 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.

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

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 4, 2012	MARATHON OIL CORPORATION

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