10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended March 31, 2013

OR

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

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)

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

5555 San Felipe 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 þ No o

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 þ No o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).         

Yes o No þ

There were 708,817,008 shares of Marathon Oil Corporation common stock outstanding as of April 30, 2013.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended March 31, 2013

	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	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 4.	Controls and Procedures	29
	Supplemental Statistics (Unaudited)	30
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 4.	Mine Safety Disclosures	33
Item 6.	Exhibits	34
	Signatures	35

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).

1

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)	2013			2012
Revenues and other income:
Sales and other operating revenues, including related party	$	3,440		$	2,954
Marketing revenues	430			839
Income from equity method investments	118			78
Net gain on disposal of assets	109			166
Other income	9			3
Total revenues and other income	4,106			4,040
Costs and expenses:
Production	578			514
Marketing, including purchases from related parties	429			842
Other operating	111			92
Exploration	465			135
Depreciation, depletion and amortization	747			574
Impairments	38			262
Taxes other than income	84			68
General and administrative	174			159
Total costs and expenses	2,626			2,646
Income from operations	1,480			1,394
Net interest and other	(72		)	(50		)
Income before income taxes	1,408			1,344
Provision for income taxes	1,025			927
Net income	$	383		$	417
Per Share Data
Net Income:
Basic		$0.54			$0.59
Diluted		$0.54			$0.59
Dividends paid		$0.17			$0.17
Weighted average shares:
Basic	708			706
Diluted	712			710

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

2

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended
	March 31,
(In millions)	2013			2012
Net income	$	383		$	417
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	13			13
Income tax provision on postretirement and
postemployment plans	(5		)	(5		)
Postretirement and postemployment plans, net of tax	8			8
Foreign currency translation and other
Unrealized gain (loss)	(1		)	1
Income tax provision on foreign currency translation and other	—			—
Foreign currency translation and other, net of tax	(1		)	1
Other comprehensive income	7			9
Comprehensive income	$	390		$	426

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

3

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

	March 31,			December 31,
(In millions, except per share data)	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	768		$	684
Receivables	2,466			2,418
Inventories	368			361
Other current assets	175			299
Total current assets	3,777			3,762
Equity method investments	1,304			1,279
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $20,195 and $19,266	28,382			28,272
Goodwill	528			525
Other noncurrent assets	1,118			1,468
Total assets	$	35,109		$	35,306
Liabilities
Current liabilities:
Commercial paper	$	—		$	200
Accounts payable	2,284			2,324
Payroll and benefits payable	182			217
Accrued taxes	1,892			1,983
Other current liabilities	203			173
Long-term debt due within one year	68			184
Total current liabilities	4,629			5,081
Long-term debt	6,476			6,512
Deferred tax liabilities	2,401			2,432
Defined benefit postretirement plan obligations	850			856
Asset retirement obligations	1,795			1,749
Deferred credits and other liabilities	370			393
Total liabilities	16,521			17,023
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued or 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 or
outstanding (no par value, 29 million shares authorized)	—			—
Held in treasury, at cost – 62 million and 63 million shares	(2,527		)	(2,560		)
Additional paid-in capital	6,618			6,616
Retained earnings	14,153			13,890
Accumulated other comprehensive loss	(426		)	(433		)
Total equity	18,588			18,283
Total liabilities and stockholders' equity	$	35,109		$	35,306

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

4

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended
	March 31,
(In millions)	2013			2012
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	383		$	417
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes	44			(22		)
Depreciation, depletion and amortization	747			574
Impairments	38			262
Pension and other postretirement benefits, net	7			(29		)
Exploratory dry well costs and unproved property impairments	404			58
Net gain on disposal of assets	(109		)	(166		)
Equity method investments, net	(48		)	(21		)
Changes in:
Current receivables	(4		)	(296		)
Inventories	(15		)	7
Current accounts payable and accrued liabilities	(54		)	213
All other operating, net	135			(24		)
Net cash provided by operating activities	1,528			973
Investing activities:
Additions to property, plant and equipment	(1,375		)	(1,017		)
Disposal of assets	312			208
Investments - return of capital	18			15
All other investing, net	8			(12		)
Net cash used in investing activities	(1,037		)	(806		)
Financing activities:
Commercial paper, net	(200		)	—
Debt repayments	(114		)	(53		)
Dividends paid	(120		)	(121		)
All other financing, net	21			17
Net cash used in financing activities	(413		)	(157		)
Effect of exchange rate changes on cash	6			10
Net increase in cash and cash equivalents	84			20
Cash and cash equivalents at beginning of period	684			493
Cash and cash equivalents at end of period	$	768		$	513

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

5

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 ("SEC") 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.

Beginning in the first quarter of 2013, we changed the presentation of our consolidated statements of income, primarily to present additional details of revenues and expenses and to classify certain expenses more consistently with our peer group of independent exploration and production companies. To effect these changes, reclassifications of previously reported amounts were made and are reflected in these consolidated financial statements. As a result of the reclassifications, general and administrative expenses for the first quarter of 2012 increased by $39 million which primarily includes certain costs associated with operations support and operations management. Offsetting reductions are reflected in production, other operating and exploration expenses and taxes other than income.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation 2012 Annual Report on Form 10-K.  The results of operations for the first quarter of 2013 are not necessarily indicative of the results to be expected for the full year.

2.   Accounting Standards

Not Yet Adopted

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within United States generally accepted accounting principles ("U.S. GAAP"). An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. We are currently evaluating the potential impact of this accounting standards update on our consolidated results of operations, financial position and cash flows.

Recently Adopted

In February 2013, an accounting standards update was issued to improve the reporting of reclassifications out of accumulated other comprehensive income. This standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This accounting standards update was effective for us beginning the first quarter of 2013 and we present the required disclosures in Note14. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

6

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

In December 2011, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosures are intended to enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclose both gross information and net information about in-scope financial instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. The accounting standards update was effective for us beginning the first quarter of 2013 and we include the required disclosures in Note 12. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

3.   Variable Interest Entity

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 current liabilities of $2 million and $3 million recorded at March 31, 2013 and December 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 by us.  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 $711 million as of March 31, 2013.  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.

4.    Income per Common Share

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

	Three Months Ended March 31,
	2013				2012
(In millions, except per share data)	Basic		Diluted		Basic		Diluted
Net income	$	383	$	383	$	417	$	417
Weighted average common shares outstanding	708		708		706		706
Effect of dilutive securities	—		4		—		4
Weighted average common shares, including
dilutive effect	708		712		706		710
Per share:
Net income		$0.54		$0.54		$0.59		$0.59

The per share calculations above exclude 6 million and 7 million stock options and stock appreciation rights for the first quarters of 2013 and 2012 that were antidilutive.

7

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

5.   Dispositions

2013 - North America Exploration and Production ("E&P") Segment

In April 2013, we reached an agreement to sell our interests in the DJ Basin. The transaction is expected to close in mid-2013 and a second quarter loss of approximately $115 million, before closing adjustments, is anticipated on this disposition.

In February 2013, we entered an agreement to convey our interest in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.

In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain, before closing adjustments, was recorded in the first quarter of 2013.

In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million for various indemnities. A $46 million pretax gain, before closing adjustments, was recorded in the first quarter of 2013.

2012 - North America E&P Segment

In January 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million.  This included 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.

6.    Segment Information

  Beginning in 2013, we changed our reportable segments and revised our management reporting to better reflect the growing importance of United States unconventional resource plays to our business. All periods presented have been recast to reflect these new segments.

We have three reportable operating segments.  Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.

• North America E&P ("N.A. E&P") – explores for, produces and markets liquid hydrocarbons and natural gas in North America;

• International E&P ("Int'l E&P") – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as liquefied natural gas ("LNG")and methanol, in Equatorial Guinea;

• 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.

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 excluding certain items not allocated to segments as discussed below, net of income taxes, attributable to the operating segments. Our corporate and operations support 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 and operations support activities, net of associated income tax effects.  Unrealized gains or losses on crude oil derivative instruments, 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 and our consolidated totals for income taxes and depreciation, depletion and amortization 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.

8

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Three Months Ended March 31, 2013
(In millions)	N.A. E&P			Int'l E&P		OSM		Total
Revenues:
Sales and other operating revenues	$	1,215		$	1,887	$	388	$	3,490
Marketing revenues	345			85		—		430
Segment revenues	$	1,560		$	1,972	$	388	3,920
Unrealized loss on crude oil derivative instruments								(50		)
Total revenues								$	3,870
Segment income (loss)	$	(59	)	$	453	$	38	$	432
Income from equity method investments	—			118		—		118
Depreciation, depletion and amortization	478			207		52		737
Income tax provision (benefit)	(30		)	1,142		13		1,125
Capital expenditures	970			225		45		1,240

	Three Months Ended March 31, 2012
(In millions)	N.A. E&P		Int'l E&P		OSM		Total
Revenues:
Sales and other operating revenues	$	912	$	1,663	$	379	$	2,954
Marketing revenues	775		64		—		839
Total revenues	$	1,687	$	1,727	$	379	$	3,793
Segment income	$	104	$	407	$	38	$	549
Income from equity method investments	1		77		—		78
Depreciation, depletion and amortization	314		200		49		563
Income tax provision	61		971		13		1,045
Capital expenditures	829		138		52		1,019

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)	2013		2012
Total revenues	$	3,870	$	3,793
Less:  Marketing revenues	430		839
Sales and other operating revenues, including related party	$	3,440	$	2,954

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

	Three Months Ended March 31,
(In millions)	2013			2012
Segment income	$	432		$	549
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(71		)	(71		)
Unrealized loss on crude oil derivative instruments	(32		)	—
Impairments	(10		)	(167		)
Net gain on dispositions	64			106
Net income	$	383		$	417

9

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

7.    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)	2013			2012			2013			2012
Service cost	$	14		$	12		$	1		$	1
Interest cost	15			16			3			4
Expected return on plan assets	(17		)	(16		)	—			—
Amortization:
– prior service cost (credit)	2			2			(2		)	(2		)
– actuarial loss	13			12			—			—
Net periodic benefit cost	$	27		$	26		$	2		$	3

During the first three months of 2013, we made contributions of $9 million to our funded pension plans.  We expect to make additional contributions up to an estimated $55 million to our funded pension plans over the remainder of 2013.  Current benefit payments related to unfunded pension and other postretirement benefit plans were $9 million and $4 million during the first three months of 2013.

8.   Income Taxes

The effective income tax rate is influenced by a variety of factors including the geographic 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 items not allocated to segments is presented in Corporate and other unallocated items in Note 6.

Our effective income tax rates in the first three months of 2013 and 2012 were 73 percent and 69 percent.   These rates are higher than the U.S. statutory rate of 35 percent due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax rates are in excess of the U.S. statutory rate.  In Libya, where the statutory tax rate is in excess of 90 percent, there remains uncertainty around sustained production and sales levels.  Reliable estimates of 2013 and 2012 annual ordinary income from our Libyan operations could not 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 first three months of 2013 and 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 65 percent and 64 percent for the first three months of 2013 and 2012.

9.   Inventories

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

	March 31,		December 31,
(In millions)	2013		2012
Liquid hydrocarbons, natural gas and bitumen	$	54	$	73
Supplies and other items	314		288
Inventories, at cost	$	368	$	361

10

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

10.  Property, Plant and Equipment

	March 31,			December 31,
(In millions)	2013			2012
North America E&P	$	24,500		$	23,748
International E&P	13,429			13,214
Oil Sands Mining	10,171			10,127
Corporate	477			449
Total property, plant and equipment	48,577			47,538
Less accumulated depreciation, depletion and amortization	(20,195		)	(19,266		)
Net property, plant and equipment	$	28,382		$	28,272

In the first quarter of 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed.  Since that time, average sales volumes have increased to near pre-conflict levels.  We and our partners in the Waha concessions continue to assess the condition of our assets in Libya and uncertainty around sustained production and sales levels remains. As of March 31, 2013, our net property, plant and equipment investment in Libya was approximately $748 million.

Exploratory well costs capitalized greater than one year after completion of drilling were $220 million as of March 31, 2013.  The net decrease in such costs from December 31, 2012 primarily related to the conveyance of our interest in the Marcellus natural gas shale play to the operator in February 2013.

11.  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, 2013 and December 31, 2012 by fair value hierarchy level.

	March 31, 2013
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	8	$	—	$	1	$	9
Interest rate	—		18		—		—		18
Derivative instruments, assets	$	—	$	26	$	—	$	1	$	27
Derivative instruments, liabilities
Commodity	$	—	$	6	$	—	$	—	$	6
Foreign currency	—		20		—		—		20
Derivative instruments, liabilities	$	—	$	26	$	—	$	—	$	26

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	52	$	—	$	1	$	53
Interest rate	—		21		—		—		21
Foreign currency	—		18		—		—		18
Derivative instruments, assets	$	—	$	91	$	—	$	1	$	92

11

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Commodity swaps in Level 2 are measured at fair value with a market approach using prices obtained from exchanges or pricing services, which have been corroborated with data from active markets for similar assets or liabilities.  Commodity options in Level 2 are valued using The Black-Scholes Model.  Inputs to this model include prices as noted above, discount factors, and implied market volatility.  The inputs to this fair value measurement are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.  Collateral deposits related to commodity derivatives are in broker accounts covered by master netting agreements.

Interest rate swaps are measured at fair value with a market approach 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 or liabilities, and are Level 2 inputs.

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,
	2013				2012
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	38	$	75	$	262

All long-lived assets held for use that were impaired in the first quarters of 2013 and 2012 were held by our North America E&P segment. The fair values of each discussed below were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs.  Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

In the first quarter of 2013, as a result of our decision to wind down operations in the Powder River Basin due to poor economics, an impairment of $15 million was recorded.

In early 2012, production rates from the Ozona development in the Gulf of Mexico declined significantly. Accordingly, our reserve engineers prepared evaluations of our future production as well as our reserves and an impairment of $261 million was recorded in the first quarter of 2012.  As the development produced towards abandonment pressures, further downward revisions of reserves were taken, resulting in an additional impairment recorded in the fourth quarter of 2012. Ozona production ceased in the first quarter of 2013 and an additional $21 million impairment was recorded.

Other impairments of long-lived assets held for use by our North America E&P segment in the first quarters of 2013 and 2012 were a result of reduced drilling expectations, reductions of estimated reserves or declining natural gas prices.

Fair Values – Financial Instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, commercial paper and payables. We believe the carrying values of our receivables, commercial paper and payables 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.

12

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table summarizes financial instruments, excluding receivables, commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at March 31, 2013 and December 31, 2012.

	March 31, 2013				December 31, 2012
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	174	$	169	$	189	$	186
Total financial assets	174		169		189		186
Financial liabilities
Other current liabilities	13		13		13		13
Long-term debt, including current portion(a)	7,347		6,494		7,610		6,642
Deferred credits and other liabilities	146		141		94		94
Total financial liabilities	$	7,506	$	6,648	$	7,717	$	6,749

^(a)      Excludes capital leases.

Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and 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.

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

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

12. Derivatives

For information regarding the fair value measurement of derivative instruments, see Note 11. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. Netting is assessed by counterparty, and as of March 31, 2013 and December 31, 2012, there were no offsetting amounts. Positions by contract were all either assets or liabilities. The following tables present the gross fair values of derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of March 31, 2013 and December 31, 2012.

	March 31, 2013
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	18	$	—	$	18	Other noncurrent assets
Total Designated Hedges	18		—		18
Not Designated as Hedges
Commodity	8		—		8		Other current assets
Total Not Designated as Hedges	8		—		8
Total	$	26	$	—	$	26

	March 31, 2013
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	20	$	20	Other current liabilities
Total Designated Hedges	—		20		20
Not Designated as Hedges
Commodity	—		6		6		Other current liabilities
Total Not Designated as Hedges	—		6		6
Total	$	—	$	26	$	26

	December 31, 2012
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	18	$	—	$	18	Other current assets
Interest rate	21		—		21		Other noncurrent assets
Total Designated Hedges	39		—		39
Not Designated as Hedges
Commodity	52		—		52		Other current assets
Total Not Designated as Hedges	52		—		52
Total	$	91	$	—	$	91

Derivatives Designated as Fair Value Hedges

As of March 31, 2013 and December 31, 2012, we had multiple interest rate swap agreements with a total notional amount of $600 million with a maturity date of October 1, 2017 at a weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate of 4.69 percent and 4.70 percent.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

As of March 31, 2013 and December 31, 2012, our foreign currency forwards had an aggregate notional amount of 3,571 million and 3,043 million Norwegian Kroner at a weighted average forward rate of 5.678 and 5.780. These forwards hedge our current Norwegian tax liability and have settlement dates through August 2013.

The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below.

		Gain (Loss)
		Three Months Ended March 31,
(In millions)	Income Statement Location	2013			2012
Derivative
Interest rate	Net interest and other	$	(3	)	$	(1	)
Foreign currency	Provision for income taxes	$	(25	)	$	(8	)
Hedged Item
Long-term debt	Net interest and other	$	3		$	1
Accrued taxes	Provision for income taxes	$	25		$	8

Derivatives not Designated as Hedges

In August 2012, we entered into crude oil derivatives related to a portion of our forecast North America E&P crude oil sales through December 31, 2013. These commodity derivatives were not designated as hedges and are shown in the table below.

Remaining Term	Bbls per Day	Weighted Average Price per Bbl	Benchmark
Swaps
April 2013 - December 2013	20,000	$96.29	West Texas Intermediate
April 2013 - December 2013	25,000	$109.19	Brent
Option Collars
April 2013 - December 2013	15,000	$90.00 floor / $101.17 ceiling	West Texas Intermediate
April 2013 - December 2013	15,000	$100.00 floor / $116.30 ceiling	Brent

The impact of commodity derivative instruments not designated as hedges appears in the sales and operating revenues, including related party, line of our consolidated statements of income and was a net loss of $55 million in the first quarter of 2013 and a net gain of $2 million in the first quarter of 2012.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

13.    Incentive Based Compensation

Stock option and restricted stock awards

  The following table presents a summary of stock option and restricted stock award activity for the first quarter of 2013: 

	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2012	19,536,965				$26.19	4,177,884			$29.02
Granted	1,002,400		(a)		$32.86	137,722			$33.04
Options Exercised/Stock Vested	(839,273	)			$21.33	(493,840	)		$30.66
Cancelled	(215,262	)			$35.17	(78,778	)		$28.98
Outstanding at March 31, 2013	19,484,830				$26.65	3,742,988			$28.96

^(a)    The weighted average grant date fair value of stock option awards granted was $10.50 per share.

Performance unit awards

 During the first quarter of 2013, we granted 353,600 performance units to certain officers that provide a cash payout upon the achievement of certain performance goals at the end of a 36-month performance period.  The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors.   At the grant date, each unit represents the value of one share of our common stock, while payout after completion of the performance period will be based on the value of anywhere from zero to two times the number of units granted.  Dividend equivalents accrue during the performance period and are paid in cash at the end of the performance period based on the number of shares that would represent the value of the units.  The fair value of these performance units is re-measured on a quarterly basis using the Monte Carlo simulation method.  These performance units are accounted for as liability awards because they are to be settled in cash at the end of the performance period and their fair value is expensed over the performance period.

14.  Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss for the first quarter of 2013:

	Three Months Ended March 31, 2013
(In millions)		Reclassified to Income (Expense)			Income Statement Line
Accumulated Other Comprehensive Loss Components
Amortization of postretirement and postemployment plans
Actuarial loss		$	(13	)	General and administrative
		5			Provision for income taxes
Total reclassifications for the period		$	(8	)	Net income

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

15.  Supplemental Cash Flow Information

	Three Months Ended March 31,
(In millions)	2013			2012
Net cash provided from operating activities:
Interest paid (net of amounts capitalized)	$	61		$	50
Income taxes paid to taxing authorities	1,003			828
Commercial paper, net:
Commercial paper - issuances	$	200		$	100
- repayments	(400		)	(100		)
Noncash investing activities:
Asset retirement costs capitalized	$	27		$	1
Change in capital expenditure accrual	(105		)	46
Asset retirement obligations assumed by buyer	88			7
Receivable for disposal of assets	50			—

16.   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. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. 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, 2013, Marathon’s contract commitments to acquire property, plant and equipment were $1,209 million.

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

  Beginning in 2013, we changed our reportable segments and revised our management reporting to better reflect the growing importance of United States unconventional resource plays to our business. All periods presented have been recast to reflect these new segments.

We are an international energy company with operations in the United States, Canada, Africa, the Middle East and Europe.  We have three reportable operating segments. Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.

• North America Exploration and Production ("E&P") – explores for, produces and markets liquid hydrocarbons and natural gas in North America;

• International E&P – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol in Equatorial Guinea;

• Oil Sands Mining – 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.

 Certain sections of this Quarterly Report on Form 10-Q, including Management’s Discussion and Analysis of Financial Condition and Results of Operations contain 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 2012 Annual Report on Form 10-K. We assume no duty to update these statements as to any future date.

Key Operating and Financial Activities

In the first quarter of 2013, notable items were:

• Total net sales volumes averaged 523 thousand barrels of oil equivalent per day (“mboed”), a 22 percent increase over the same quarter of last year

• Liquid hydrocarbon and synthetic crude oil sales volumes accounted for 93 percent of the increase

• Eagle Ford shale averaged net sales volumes of 72 mboed, a four-fold increase

• Bakken shale averaged net sales volumes of 37 mboed, a 46 percent increase

• Libya averaged net sales volumes of 38 mboed, a 123 percent increase

• Oil Sands Mining averaged net sales volumes of 51 thousand barrels per day ("mbbld"), a 16 percent increase

• Sale of our interest in the Neptune gas plant closed for proceeds of $166 million before closing adjustments

• Sale of our Alaska assets closed for proceeds of $195 million subject to a six-month escrow of $50 million and closing adjustments

• Government approval received for acquisition of a 20 percent non-operated interest in the onshore South Omo concession in Ethiopia, and exploratory drilling commenced

• Successful appraisal well on non-operated Shenandoah prospect in the Gulf of Mexico announced

• Sales commenced at the PSVM development located on the northeastern portion of Angola Block 31

• Apparent high bidder on two blocks in the March 2013 Gulf of Mexico lease sale

• Unproved property impairments of approximately $340 million recorded related to expiring Eagle Ford leases and leases we do not intend to drill

• Changed reportable segments to reflect the growing importance of the United States unconventional resource plays

18

Some significant second quarter activities through May 10, 2013 include:

• Decision made to conclude exploration activities in Poland

• Agreement reached to sell interests in DJ Basin

• Turnaround in Equatorial Guinea started and safely completed in April, eight days ahead of schedule and below budget

Overview and Outlook

North America E&P

Production

 Net liquid hydrocarbon and natural gas sales volumes averaged 198 mboed during the first quarter of 2013 and 147 mboed in the same period of 2012, a 35 percent increase.  Net liquid hydrocarbon sales volumes increased, primarily reflecting the impact of our ongoing development programs in the Eagle Ford and Bakken shale resource plays, while net natural gas sales volumes decreased slightly due to the sale of our Alaska assets in January 2013. Excluding the sales volume related to Alaska in both periods, our average net liquid hydrocarbon and natural gas sales volumes increased 47 percent.

In 2013, production growth continued in the Eagle Ford shale play. Average net sales volumes were 72 mboed in the first quarter of 2013 compared to 14 mboed in the same period of 2012. Approximately 64 percent of first quarter 2013 production was crude oil and condensate, 17 percent was natural gas liquids ("NGLs") and 19 percent was natural gas. During the first quarter of 2013, we reached total depth on 76 gross operated wells and brought 68 gross operated wells to sales. We continue to advance our drilling performance, reducing the average time to drill a well from 28 days in the first quarter of 2012 to 18 days in the first quarter of 2013. We expect these drilling times to continue dropping during 2013 as additional efficiencies are gained from pad drilling.

We continue to build infrastructure to support production growth across the Eagle Ford operating area. Approximately 148 miles of gathering lines were installed in the first quarter of 2013, while five new central gathering and treating facilities were commissioned, with two additional facilities in various stages of planning or construction. As of March 31, 2013, we transport approximately 65 percent of our crude oil and condensate by pipeline, with additional contract negotiations and facility designs under way that are expected to push that figure to 75 percent by the end of May. The ability to transport more barrels by pipeline enables us to reduce costs, improve reliability and lessen our environmental footprint.

We are confident our core Eagle Ford acreage position will be developed on a maximum of 80-acre spacing and continue to evaluate the potential of downspacing to 40-acre and 60-acre units. We have begun drilling wells in the Austin Chalk and Pearsall formations to further test the potential of these horizons. The results to-date of the downspacing pilots have been in line with our expectations, and we anticipate releasing more definitive results of both the downspacing pilots and the additional formation testing in the second half of 2013.

 Average net sales volumes from the Bakken shale were 37 mboed in the first quarter of 2013 compared to 25 mboed in the same period of 2012. Our Bakken production averages approximately 90 percent crude oil, 5 percent NGLs and 5 percent natural gas. During the first quarter of 2013, we reached total depth on 18 gross operated wells and brought 22 gross operated wells to sales. Our average time to drill a well was 25 days.

 In the Oklahoma Resource Basins, net sales volumes averaged 13 mboed in the first quarter of 2013 compared to 5 mboed in the same period of 2012.  All net sales volumes are from the Anadarko Woodford shale. During the first quarter of 2013, four gross operated wells were brought to sales. We anticipate drilling two wells each in the Mississippi Lime and Granite Wash formations during 2013.

Exploration

Exploration activity continues in the Gulf of Mexico. The first appraisal well on the Shenandoah prospect located on Walker Ridge Block 51, in which we have a 10 percent outside-operated working interest, reached total depth in the first quarter of 2013. We are currently participating in a Gunflint prospect appraisal well located on Mississippi Canyon Block 992 where we hold an 18 percent non-operated working interest.

In March 2013, we submitted the apparent high bids totaling $33 million for 100 percent working interest in two blocks in Central Gulf of Mexico Lease Sale 227: Keathley Canyon Block 340 on the Colonial prospect and Keathley Canyon Block 153, an extension to the Meteor prospect on our existing Keathley Canyon 196 lease. Keathley Canyon Blocks 340 and 153 are both inboard-Paleogene prospects.

During the first quarter of 2012, we submitted a regulatory application relating to our Canada in-situ assets at Birchwood, for a proposed 12 mbbld steam assisted gravity drainage ("SAGD") demonstration project. We are expecting to receive regulatory approval for this project in late 2013 or early 2014.  Upon receiving this approval, we will further evaluate our development plans.

19

International E&P

Production

Net liquid hydrocarbon and natural gas sales volumes averaged 274 mboed during the first quarter of 2013 and 236 mboed in the same period of 2012, a 16 percentincrease.  During the first quarter of 2013, Libya net liquid hydrocarbon and natural gas sales volumes increased 21 mboed, compared to the same period of 2012, primarily due to limited sales in the first quarter of 2012 upon the resumption of sales after the 2011 civil unrest.  In addition, the first quarter of 2013 includes net liquid hydrocarbon sales volumes of 9 mboed from the PSVM development located on the northeastern portion of Angola Block 31 which had first sales in February 2013.

Strong operational performance continues in Equatorial Guinea, with availability of nearly 98 percent in the first quarter of 2013, which bolstered production during the first quarter of 2013. We started a 30-day planned turnaround in Equatorial Guinea on April 1, 2013 which was safely completed eight days ahead of schedule and below budget. The Alba field, associated gas plant and liquefied natural gas facility each resumed full production on April 22, 2013.

The production decline in the Alvheim area offshore Norway continues to be less severe than expected. These better-than-expected results have been achieved through continued strong operational performance that delivered availability of 97 percent in the first quarter of 2013, reservoir and well performance at the upper end of expectations primarily due to a delay in anticipated water breakthrough at the Volund field and sustained contributions from the recently completed development drilling program.

Exploration

In the Kurdistan Region of Iraq, we hold 45 percent operated working interests in both the Harir and Safen blocks. Current exploratory drilling includes the Mirawa well which began in March 2013 on the Harir Block and the Safen well which commenced drilling in April 2013 on the Safen Block. Both of these wells are expected to reach projected total depth in the third quarter of 2013 with testing programs to follow on each well.

Additionally, following the successful appraisal program on the non-operated Atrush Block, a declaration of commerciality was filed with the government and a plan of development is anticipated to be filed in May 2013. Drilling of the Atrush-3 appraisal well commenced in March. On the non-operated Sarsang block, the Mangesh and Gara exploration wells began drilling in the second half of 2012. Both wells are currently drilling and are expected to reach total depth during the second quarter of 2013, with testing programs to follow on each well. Also on the Sarsang block, the East Swara Tika well is expected to begin drilling late in the second quarter or early in the third quarter of 2013. We hold a 15 percent working interest in the Atrush block and a 25 percent working interest in the Sarsang block.

The Sabisa-1 exploration well in the South Omo block onshore Ethiopia has been drilled to total depth and recorded hydrocarbon indications in sands beneath a thick claystone top seal. Hole instability issues have required the drilling of a sidetrack to comprehensively log and sample zones of interest. Results from the sidetrack are expected in the second quarter of 2013. We hold a 20 percent non-operated working interest in the South Omo block.

Exploration drilling began in April 2013 on the Diaman No. 1 well in the Diaba License G4-223, offshore Gabon, to test the deepwater presalt play. We expect the well to reach total depth in the third quarter of 2013. We hold a 21 percent non-operated working interest in the Diaba License.

Offshore Norway, the Darwin (formerly Veslemoy) exploration well was drilled in the first quarter of 2013 on PL 531 in which we hold a 10 percent non-operated fully-carried working interest. Gas shows were recorded in the Paleocene objective section, although no hydrocarbons were found in the Cretaceous section and the well has been plugged and abandoned. We expect drilling to commence in the third quarter of 2013 on the Sverdrup exploration well on PL 330, in which we hold a 30 percent non-operated working interest.

After an extensive evaluation of our exploration activities in Poland and unsuccessful attempts to find commercial levels of hydrocarbons, we have elected to conclude operations in the country. We are evaluating disposition options for our concessions, which had a book value at March 31, 2013 of $12 million.

Oil Sands Mining

 Our Oil Sands Mining operations consist of a 20 percent non-operated working interest in the Athabasca Oil Sands Project (“AOSP”).  Our net synthetic crude oil sales were 51 mbbld in the first quarter of 2013 compared to 44 mbbld in the same period of 2012.  Both mines and the upgrader experienced significantly improved reliability during the first quarter of 2013. Primarily because of reliability improvements, combined production from the Jack Pine and Muskeg River mines set a record bitumen production rate in the first quarter of 2013.  In addition, upgrader availability was 100 percent for the entire first quarter of 2013, allowing the facility to maximize production of lighter synthetic crude oils, which improved realizations and profit margins.

20

Acquisitions and Dispositions

In April 2013, we reached an agreement to sell our interests in the DJ Basin. The transaction is expected to close in mid-2013 and a second quarter loss of approximately $115 million, before closing adjustments, is anticipated on this disposition.

In February 2013, we entered an agreement to convey our interests in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.

In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain, before closing adjustments, was recorded in the first quarter of 2013.

In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million for various indemnities. A $46 million pretax gain, before closing adjustments, was recorded in the first quarter of 2013.

In January 2013, government approval was received for our acquisition of a 20 percent non-operated interest in the onshore South Omo concession in Ethiopia.

We continue to progress the potential sale of assets in an ongoing effort to optimize our portfolio for profitable growth, with a previously stated goal of divesting between $1.5 billion and $3 billion over the period of 2011 through 2013. To date, we have agreed upon or completed approximately $1.3 billion in divestitures.

The above discussions include forward-looking statements with respect to anticipated drilling activity, the timing of closing the sale of our interests in the DJ Basin, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, possible decreased average drilling times in the Eagle Ford resource play, central batteries and pipeline construction projects, the filing of a plan of development for the Atrush Block, anticipated exploration activity in the Gulf of Mexico, Ethiopia, Gabon, Norway, and the Kurdistan Region of Iraq, the development of our in-situ assets, plans to exit Poland and the goal of divesting between $1.5 to $3.0 billion of other assets over the period of 2011 through 2013. The average times to drill a well and expectations as to future drilling times may not be indicative of future drilling times. Factors that could potentially affect anticipated drilling activity, possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, possible decreased average drilling times in the Eagle Ford resource play, central batteries and pipeline construction projects and anticipated exploratory activity in the Gulf of Mexico, Ethiopia, Gabon, Norway, and the Kurdistan Region of Iraq include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, availability of materials and labor, other associated risks with construction projects, the inability to obtain or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other geological, operating and economic considerations. The timing of closing the sale of our interests in the DJ Basin is subject to the satisfaction of customary closing conditions. Plans to exit Poland, the timing of filing the plan of development for the Atrush Block and the projected asset dispositions through 2013 are based on current expectations, estimates, and projections and are not guarantees of future performance. The development of our in-situ assets is dependent on obtaining regulatory approval and future development plans. 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 difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Market Conditions

 Prevailing prices for the various qualities of crude oil and natural gas that we produce significantly impact our revenues and cash flows.  Worldwide prices have been volatile in recent years.  The following table lists benchmark crude oil and natural gas price averages relative to our North America E&P and International E&P segments in the first quarters of 2013 and 2012.

	Three Months Ended March 31,
Benchmark	2013		2012
West Texas Intermediate ("WTI") crude oil (Dollars per barrel)		$94.36		$103.03
Brent (Europe) crude oil (Dollars per barrel)		$112.49		$118.49
Henry Hub natural gas (Dollars per million British thermal units  ("mmbtu"))(a)		$3.34		$2.74

^(a)  Settlement date average.

21

North America E&P

Liquid hydrocarbons – The quality, location and composition of our liquid hydrocarbon production mix will cause our U.S. liquid hydrocarbon realizations to differ from the WTI benchmark. Light sweet crude contains less sulfur and tends to be lighter than sour crude oil so that refining it is less costly and produces higher value products; therefore, light sweet crude is considered of higher quality and typically sells at a price that approximates WTI or at a premium to WTI. The percentage of our North America E&P crude and condensate production that is sweet crude has been increasing as onshore production from the Eagle Ford and Bakken shale plays increases and production from the Gulf of Mexico declines. In the first quarter of 2013, the percentage of our U.S. crude oil and condensate production that was sweet averaged 74 percent compared to 53 percent in the same period of 2012.  In recent years, crude oil sold along the United States Gulf Coast, such as that from the Eagle Ford shale, has been priced at a premium to WTI because the Louisiana Light Sweet benchmark has been tracking Brent, while production from inland areas farther from large refineries has been at a discount to WTI. The proportion of our liquid hydrocarbon sales that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays. NGLs were 14 percent of our North America E&P liquid hydrocarbon sales volumes in the first quarter of 2013 compared to 8 percent in the same period of 2012.

Natural gas –A significant portion of our natural gas production in the lower 48 states of the United States 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 22 percent higher for the first quarter of 2013 compared to the same period of the prior year. 

International E&P

Liquid hydrocarbons – Our international crude oil production is relatively sweet and is generally sold in relation to the Brent crude benchmark, which was 5 percent lower in the first quarter of 2013 than the same quarter of 2012.

Natural gas –Our major international natural gas-producing regions are Europe and Equatorial Guinea.  Natural gas prices in Europe have been considerably higher than in the U.S. in recent years.  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

 The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational problems or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil marker, primarily Western Canadian Select ("WCS"). The decrease in benchmark pricing coupled with the increased WCS discount from WTI in the first quarter of 2013 compared to same period of 2012, combined to create downward pressure on our average realizations.

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 rates. 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 oil prices, respectively.

The table below shows benchmark prices that impacted both our revenues and variable costs for the first quarters of 2013 and 2012:

	Three Months Ended March 31,
Benchmark	2013		2012
WTI crude oil(Dollars per barrel)		$94.36		$103.03
WCS crude oil(Dollars per barrel)(a)		$62.41		$81.51
AECO natural gas sales index (Dollars per mmbtu)(b)		$3.16		$2.18

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

^(b)  Monthly average AECO day ahead index.

22

Results of Operations

Consolidated Results of Operation

Consolidated income before income taxes in the first quarter of 2013 was 5 percent higher than in the same period of 2012 primarily related to the 22 percent increase in sales volumes on a boe basis. The effective tax rate was 73 percent in the first quarter of 2013 compared to 69 percent in the first quarter of 2012, with the increase related to higher income from operations in higher tax jurisdictions, primarily Norway and Libya.

Sales and other operating revenues, including related party are summarized by segment in the following table:

	Three Months Ended March 31,
(In millions)	2013			2012
Sales and other operating revenues, including related party:
North America E&P	$	1,215		$	912
International E&P	1,887			1,663
Oil Sands Mining	388			379
Segment sales and other operating revenues, including related party	$	3,490		$	2,954
Unrealized loss on crude oil derivative instruments	(50		)	—
Total sales and other operating revenues, including related party	$	3,440		$	2,954

Total sales and other operating revenuesincreased $486 million in the first quarter of 2013 from the comparable prior-year period, with increases in each segment. The $303 million increase in the North America E&P segment was primarily due to liquid hydrocarbon net sales volumes which increased 57 percent over the same quarter of 2012. Most of this net sales volume increase is a result of ongoing development programs in the Eagle Ford and Bakken shale resource plays. Partially offsetting this increase were lower liquid hydrocarbon and natural gas realizations. The following table gives details of net sales volumes and average realizations of our North America E&P segment.

	Three Months Ended March 31,
	2013		2012
North America E&P Operating Statistics
Net liquid hydrocarbon sales volumes (mbbld) (a)	141		90
Liquid hydrocarbon average realizations (per bbl)(b) (c)		$86.14		$93.63
Net crude oil and condensate sales volumes (mbbld)	121		83
Crude oil and condensate average realizations (per bbl)(b)		$94.68		$97.28
Net natural gas liquids sales volumes (mbbld)	20		7
Natural gas liquids average realizations (per bbl)(b)		$35.48		$51.55
Net natural gas sales volumes (mmcfd)	340		344
Natural gas average realizations (per mcf)(b)		$3.86		$4.13

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

^(b)  Excludes gains and losses on derivative instruments

^(c)  Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) average liquid hydrocarbon realizations by ($0.37) per bbl for the first quarter of 2013. There were no realized gains (losses) on crude oil derivative instruments in the first quarter of 2012.

The $224 million increase in sales and other operating revenues in the International E&P segment was primarily a result of increased liquid hydrocarbon and natural gas sales volumes from our African operations as previously discussed.  Lower liquid hydrocarbon realizations partially offset the volume impact.

23

The following table gives details of net sales volumes and average realizations of our International E&P segment.

	Three Months Ended March 31,
	2013		2012
International E&P Operating Statistics
Net liquid hydrocarbon salesvolumes (mbbld)(a)
Europe	100		97
Africa	80		52
Total International E&P	180		149
Liquid hydrocarbon average realizations (per bbl)(b)
Europe		$116.13		$123.76
Africa		$97.13		$94.41
Total International E&P		$107.68		$113.55
Net natural gas sales volumes (mmcfd)
Europe(c)	95		104
Africa	473		418
Total International E&P	568		522
Natural gas average realizations (per mcf)(b)
Europe		$12.83		$9.99
Africa		$0.51		$0.24
Total International E&P		$2.57		$2.19

^(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 11 mmcfd and 14 mmcfd for the first quarters of 2013 and 2012.

Oil Sands Mining sales and other operating revenues increased $9 million. Synthetic crude oil sales volumes were 16 percent higher than in the first quarter of 2012, reflecting increased reliability of the mines and upgrader in the first quarter of 2013.  However, an increase in the discount of WCS to WTI resulted in decreases in average realizations during the first quarter of 2013, partially offsetting the positive volume impact.   The following table gives details of net sales volumes and average realizations of our Oil Sands Mining segment.

	Three Months Ended March 31,
	2013		2012
Oil Sands Mining Operating Statistics
Net synthetic crude oil sales volumes (mbbld)(a)	51		44
Synthetic crude oil average realizations (per bbl)		$79.98		$90.88

^(a)  Includes blendstocks.

Unrealized gains and losses on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. In the first quarter of 2013, the net unrealized loss on crude oil derivative instruments was $50 million with no comparable crude oil derivative activity in the same period of 2012. See Note 12 to the consolidated financial statements and Item 3. Quantitative and Qualitative Disclosures About Market Risk for additional information about our derivative positions.

Marketing revenues decreased $409 million in the first quarter of 2013 from the comparable prior-year period. North America E&P segment marketing activities, formerly referred to as supply optimization activities, which include the purchase of commodities from third parties for resale, have been decreasing in 2013 due to market dynamics. Related commodity prices have also been lower in 2013 than in 2012.  These activities serve to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points.  

Income from equity method investments increased $40 million in the first quarter of 2013 from the comparable prior-year period, primarily due to higher LNG realizations and partially due to higher sales volumes since turnarounds at our facilities in Equatorial Guinea reduced sale volumes in the first quarter of 2012.  

24

Net gain on disposal of assetsin the first quarter of 2013 includes a $98 million gain on the sale of our interest in the Neptune gas plant, a $46 million gain on the sale of our remaining assets in Alaska and a $43 million loss on the conveyance of our interest in the Marcellus natural gas shale play to the operator. The net gain on disposal of assets in the first quarter of 2012 consists of the $166 million gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems. See Note 5 to the consolidated financial statements for information about these dispositions.

Production expenses increased $64 million in the first quarter of 2013 from the comparable period of 2012. The increase is primarily related to increased sales volumes in each segment.

Marketing expenses decreased $413 million in the first quarter of 2013 from the same period of 2012, consistent with the marketing revenue decline discussed above.

Exploration expenseswere higher in the first quarter of 2013 than in the same quarter of 2012, primarily due to larger unproved property impairments. The first quarter of 2013 included $340 million in unproved property impairments on Eagle Ford shale leases that either have expired or that we do not expect to drill or extend. The following table summarizes the components of exploration expenses.

	Three Months Ended March 31,
(In millions)	2013		2012
Unproved property impairments	$	383	$	35
Dry well costs	21		23
Geological and geophysical	27		45
Other	34		32
Total exploration expenses	$	465	$	135

Depreciation, depletion and amortization (“DD&A”) increased $173 million in the first quarter of 2013 from the comparable prior-year period.  Our segments apply the units-of-production method to the majority of their assets; therefore, the previously discussed increases in sales volumes generally result in similar changes in DD&A. 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.  A lower International E&P DD&A rate in the first quarter of 2013, primarily due to reserve increases at the end of 2012 for Norway, compared to the same period in 2012 partially offset the impact of higher sales volumes.  The following table provides DD&A rates for each segment.

	Three Months Ended March 31,
($ per boe)	2013		2012
DD&A rate
North America E&P		$27		$23
International E&P		$8		$9
Oil Sands Mining		$12		$13

Impairmentsin the first quarter of 2013 related primarily to the Powder River Basin and to the Ozona development in the Gulf of Mexico. Impairments in the first quarter of 2012 were also primarily related to the Ozona development in the Gulf of Mexico.  See Note 11 to the consolidated financial statements for information about these impairments.

Taxes other than incomeinclude production, severance and ad valorem taxes in the United States which tend to increase or decrease in relation to sales volumes and revenues.

Net interest and otherincreased $22 million in the first quarter of 2013 from the comparable period of 2012 primarily due to lower capitalized interest in 2013.

Provision for income taxesincreased $98 million in the first quarter of 2013 from the comparable period of 2012 primarily due to the increase in pretax income in high tax rate jurisdictions.

The effective income tax rate is influenced by a variety of factors including the geographic 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 items not allocated to segments is shown in corporate and other unallocated items in the segment income table below.

25

Our effective tax rates in the first three months of 2013 and 2012 were 73 percent and 69 percent.   These rates are higher than the U.S. statutory rate of 35 percent due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax rates are in excess of the U.S. statutory rate.  In Libya, where the statutory tax rate is in excess of 90 percent, there remains uncertainty around sustained production and sales levels.  Reliable estimates of 2013 and 2012 annual ordinary income from our Libyan operations could not 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 first three months of 2013 and 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 65 percent and 64 percent for the first three months of 2013 and 2012.

Segment Income (Loss)

	Three Months Ended March 31,
(In millions)	2013			2012
North America E&P	$	(59	)	$	104
International E&P	453			407
Oil Sands Mining	38			38
Segment income	432			549
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(71		)	(71		)
Unrealized loss on crude oil derivative instruments	(32		)	—
Impairments	(10		)	(167		)
Net gain on dispositions	64			106
Net income	$	383		$	417

 North America E&P segment incomedecreased $163 million in the first quarter of 2013 compared to the same period of 2012. The decrease was primarily the result of unproved property impairments, higher DD&A and lower liquid hydrocarbon realizations, partially offset by higher liquid hydrocarbon sales volumes, as discussed above.

International E&P segment incomeincreased $46 million in the first quarter of 2013 compared to the same period of 2012. The increase was primarily related to higher liquid hydrocarbon sales volumes and increased income from equity method investments, partially offset by higher income taxes.  

Critical Accounting Estimates

There have been no changes to our critical accounting estimates subsequent to December 31, 2012.

Accounting Standards Not Yet Adopted

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within U.S. GAAP. An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. We are currently evaluating the potential impact of this accounting standards update on our consolidated results of operations, financial position and cash flows.

26

Cash Flows and Liquidity

Cash Flows

Net cash provided by operating activitieswas $1,528 million in the first three months of 2013, compared to $973 million in the first three months of 2012 primarily reflecting the impact of increased liquid hydrocarbon, natural gas and synthetic crude oil sales volumes on operating income.

Net cash used in investing activitiestotaled $1,037 million in the first three months of 2013, compared to $806 million in the first three months of 2012.  Significant investing activities are additions to property, plant and equipment and disposal of assets.  Additions in both periods primarily related to spending on U.S. unconventional resource plays, particularly the Eagle Ford shale. Disposals of assets totaled $312 million and $208 million in first three months of 2013 and 2012, with 2013 net proceeds primarily related to the sales of our Alaska assets and our interest in the Neptune gas plant. In 2012, net proceeds resulted primarily from the sale of our interests in several Gulf of Mexico crude oil pipeline systems.

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

Net cash used in financing activitieswas $413 million in the first three months of 2013, compared to $157 million in the first three months of 2012.  Repayments of debt at maturity were $114 million in the first three months of 2013 and $53 million in the first three months of 2012. We also repaid all $200 million of our outstanding commercial paper during the first three months of 2013.   Dividends paid of approximately $120 million 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-strategic 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.  Because of the alternatives available to us as discussed above and our 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

Credit Arrangements and Borrowings

 At March 31, 2013, we had no borrowings against our revolving credit facility or under our U.S. commercial paper program that is backed by the revolving credit facility. During the first quarter of 2013, $200 million of commercial paper was issued and $400 million of commercial paper was repaid.

At March 31, 2013, we had $6,544 million in long-term debt outstanding, $68 million of which is due within one year. We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.

Shelf Registration

We have a universal shelf registration statement filed with the SEC under which we, as a "well-known seasoned issuer" for purposes of SEC rules, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

27

Cash-Adjusted-Debt-To-Capital Ratio

 Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 24 percent at March 31, 2013, compared to 25 percent at December 31, 2012.

	March 31,			December 31,
(In millions)	2013			2012
Commercial paper	$	—		$	200
Long-term debt due within one year	68			184
Long-term debt	6,476			6,512
Total debt	$	6,544		$	6,896
Cash	$	768		$	684
Equity	$	18,588		$	18,283
Calculation:
Total debt	$	6,544		$	6,896
Minus cash	768			684
Total debt minus cash	5,776			6,212
Total debt	6,544			6,896
Plus equity	18,588			18,283
Minus cash	768			684
Total debt plus equity minus cash	$	24,364		$	24,495
Cash-adjusted debt-to-capital ratio	24		%	25		%

Capital Requirements

 On April 24, 2013, our Board of Directors approved a dividend of 17 cents per share for the first quarter of 2013, payable June 10, 2013 to stockholders of record at the close of business on May 16, 2013.

As of March 31, 2013, we plan to make contributions of up to $55 million to our funded pension plans in 2013, $17 million of which were made in April 2013.

 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. 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 discussion of liquidity above also contains forward-looking statements regarding planned funding of pension plans, which are based on current expectations, estimates and projections and are not guarantees of actual 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 include prices of and demand for liquid hydrocarbons, natural gas and synthetic crude oil, actions of competitors, disruptions or interruptions of our production or oil sands mining and bitumen upgrading 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, 2013, our total contractual cash obligations were consistent with December 31, 2012.

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 significant changes to our environmental matters subsequent to December 31, 2012.

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Other 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.  

 See Part II Item 1. Legal Proceedings for updated information about ongoing litigation.

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 2012 Annual Report on Form 10-K. Additional disclosures regarding our open derivative positions, such as how they are reported in our consolidated financial statements and how their fair values are measured, may be found in Notes 11 and 12 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, by contract type as of March 31, 2013 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
	10%			25%			10%		25%
Crude oil
Swaps	$	(127	)	$	(317	)	$	127	$	317
Option Collars	(52		)	(160		)	47		155
Total crude oil	(179		)	(477		)	174		472
Natural gas
Futures	(1		)	(1		)	1		1
Total natural gas	(1		)	(1		)	1		1
Total	$	(180	)	$	(478	)	$	175	$	473

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, 2013 is provided in the following table.

					Incremental
					Change in
(In millions)	Fair Value				Fair Value
Financial assets (liabilities): (a)
Interest rate swap agreements	$	18		(b)	$	2
Long-term debt, including amounts due within one year	$	(7,347	)	(b)	$	(231	)

^(a)  Fair values of cash and cash equivalents, receivables, commercial paper, 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, 2013 would be $61 million.

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.  Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our company's design and operation of disclosure controls and procedures were effective for the period ending March 31, 2013.  

In the first quarter of 2013, we completed the update of our existing Enterprise Resource Planning ("ERP") system. This update included a new general ledger, consolidations system and reporting tools. 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.

29

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Three Months Ended
	March 31,
(In millions)	2013			2012
Segment Income (Loss)
North America E&P	$	(59	)	$	104
International E&P	453			407
Oil Sands Mining	38			38
Segment income	432			549
Items not allocated to segments, net of income taxes	(49		)	(132		)
Net income	$	383		$	417
Capital Expenditures(a)
North America E&P	$	970		$	829
International E&P	225			138
Oil Sands Mining	45			52
Corporate	30			44
Total	$	1,270		$	1,063
Exploration Expenses
North America E&P	$	435		$	106
International E&P	30			29
Total	$	465		$	135

^(a)  Capital expenditures include changes in accruals.

30

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Three Months Ended
	March 31,
Net Sales Volumes	2013	2012
North America E&P
Crude Oil and Condensate (mbbld)	121	83
Natural Gas Liquids (mbbld)	20	7
Total Liquid Hydrocarbons	141	90
Natural Gas (mmcfd)	340	344
Total North America E&P (mboed)	198	147
International E&P
Liquid Hydrocarbons (mbbld)
Europe	100	97
Africa	80	52
Total Liquid Hydrocarbons	180	149
Natural Gas (mmcfd)
Europe(b)	95	104
Africa	473	418
Total Natural Gas	568	522
Total International E&P (mboed)	274	236
Oil Sands Mining
Synthetic Crude Oil (mbbld)(c)	51	44
Total Company (mboed)	523	427
Net Sales Volumes of Equity Method Investees
LNG (mtd)	6,787	6,291
Methanol (mtd)	1,410	1,312

^(b)  Includes natural gas acquired for injection and subsequent resale of 11 mmcfd and 14 mmcfd for the first quarters of 2013 and 2012.

^(c)  Includes blendstocks.

31

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Three Months Ended
	March 31,
Average Realizations(d)	2013		2012
North America E&P
Crude Oil and Condensate (per bbl)		$94.68		$97.28
Natural Gas Liquids (per bbl)		$35.48		$51.55
Total Liquid Hydrocarbons(e)		$86.14		$93.63
Natural Gas (per mcf)		$3.86		$4.13
International E&P
Liquid Hydrocarbons (per bbl)
Europe		$116.13		$123.76
Africa		$97.13		$94.41
Total Liquid Hydrocarbons		$107.68		$113.55
Natural Gas (per mcf)
Europe		$12.83		$9.99
Africa(f)		$0.51		$0.24
Total Natural Gas		$2.57		$2.19
Oil Sands Mining
Synthetic Crude Oil (per bbl)		$79.98		$90.88

^(d)  Excludes gains and losses on derivative instruments.

^(e)  Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) average liquid hydrocarbon realizations by ($0.37) per bbl for the first quarter of 2013. There were no realized gains (losses) on crude oil derivative instruments in the first quarter of 2012.

^(f)  Primarily represents fixed prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC and Equatorial Guinea LNG Holdings Limited, which are equity method investees.  We include our share of income from each of these equity method investees in our International E&P segment.

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Part II – OTHER INFORMATION

Item 1. Legal Proceedings

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 those 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. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. We are vigorously defending this litigation.  The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain.  We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.

Environmental

 We continue to work with the North Dakota Department of Health to resolve voluntary disclosures we made in 2009 relating to potential Clean Air Act violations relating to our operations on state lands in the Bakken shale. The proposed settlement of the fine is $169,800 and is expected to be executed by the parties in the second quarter of 2013.

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 2012 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 during the quarter ended March 31, 2013, 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	Average Price	Total Number of Shares Purchased as Part of Publicly Announced	Approximate Dollar Value of Shares that May Yet Be Purchased Under the
Period	Shares Purchased (a)(b)	Paid per Share	Plans or Programs(c)	Plans or Programs(c)
01/01/13 – 01/31/13	5,910	$31.34	—	$1,780,609,536
02/01/13 – 02/28/13	107,389	$33.74	—	$1,780,609,536
03/01/13 – 03/31/13	34,051	$33.56	—	$1,780,609,536
Total	147,350	$33.60	—

^(a)  120,431 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)  In March 2013, 26,919 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, 2013, 78 million split-adjusted 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.

Item 4. Mine Safety Disclosures

 Not applicable.

33

Item 6.  Exhibits

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

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.	Filed Herewith	Furnished Herewith
10.1	Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan					X
10.2	Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan					X
12.1	Computation of Ratio of Earnings to Fixed Charges.					X
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.					X
31.2	Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
32.1	Certification of Chairman, President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.					X
32.2	Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.					X
101.INS	XBRL Instance Document.					X
101.SCH	XBRL Taxonomy Extension Schema.					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.					X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase.					X
101.DEF	XBRL Taxonomy Extension Definition Linkbase.					X
101.LAB	XBRL Taxonomy Extension Label Linkbase.					X

34

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 10, 2013		MARATHON OIL CORPORATION
	By:	/s/ Michael K. Stewart
		Michael K. Stewart
		Vice President, Finance and Accounting, Controller and Treasurer

35

Exhibit Index

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.	Filed Herewith	Furnished Herewith
10.1	Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan					X
10.2	Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan					X
12.1	Computation of Ratio of Earnings to Fixed Charges.					X
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.					X
31.2	Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
32.1	Certification of Chairman, President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.					X
32.2	Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.					X
101.INS	XBRL Instance Document.					X
101.SCH	XBRL Taxonomy Extension Schema.					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase.					X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase.					X
101.DEF	XBRL Taxonomy Extension Definition Linkbase.					X
101.LAB	XBRL Taxonomy Extension Label Linkbase.					X

EX-10.1

Exhibit 10.1

MARATHON OIL CORPORATION

2012 INCENTIVE COMPENSATION PLAN

PERFORMANCE UNIT AWARD AGREEMENT

2013 - 2015 PERFORMANCE CYCLE

Section 16 Officer

1.Grant of Performance Units. Pursuant to this Award Agreement and the Marathon Oil Corporation 2012 Incentive Compensation Plan (the “Plan”), MARATHON OIL CORPORATION (the “Corporation”) hereby grants to [NAME] (the “Participant”), an employee of the Corporation or a Subsidiary, on February 26, 2013, [NUMBER] Performance Units, subject to the terms and conditions set forth in this Award Agreement and the Plan. The Participant has no legally binding right to any payment prior to the vesting of the Performance Units in accordance with the terms of this Award Agreement.

2. Relationship to the Plan and Definitions.

(a)This grant of Performance Units is subject to all of the terms, conditions and provisions of the Plan and administrative interpretations thereunder, if any, that have been adopted by the Committee. Except as defined in this Award Agreement, capitalized terms shall have the same meanings ascribed to them under the Plan. To the extent that any provision of this Award Agreement conflicts with the express terms of the Plan, the terms of the Plan shall control and, if necessary, the applicable provisions of this Award Agreement shall be hereby deemed amended so as to carry out the purpose and intent of the Plan.

(b)For purposes of this Award Agreement:

“Beginning Stock Price” means the average of the daily closing price of Common Stock for each trading day of December 2012, historically adjusted, if necessary, for any stock split, stock dividend, recapitalization, or similar corporate events that occur during the measurement period.

“Change in Control,” unless otherwise defined by the Committee, means a change in control of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Securities Exchange Act of 1934, as amended, whether or not the Corporation is then subject to such reporting requirement; provided, that, without limitation, such a change in control shall be deemed to have occurred if:

(i)any person (as defined in Sections 13(d) and 14(d) of the Exchange Act) (a “Person”) is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Corporation (not including in the amount of the securities beneficially owned by such person any such securities acquired directly from the Corporation or its affiliates) representing twenty percent (20%) or more of the combined voting power of the Corporation's then outstanding voting securities; provided, however, that for purposes of this Plan the term “Person” shall not include (A) the Corporation or any of its subsidiaries, (B) a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation or any of its subsidiaries, (C) an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) a corporation owned, directly or indirectly, by the stockholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation; and provided, further, however, that for purposes of this paragraph (i), there shall be excluded any Person who becomes such a beneficial owner in connection with an Excluded Transaction (as defined in paragraph (iii) below);

(ii)the following individuals cease for any reason to constitute a majority of the number of Directors then serving: individuals who, on the date hereof, constitute the Board and any new Director (other than a Director whose initial assumption of office is in connection with an actual or threatened election contest including but not limited to a consent solicitation, relating to the election of Directors of the Corporation) whose appointment or election by the Board or nomination for election by the Corporation's stockholders was approved or recommended by a vote of at least two-thirds (2/3)

of the directors then still in office who either were Directors on the date hereof or whose appointment, election or nomination for election was previously so approved; or

(iii)there is consummated a merger or consolidation of the Corporation or any direct or indirect subsidiary thereof with any other corporation, other than a merger or consolidation (an “Excluded Transaction”) which would result in the holders of the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving corporation or any parent thereof) at least 50% of the combined voting power of the voting securities of the entity surviving the merger or consolidation (or the parent of such surviving entity) immediately after such merger or consolidation, or the stockholders of the Corporation approve a plan of complete liquidation of the Corporation, or there is consummated the sale or other disposition of all or substantially all of the Corporation's assets.

Notwithstanding any other provision to the contrary, in no event shall the transfer of ownership interests in the Corporation in and of itself constitute a Change in Control under this Award Agreement.

“Cumulative Dividends” means the sum of all cash dividends paid on a share of Common Stock during the Performance Cycle.

“Employment” means employment with the Corporation or any of its Subsidiaries. For purposes of this Award Agreement, Employment shall also include any period of time during which the Participant is on Disability status.

“End Stock Price” means the average of the daily closing price of Common Stock for each trading day of December 2015, historically adjusted, if necessary, for any stock split, stock dividend, recapitalization, or similar corporate events that occur during the measurement period.

“Forfeiture Event” means the occurrence of at least one of the following (a) the Corporation is required, pursuant to a determination made by the Securities and Exchange Commission or by the Audit Committee of the Board, to prepare a material accounting restatement due to the noncompliance of the Corporation with any financial reporting requirement under applicable securities laws as a result of misconduct, and the Committee determines that (1) the Participant knowingly engaged in the misconduct, (2) the Participant was grossly negligent with respect to such misconduct or (3) the Participant knowingly or grossly negligently failed to prevent the misconduct or (b) the Committee concludes that the Participant engaged in fraud, embezzlement or other similar misconduct materially detrimental to the Corporation.

“Payout Value” means, except as provided in Paragraph 6 or Paragraph 8 of this Award Agreement, for each Performance Unit the Fair Market Value of a share of Common Stock on the date of the Committee's first regularly scheduled meeting following the end of the Performance Cycle.

“Peer Group” means the following group of eleven companies (in addition to the Corporation): Anadarko Petroleum Corp., Apache Corp., Chesapeake Energy Corp., Devon Energy Corp., Encana Corp., EOG Resources Inc., Hess Corp., Murphy Oil Corp., Noble Energy Inc., Occidental Petroleum Corp., and Talisman Energy. If, at the end of the Performance Cycle, one or more than one of the corporations in the Peer Group either ceases to exist or is no longer a company for which TSR can be calculated from publicly available information, then one or more of ConocoPhillips, Pioneer Natural Resources Company and Southwestern Energy Company shall be substituted as members of the Peer Group, in the order in which they are here listed, to ensure that the Peer Group consists of eleven companies (in addition to the Corporation).

“Performance Cycle” means the period from January 1, 2013 to December 31, 2015.

“Performance Unit” means an unfunded and unsecured right to receive a cash payment determined in accordance with the terms of this Award Agreement and the Plan.

“Retirement” means (i) for an Employee participating in the Retirement Plan, termination on or after the time at which the Employee is eligible for retirement under the Retirement Plan, or (ii) for an Employee not participating in the Retirement Plan, (a) for an Employee with ten or more years of Employment, termination on or after the Employee's 50th birthday or (b) termination on or after the Employee's 65th birthday.

“Retirement Plan” means the Retirement Plan of Marathon Oil Company, or a successor plan to such plan, as applicable.

“Total Shareholder Return” or “TSR” means the number derived using the following formula:

(End Stock Price - Beginning Stock Price) + Cumulative Dividends

Beginning Stock Price.

“TSR Percentile Ranking” means the relative ranking of the Corporation's Total Shareholder Return for the Performance Cycle as compared to the Total Shareholder Return of the Peer Group companies during the Performance Cycle, expressed as a percentile ranking.

“Vesting Percentage” means the percentage (between 0% and 200%) determined by the Committee in accordance with the procedures set forth in Paragraph 3, which shall be used to determine the value of each Performance Unit.

3.Determination of Number of Performance Units Eligible for Vesting.

(a)The Committee shall determine the number of Performance Units eligible for vesting by multiplying (i) the number of Performance Units granted under Paragraph 1 of this Award Agreement and (ii) the Vesting Percentage.

(b)Except as provided in Paragraphs 6 and 8 of this Award Agreement, the Vesting Percentage will depend upon the Corporation's TSR Percentile Ranking. At its first regularly scheduled meeting following the close of the Performance Cycle, the Committee shall determine the TSR Percentile Ranking and the Vesting Percentage as follows based on the TSR of the Corporation relative to the TSR of the other corporations in the Peer Group:

TSR Ranking of	TSR Percentile	Vesting
Corporation	Ranking	Percentage
1st	100%	200%
2nd	90.9%	182%
3rd	81.8%	164%
4th	72.7%	145%
5th	63.6%	127%
6th	54.5%	109%
7th	45.4%	91%
8th	36.3%	73%
9th	27.2%	54%
10th	18.1%	—%
11th	9%	—%
12th	—%	—%

(c)Notwithstanding anything herein to the contrary, if the TSR calculated for the Performance Cycle is negative, then the Vesting Percentage shall not exceed 100%.

(d)Notwithstanding anything herein to the contrary, the Committee has sole and absolute authority and discretion to reduce the Vesting Percentage, including to 0%, as it may deem appropriate.

4.Vesting of Performance Units. Unless the Participant's right to the Performance Units is previously forfeited or vested in accordance with Paragraphs 5, 6, or 8 or is vested in accordance with Paragraph 7, the Committee shall certify in writing on the date of its first regularly scheduled meeting following the end of the Performance Period whether and to what extent the performance goal described in Paragraph 3 has been achieved and shall determine the Vesting Percentage and number of Performance Units that vest. Following the Committee's certification, the Participant shall vest in and be entitled to receive a cash payment equal to the product of (a) the

number of vested Performance Units, multiplied by (b) the Payout Value. Such cash payment shall be made as soon as administratively feasible following the Committee's certification and, in any event, on or before March 15, 2016. If, in accordance with the Committee's determination under Paragraph 3, the Vesting Percentage is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9), if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be satisfied in full.

5.Termination of Employment Other than due to Retirement. If Participant's Employment is terminated prior to the close of the Performance Cycle for any reason other than death or Retirement, the Participant's right to the Performance Units shall be forfeited in its entirety as of such termination, and the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be terminated.

6.Vesting Upon Termination of Employment due to Death. If Participant's Employment is terminated by reason of death prior to the close of the Performance Cycle, the Participant's right to receive the Performance Units shall vest in full as of the date of death, the Vesting Percentage shall be 100%, and the Payout Value for each Performance Unit shall be the Fair Market of a share of Common Stock on the date of the Participant's death. A cash payment equal to the vested value of the Performance Units shall be made to the Participant's estate on the first day of the third month following the death of the Participant. Such vesting and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9) shall satisfy the rights of the Participant and the obligations of the Corporation under this Award Agreement in full.

7.Vesting Upon Termination of Employment due to Retirement. In the event of the Retirement of the Participant on or after completion of half of the Performance Cycle, the Participant may vest, at the discretion of the Committee, in a number of Performance Units equal to or less than the product of (a) the percentage equal to the days of Participant's Employment during the Performance Cycle divided by the total days in the Performance Cycle, (b) the number of Performance Units granted under this Award Agreement, and (c) the Vesting Percentage, as determined by the Committee under Paragraph 3. Following the Committee's determination under this Paragraph 7, the Participant shall be entitled to receive a cash payment equal to the product of (a) the number of vested Performance Units, multiplied by (b) the Payout Value. Such cash payment shall be made as soon as administratively feasible following the Committee's vesting determination under this Paragraph 7 and, in any event, on or before March 15, 2016. If, in accordance with the Committee's determination, the Vesting Percentage is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9), if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be satisfied in full.

8.Vesting Upon a Change of Control. Notwithstanding anything herein to the contrary, upon the occurrence of a Change in Control prior to the end of the Performance Cycle, the Participant's right to receive the Performance Units, unless previously forfeited pursuant to Paragraph 5 or vested pursuant to Paragraph 6, shall vest in full, the Vesting Percentage shall be 100%, and the Payout Value for each Performance Unit shall be the Fair Market Value of a share of Common Stock on the effective date of the Change in Control. A cash payment equal to the vested value of the Performance Units shall be made on the first day of the third month following the Change in Control; provided, however that if such Change in Control fails to qualify as a “change in control event” within the meaning of Treas. Regs. section 1.409A-3(i)(5), then the cash payment will be made during the first week of January 2015. Such vesting and the making of the related cash payment shall satisfy the rights of the Participant and the obligations of the Corporation under this Award Agreement in full.

9.Dividend Equivalents. With respect to each of the Performance Units granted under Paragraph 1, the Participant shall be credited with Dividend Equivalents equal to the amount per share of Common Stock of any ordinary cash dividends declared by the Board with record dates during the period beginning on the first day of the Performance Cycle and ending on the earliest to occur of: (a) the last day of the Performance Cycle, (b) the effective date of a Change in Control and (c) the date on which the Performance Units otherwise vest or are forfeited in accordance with Paragraphs 5, 6 or 7. The Corporation shall pay in cash to the Participant an amount equal to (x) the sum of the aggregate amounts of such Dividend Equivalents credited to the Participant, plus interest that accrues at a rate equal to the interest crediting rate under the Stable Value investment option under the Marathon Oil Company Thrift Plan for the applicable period that accrues on the amounts of such Dividend Equivalents from the date each such Dividend Equivalent is credited until the date of payment, if any, multiplied by (y) the Vesting Percentage that is applicable to the related Performance Units, with such amount to be paid as and when any cash payment with respect

to the related Performance Units is paid. Any Dividend Equivalents shall be forfeited as and when the related Performance Units are forfeited in accordance with the terms of the Award Agreement.

10.Repayment or Forfeiture Resulting from Forfeiture Event.

(a)If there is a Forfeiture Event either while the Participant is employed or within two years after termination of the Participant's Employment, then the Committee may, but is not obligated to, cause some or all of the Participant's outstanding Performance Units to be forfeited by the Participant.

(b)If there is a Forfeiture Event either while the Participant is employed or within two years after termination of the Participant's Employment and a payment has previously been made in settlement of Performance Units granted under this Award Agreement, the Committee may, but is not obligated to, require that the Participant pay to the Corporation an amount (the “Forfeiture Amount”) up to (but not in excess of) the amount paid in settlement of the Performance Units.

(c) This Paragraph 10 shall apply notwithstanding any provision of this Award Agreement to the contrary and is meant to provide the Corporation with rights in addition to any other remedy which may exist in law or in equity. This Paragraph 10 shall not apply to the Participant following the effective time of a Change in Control.

11.Taxes. Pursuant to Section 10 of the Plan, the Corporation or its designated representative shall have the right to withhold applicable taxes from the cash otherwise payable to the Participant, or from other compensation payable to the Participant, at the time of the vesting and delivery of such cash payment.

12.No Stockholder Rights. The Participant shall in no way be entitled to any of the rights of a stockholder of the Corporation as a result of this Award Agreement. Specifically, the Performance Units do not have voting rights.

13.Nonassignability. Upon the Participant's death, the Performance Units may be transferred by will or by the laws governing the descent and distribution of the Participant's estate. Otherwise, the Participant may not sell, transfer, assign, pledge or otherwise encumber any portion of the Performance Units, and any attempt to sell, transfer, assign, pledge, or encumber any portion of the Performance Units shall have no effect.

14.No Employment Guaranteed. Nothing in this Award Agreement shall give the Participant any rights to (or impose any obligations for) continued Employment by the Corporation or any Affiliate thereof or successor thereto, nor shall it give such entities any rights (or impose any obligations) with respect to continued performance of duties by the Participant.

15.Modification of Agreement. Any modification of this Award Agreement shall be binding only if evidenced in writing and signed by an authorized representative of the Corporation, provided that no modification may, without the consent of the Participant, adversely affect the rights of the Participant under this Award Agreement.

Marathon Oil Corporation

By

Authorized Officer

EX-10.2

Exhibit 10.2

MARATHON OIL CORPORATION

2012 INCENTIVE COMPENSATION PLAN

PERFORMANCE UNIT AWARD AGREEMENT

2013 - 2015 PERFORMANCE CYCLE

Officer

1.Grant of Performance Units. Pursuant to this Award Agreement and the Marathon Oil Corporation 2012 Incentive Compensation Plan (the “Plan”), MARATHON OIL CORPORATION (the “Corporation”) hereby grants to [NAME] (the “Participant”), an employee of the Corporation or a Subsidiary, on February 26, 2013, [NUMBER] Performance Units, subject to the terms and conditions set forth in this Award Agreement and the Plan. The Participant has no legally binding right to any payment prior to the vesting of the Performance Units in accordance with the terms of this Award Agreement.

2. Relationship to the Plan and Definitions.

(a)This grant of Performance Units is subject to all of the terms, conditions and provisions of the Plan and administrative interpretations thereunder, if any, that have been adopted by the Committee. Except as defined in this Award Agreement, capitalized terms shall have the same meanings ascribed to them under the Plan. To the extent that any provision of this Award Agreement conflicts with the express terms of the Plan, the terms of the Plan shall control and, if necessary, the applicable provisions of this Award Agreement shall be hereby deemed amended so as to carry out the purpose and intent of the Plan.

(b)For purposes of this Award Agreement:

“Beginning Stock Price” means the average of the daily closing price of Common Stock for each trading day of December 2012, historically adjusted, if necessary, for any stock split, stock dividend, recapitalization, or similar corporate events that occur during the measurement period.

“Change in Control,” unless otherwise defined by the Committee, means a change in control of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Securities Exchange Act of 1934, as amended, whether or not the Corporation is then subject to such reporting requirement; provided, that, without limitation, such a change in control shall be deemed to have occurred if:

(i)any person (as defined in Sections 13(d) and 14(d) of the Exchange Act) (a “Person”) is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Corporation (not including in the amount of the securities beneficially owned by such person any such securities acquired directly from the Corporation or its affiliates) representing twenty percent (20%) or more of the combined voting power of the Corporation's then outstanding voting securities; provided, however, that for purposes of this Plan the term “Person” shall not include (A) the Corporation or any of its subsidiaries, (B) a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation or any of its subsidiaries, (C) an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) a corporation owned, directly or indirectly, by the stockholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation; and provided, further, however, that for purposes of this paragraph (i), there shall be excluded any Person who becomes such a beneficial owner in connection with an Excluded Transaction (as defined in paragraph (iii) below);

(ii)the following individuals cease for any reason to constitute a majority of the number of Directors then serving: individuals who, on the date hereof, constitute the Board and any new Director (other than a Director whose initial assumption of office is in connection with an actual or threatened election contest including but not limited to a consent solicitation, relating to the election of Directors of the Corporation) whose appointment or election by the Board or nomination for election by the Corporation's stockholders was approved or recommended by a vote of at least two-thirds (2/3) of the directors then still in office who either were Directors on the date hereof or whose appointment, election or nomination for election was previously so approved; or

(iii)there is consummated a merger or consolidation of the Corporation or any direct or indirect subsidiary thereof with any other corporation, other than a merger or consolidation (an “Excluded Transaction”) which would result in the holders of the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving corporation or any parent thereof) at least 50% of the combined voting power of the voting securities of the entity surviving the merger or consolidation (or the parent of such surviving entity) immediately after such merger or consolidation, or the stockholders of the Corporation approve a plan of complete liquidation of the Corporation, or there is consummated the sale or other disposition of all or substantially all of the Corporation's assets.

Notwithstanding any other provision to the contrary, in no event shall the transfer of ownership interests in the Corporation in and of itself constitute a Change in Control under this Award Agreement.

“Cumulative Dividends” means the sum of all cash dividends paid on a share of Common Stock during the Performance Cycle.

“Employment” means employment with the Corporation or any of its Subsidiaries. For purposes of this Award Agreement, Employment shall also include any period of time during which the Participant is on Disability status.

“End Stock Price” means the average of the daily closing price of Common Stock for each trading day of December 2015, historically adjusted, if necessary, for any stock split, stock dividend, recapitalization, or similar corporate events that occur during the measurement period.

“Payout Value” means, except as provided in Paragraph 6 or Paragraph 8 of this Award Agreement, for each Performance Unit the Fair Market Value of a share of Common Stock on the date of the Committee's first regularly scheduled meeting following the end of the Performance Cycle.

“Peer Group” means the following group of eleven companies (in addition to the Corporation): Anadarko Petroleum Corp., Apache Corp., Chesapeake Energy Corp., Devon Energy Corp., Encana Corp., EOG Resources Inc., Hess Corp., Murphy Oil Corp., Noble Energy Inc., Occidental Petroleum Corp., and Talisman Energy. If, at the end of the Performance Cycle, one or more than one of the corporations in the Peer Group either ceases to exist or is no longer a company for which TSR can be calculated from publicly available information, then one or more of ConocoPhillips, Pioneer Natural Resources Company and Southwestern Energy Company shall be substituted as members of the Peer Group, in the order in which they are here listed, to ensure that the Peer Group consists of eleven companies (in addition to the Corporation).

“Performance Cycle” means the period from January 1, 2013 to December 31, 2015.

“Performance Unit” means an unfunded and unsecured right to receive a cash payment determined in accordance with the terms of this Award Agreement and the Plan.

“Retirement” means (i) for an Employee participating in the Retirement Plan, termination on or after the time at which the Employee is eligible for retirement under the Retirement Plan, or (ii) for an Employee not participating in the Retirement Plan, (a) for an Employee with ten or more years of Employment, termination on or after the Employee's 50th birthday or (b) termination on or after the Employee's 65th birthday.

“Retirement Plan” means the Retirement Plan of Marathon Oil Company, or a successor plan to such plan, as applicable.

“Total Shareholder Return” or “TSR” means the number derived using the following formula:

(End Stock Price - Beginning Stock Price) + Cumulative Dividends

Beginning Stock Price.

“TSR Percentile Ranking” means the relative ranking of the Corporation's Total Shareholder Return for the Performance Cycle as compared to the Total Shareholder Return of the Peer Group companies during the Performance Cycle, expressed as a percentile ranking.

“Vesting Percentage” means the percentage (between 0% and 200%) determined by the Committee in accordance with the procedures set forth in Paragraph 3, which shall be used to determine the value of each Performance Unit.

3.Determination of Number of Performance Units Eligible for Vesting.

(a)The Committee shall determine the number of Performance Units eligible for vesting by multiplying (i) the number of Performance Units granted under Paragraph 1 of this Award Agreement and (ii) the Vesting Percentage.

(b)Except as provided in Paragraphs 6 and 8 of this Award Agreement, the Vesting Percentage will depend upon the Corporation's TSR Percentile Ranking. At its first regularly scheduled meeting following the close of the Performance Cycle, the Committee shall determine the TSR Percentile Ranking and the Vesting Percentage as follows based on the TSR of the Corporation relative to the TSR of the other corporations in the Peer Group:

TSR Ranking of	TSR Percentile	Vesting
Corporation	Ranking	Percentage
1st	100%	200%
2nd	90.9%	182%
3rd	81.8%	164%
4th	72.7%	145%
5th	63.6%	127%
6th	54.5%	109%
7th	45.4%	91%
8th	36.3%	73%
9th	27.2%	54%
10th	18.1%	—%
11th	9%	—%
12th	—%	—%

(c)Notwithstanding anything herein to the contrary, if the TSR calculated for the Performance Cycle is negative, then the Vesting Percentage shall not exceed 100%.

(d)Notwithstanding anything herein to the contrary, the Committee has sole and absolute authority and discretion to reduce the Vesting Percentage, including to 0%, as it may deem appropriate.

4.Vesting of Performance Units. Unless the Participant's right to the Performance Units is previously forfeited or vested in accordance with Paragraphs 5, 6, or 8 or is vested in accordance with Paragraph 7, the Committee shall certify in writing on the date of its first regularly scheduled meeting following the end of the Performance Period whether and to what extent the performance goal described in Paragraph 3 has been achieved and shall determine the Vesting Percentage and number of Performance Units that vest. Following the Committee's certification, the Participant shall vest in and be entitled to receive a cash payment equal to the product of (a) the number of vested Performance Units, multiplied by (b) the Payout Value. Such cash payment shall be made as soon as administratively feasible following the Committee's certification and, in any event, on or before March 15, 2016. If, in accordance with the Committee's determination under Paragraph 3, the Vesting Percentage is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9), if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be satisfied in full.

5.Termination of Employment Other than due to Retirement. If Participant's Employment is terminated prior to the close of the Performance Cycle for any reason other than death or Retirement, the Participant's right to the Performance Units shall be forfeited in its entirety as of such termination, and the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be terminated.

6.Vesting Upon Termination of Employment due to Death. If Participant's Employment is terminated by reason of death prior to the close of the Performance Cycle, the Participant's right to receive the Performance Units shall vest in full as of the date of death, the Vesting Percentage shall be 100%, and the Payout Value for each Performance Unit shall be the Fair Market of a share of Common Stock on the date of the Participant's death. A cash payment equal to the vested value of the Performance Units shall be made to the Participant's estate on the first day of the third month following the death of the Participant. Such vesting and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9) shall satisfy the rights of the Participant and the obligations of the Corporation under this Award Agreement in full.

7.Vesting Upon Termination of Employment due to Retirement. In the event of the Retirement of the Participant on or after completion of half of the Performance Cycle, the Participant may vest, at the discretion of the Committee, in a number of Performance Units equal to or less than the product of (a) the percentage equal to the days of Participant's Employment during the Performance Cycle divided by the total days in the Performance Cycle, (b) the number of Performance Units granted under this Award Agreement, and (c) the Vesting Percentage, as determined by the Committee under Paragraph 3. Following the Committee's determination under this Paragraph 7, the Participant shall be entitled to receive a cash payment equal to the product of (a) the number of vested Performance Units, multiplied by (b) the Payout Value. Such cash payment shall be made as soon as administratively feasible following the Committee's vesting determination under this Paragraph 7 and, in any event, on or before March 15, 2016. If, in accordance with the Committee's determination, the Vesting Percentage is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units and the making of the related cash payment (including, if applicable, a payment for Dividend Equivalents, as provided in Paragraph 9), if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be satisfied in full.

8.Vesting Upon a Change of Control. Notwithstanding anything herein to the contrary, upon the occurrence of a Change in Control prior to the end of the Performance Cycle, the Participant's right to receive the Performance Units, unless previously forfeited pursuant to Paragraph 5 or vested pursuant to Paragraph 6, shall vest in full, the Vesting Percentage shall be 100%, and the Payout Value for each Performance Unit shall be the Fair Market Value of a share of Common Stock on the effective date of the Change in Control. A cash payment equal to the vested value of the Performance Units shall be made on the first day of the third month following the Change in Control; provided, however that if such Change in Control fails to qualify as a “change in control event” within the meaning of Treas. Regs. section 1.409A-3(i)(5), then the cash payment will be made during the first week of January 2015. Such vesting and the making of the related cash payment shall satisfy the rights of the Participant and the obligations of the Corporation under this Award Agreement in full.

9.Dividend Equivalents. With respect to each of the Performance Units granted under Paragraph 1, the Participant shall be credited with Dividend Equivalents equal to the amount per share of Common Stock of any ordinary cash dividends declared by the Board with record dates during the period beginning on the first day of the Performance Cycle and ending on the earliest to occur of: (a) the last day of the Performance Cycle, (b) the effective date of a Change in Control and (c) the date on which the Performance Units otherwise vest or are forfeited in accordance with Paragraphs 5, 6 or 7. The Corporation shall pay in cash to the Participant an amount equal to (x) the sum of the aggregate amounts of such Dividend Equivalents credited to the Participant, plus interest that accrues at a rate equal to the interest crediting rate under the Stable Value investment option under the Marathon Oil Company Thrift Plan for the applicable period that accrues on the amounts of such Dividend Equivalents from the date each such Dividend Equivalent is credited until the date of payment, if any, multiplied by (y) the Vesting Percentage that is applicable to the related Performance Units, with such amount to be paid as and when any cash payment with respect to the related Performance Units is paid. Any Dividend Equivalents shall be forfeited as and when the related Performance Units are forfeited in accordance with the terms of the Award Agreement.

10.Taxes. Pursuant to Section 10 of the Plan, the Corporation or its designated representative shall have the right to withhold applicable taxes from the cash otherwise payable to the Participant, or from other compensation payable to the Participant, at the time of the vesting and delivery of such cash payment.

11.No Stockholder Rights. The Participant shall in no way be entitled to any of the rights of a stockholder of the Corporation as a result of this Award Agreement. Specifically, the Performance Units do not have voting rights.

12.Nonassignability. Upon the Participant's death, the Performance Units may be transferred by will or by the laws governing the descent and distribution of the Participant's estate. Otherwise, the Participant may not sell, transfer, assign, pledge or otherwise encumber any portion of the Performance Units, and any attempt to sell, transfer, assign, pledge, or encumber any portion of the Performance Units shall have no effect.

13.No Employment Guaranteed. Nothing in this Award Agreement shall give the Participant any rights to (or impose any obligations for) continued Employment by the Corporation or any Affiliate thereof or successor thereto, nor shall it give such entities any rights (or impose any obligations) with respect to continued performance of duties by the Participant.

14.Modification of Agreement. Any modification of this Award Agreement shall be binding only if evidenced in writing and signed by an authorized representative of the Corporation, provided that no modification may, without the consent of the Participant, adversely affect the rights of the Participant under this Award Agreement.

Marathon Oil Corporation

By

Authorized Officer

EX-12.1

Exhibit 12.1

Marathon Oil Corporation

Computation of Ratio of Earnings to Fixed Charges

TOTAL ENTERPRISE BASIS - Unaudited

	Three Months Ended
(In millions)	March 31,
	2013		2012
Portion of rentals representing interest,
including discontinued operations	$	6	$	6
Capitalized interest,
including discontinued operations	5		19
Other interest and fixed charges,
including discontinued operations	73		54
Total fixed charges (A)	$	84	$	79
Earnings-pretax income with
applicable adjustments (B)	$	1,442	$	1,399
Ratio of (B) to (A)	17.17		17.71

EX-31.1

Exhibit 31.1

MARATHON OIL CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

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

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

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

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

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

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

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

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

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

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

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

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

May 10, 2013	/s/ Clarence P. Cazalot, Jr.
	Clarence P. Cazalot, Jr.
	Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

MARATHON OIL CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Janet F. Clark, certify that:

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

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

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

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

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

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

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

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

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

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

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

May 10, 2013	/s/ Janet F. Clark
	Janet F. Clark
	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Marathon Oil Corporation (the “Company”) on Form 10-Q for the period ending March 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Clarence P. Cazalot, Jr., Chairman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

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

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

May 10, 2013

/s/ Clarence P. Cazalot, Jr.

Clarence P. Cazalot, Jr.

Chairman, President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Marathon Oil Corporation (the “Company”) on Form 10-Q for the period ending March 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Janet F. Clark, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

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

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

May 10, 2013

/s/ Janet F. Clark

Janet F. Clark

Executive Vice President and Chief Financial Officer

XML

Segment Information (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Reconciliation Of Segment Revenues To Revenues As Presented On Income Statement [Abstract]
Segment reporting revenue from external customers	$ 3,870	$ 3,793
Marketing revenues	430	839
Sales and other operating revenues, including related party	3,440	2,954
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(71)	(71)
Unrealized Loss On Derivatives Net Of Tax	(32)	0
Impairments, not allocated to segments	(10)	(167)
Gain (loss) on dispositions, not allocated to segments	64	106
Net income	$ 383	$ 417

XML

Incentive Based Compensation Plans (Details 4-Restricted) (USD $)	3 Months Ended
	Mar. 31, 2013
Restricted Stock
Beginning year unvested restricted stock	4,177,884
Granted restricted stock	137,722
Vested restricted stock	(493,840)
Forfeited restricted stock	(78,778)
End of year unvested restricted stock	3,742,988
Beginning year weighted average grant date fair value unvested restricted stock	$ 29.02
Granted restricted stock weighted average grant date fair value restricted stock	$ 33.04
Vested restricted stock weighted average grant date fair value restricted stock	$ 30.66
Forfeited restricted stock weighted average grant date fair value restricted stock	$ 28.98
End of year weighted average grant date fair value unvested restricted stock	$ 28.96
Restricted stock weighted average grant date fair value	$ 10.50

XML

Derivatives (Details-BS) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 26	$ 91
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	26	91
Derivative Liability, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	26
Derivative Liability, Fair Value, Net	26
Not Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	52
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	8	52
Commodity [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	52
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	8	52
Commodity [Member] | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	6
Derivative Liability, Fair Value, Net	6
Not Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	6
Derivative Liability, Fair Value, Net	6
Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	18	39
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	18	39
Derivative Liability, Fair Value, Gross Liability	20
Derivative Liability, Fair Value, Net	20
Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	18
Derivative Asset, Fair Value, Gross Liability		0
Derivative Asset, Fair Value, Net		18
Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	20
Derivative Liability, Fair Value, Net	20
Fair Value Hedging [Member] | Interest rate [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	18	21
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	$ 18	$ 21

XML

Incentive Based Compensation Plans (Details 5-Performance)	3 Months Ended
	Mar. 31, 2013
Performance Unit Disclosures [Abstract]
Performance Unit Granted	353,600
Performance Unit Awards Vesting Period	36 months
Award Instruments Other Than Options Performance Unit Value at Grant	1
AwardInstrumentsOtherThanOptionsPerformanceUnitMinimumPayoutValue	0
Award Instruments Other Than Options Performance Unit Maximum Payout Value	2

XML

Fair Value Measurements (Details 2-Nonrecurring) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Fair value of long-lived assets held for use, quarter	$ 0	$ 75
Impairment of long-lived assets held for use	38	262
Assets Held and Used Powder River Basin [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Impairment of long-lived assets held for use	15
Assets Held and Used Ozona [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Impairment of long-lived assets held for use	$ 21	$ 261

XML

Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2013

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information [Table Text Block]

	Three Months Ended March 31,
(In millions)	2013			2012
Net cash provided from operating activities:
Interest paid (net of amounts capitalized)	$	61		$	50
Income taxes paid to taxing authorities	1,003			828
Commercial paper, net:
Commercial paper - issuances	$	200		$	100
- repayments	(400		)	(100		)
Noncash investing activities:
Asset retirement costs capitalized	$	27		$	1
Change in capital expenditure accrual	(105		)	46
Asset retirement obligations assumed by buyer	88			7
Receivable for disposal of assets	50			—

XML

Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$ 61	$ 50
Income taxes paid to taxing authorities	1,003	828
Commercial paper, net:
Commercial paper - issuances	200	100
Commercial paper - repayments	(400)	(100)
Noncash investing activities:
Asset retirement costs capitalized	27	1
Change in capital expenditure accrual	(105)	46
Asset retirement obligations assumed by buyer	88	7
Receivable for disposal of assets	$ 50	$ 0

XML

Segment Information (Tables)

3 Months Ended

Mar. 31, 2013

Segment Information Disclosure [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Three Months Ended March 31, 2013
(In millions)	N.A. E&P			Int'l E&P		OSM		Total
Revenues:
Sales and other operating revenues	$	1,215		$	1,887	$	388	$	3,490
Marketing revenues	345			85		—		430
Segment revenues	$	1,560		$	1,972	$	388	3,920
Unrealized loss on crude oil derivative instruments								(50		)
Total revenues								$	3,870
Segment income (loss)	$	(59	)	$	453	$	38	$	432
Income from equity method investments	—			118		—		118
Depreciation, depletion and amortization	478			207		52		737
Income tax provision (benefit)	(30		)	1,142		13		1,125
Capital expenditures	970			225		45		1,240

	Three Months Ended March 31, 2012
(In millions)	N.A. E&P		Int'l E&P		OSM		Total
Revenues:
Sales and other operating revenues	$	912	$	1,663	$	379	$	2,954
Marketing revenues	775		64		—		839
Total revenues	$	1,687	$	1,727	$	379	$	3,793
Segment income	$	104	$	407	$	38	$	549
Income from equity method investments	1		77		—		78
Depreciation, depletion and amortization	314		200		49		563
Income tax provision	61		971		13		1,045
Capital expenditures	829		138		52		1,019

Reconciliation of Revenue from Segments to Consolidated [Table Text Block]

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)	2013		2012
Total revenues	$	3,870	$	3,793
Less:  Marketing revenues	430		839
Sales and other operating revenues, including related party	$	3,440	$	2,954

Reconciliation of Segment Income to Net Income [Table Text Block]

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

	Three Months Ended March 31,
(In millions)	2013			2012
Segment income	$	432		$	549
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(71		)	(71		)
Unrealized loss on crude oil derivative instruments	(32		)	—
Impairments	(10		)	(167		)
Net gain on dispositions	64			106
Net income	$	383		$	417

XML

Derivatives (Details 3-IS & OCI) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Net interest and other [Member] | Interest rate [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Gain (loss) on derivative instruments recognized in income	$ (3)	$ (1)
Net interest and other [Member] | Long-term Debt [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Change in unrealized gain (loss) on hedged item in fair value hedge	3	1
Provision For Income Taxes [Member] | Foreign Exchange Contract [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Gain (loss) on derivative instruments recognized in income	(25)	(8)
Provision For Income Taxes [Member] | Accrued Taxes [Member]
Gain (Loss) on Derivative Instruments [Line Items]
Change in unrealized gain (loss) on hedged item in fair value hedge	$ 25	$ 8

XML

Inventories (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Inventory Disclosure [Abstract]
Liquid hydrocarbons natural gas and bitumen	$ 54	$ 73
Supplies and other items	314	288
Total inventories, at cost	$ 368	$ 361

XML

Dispositions (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			1 Months Ended		1 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Apr. 30, 2013 DJ Basin [Member]	Jan. 31, 2013 Alaska EP [Member]	Feb. 28, 2013 Marcellus Shale [Member]	Feb. 28, 2013 Neptune Gas Plant [Member]	Jan. 31, 2012 GOM Pipelines [Member]
Dispositions Detail [Line Items]
Pretax gain/loss on sale			$ (115)	$ 46	$ (43)	$ 98	$ 166
Proceeds from Sale of Oil and Gas Property and Equipment	312	208		195		166	206
Proceeds from Sale of Oil and Gas Property and Equipment, Six Month Escrow	$ 50	$ 0		$ 50

XML

Derivatives Derivatives (Details 5-Non Hedges) (Details) (Not Designated as Hedging Instrument [Member], Sales and other operating revenues [Member], Commodity [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Not Designated as Hedging Instrument [Member] | Sales and other operating revenues [Member] | Commodity [Member]
Derivative Instruments not Designated as Hedges Gain (Loss) by Hedging Relationship, by Income Statement Location, by Derivative Instrument Risk [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	$ (55)	$ 2

XML

Fair Value Measurements (Details 3-Reported) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Mar. 31, 2012
Fair Value [Member]
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Other noncurrent financial assets	$ 174	$ 189
Total financial assets	174	189
Financial liabilities
Other current financial liabilities	13	13
Long-term debt, including current portion	7,347	7,610
Deferred credits and other financial liabilities	146	94
Total financial liabilities	7,506	7,717
Carrying Amount [Member]
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Other noncurrent financial assets	169	186
Total financial assets	169	186
Financial liabilities
Other current financial liabilities	13	13
Long-term debt, including current portion	6,494	6,642
Deferred credits and other financial liabilities	141	94
Total financial liabilities	$ 6,648	$ 6,749

XML

Variable Interest Entities

3 Months Ended

Mar. 31, 2013

Variable Interest Entities Disclosure [Abstract]

Variable Interest Entity [Text Block]

Variable Interest Entity

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 current liabilities of $2 million and $3 million recorded at March 31, 2013 and December 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 by us.  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 $711 million as of March 31, 2013.  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.

XML

Property, Plant and Equipment (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Less accumulated depreciation, depletion and amortization	$ (20,195)	$ (19,266)
Property, plant and equipment, net	28,382	28,272
Libya 1 [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	748
North America Exploration and Production [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	24,500	23,748
International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	13,429	13,214
Oil Sands Mining Segment [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	10,171	10,127
Corporate [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	477	449
Total All Segments [Member]
Segment Reporting Information [Line Items]
Total property, plant and equipment	$ 48,577	$ 47,538

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Fair Value Measurements Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of March 31, 2013 and December 31, 2012 by fair value hierarchy level.

	March 31, 2013
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	8	$	—	$	1	$	9
Interest rate	—		18		—		—		18
Derivative instruments, assets	$	—	$	26	$	—	$	1	$	27
Derivative instruments, liabilities
Commodity	$	—	$	6	$	—	$	—	$	6
Foreign currency	—		20		—		—		20
Derivative instruments, liabilities	$	—	$	26	$	—	$	—	$	26

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	52	$	—	$	1	$	53
Interest rate	—		21		—		—		21
Foreign currency	—		18		—		—		18
Derivative instruments, assets	$	—	$	91	$	—	$	1	$	92

Fair Value, Assets and Liabilities Measured on Nonrecurring Basis [Table Text Block]

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,
	2013				2012
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	38	$	75	$	262

Fair Value, by Balance Sheet Grouping [Table Text Block]

The following table summarizes financial instruments, excluding receivables, commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at March 31, 2013 and December 31, 2012.

	March 31, 2013				December 31, 2012
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	174	$	169	$	189	$	186
Total financial assets	174		169		189		186
Financial liabilities
Other current liabilities	13		13		13		13
Long-term debt, including current portion(a)	7,347		6,494		7,610		6,642
Deferred credits and other liabilities	146		141		94		94
Total financial liabilities	$	7,506	$	6,648	$	7,717	$	6,749

^(a)      Excludes capital leases.

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 2013

Property Plant And Equipment Disclosure [Abstract]

Schedule Of Property Plant And Equipment [Table Text Block]

	March 31,			December 31,
(In millions)	2013			2012
North America E&P	$	24,500		$	23,748
International E&P	13,429			13,214
Oil Sands Mining	10,171			10,127
Corporate	477			449
Total property, plant and equipment	48,577			47,538
Less accumulated depreciation, depletion and amortization	(20,195		)	(19,266		)
Net property, plant and equipment	$	28,382		$	28,272

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Reclassifications out of Accumulated Other Comprehensive Income Reclassifications out of Accumulated Other Comprehensive Income (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Provision for income taxes	$ (1,025)	$ (927)
Net income	383	417
Accumulated Defined Benefit and Post Retirement Plan Adjustment [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
General and Administrative	(13)
Provision for income taxes	5
Net income	$ (8)

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Property, Plant and Equipment Property, Plant and Equipment (Details 3) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Total Deferred Exploratory Well Costs [Abstract]
Amounts capitalized greater than one year after completion of drilling	$ 220

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Derivatives (Tables)

3 Months Ended

Mar. 31, 2013

Derivatives Disclosure [Abstract]

Derivatives as they appear on the balance sheet [Table Text Block]

The following tables present the gross fair values of derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of March 31, 2013 and December 31, 2012.

	March 31, 2013
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	18	$	—	$	18	Other noncurrent assets
Total Designated Hedges	18		—		18
Not Designated as Hedges
Commodity	8		—		8		Other current assets
Total Not Designated as Hedges	8		—		8
Total	$	26	$	—	$	26

	March 31, 2013
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	20	$	20	Other current liabilities
Total Designated Hedges	—		20		20
Not Designated as Hedges
Commodity	—		6		6		Other current liabilities
Total Not Designated as Hedges	—		6		6
Total	$	—	$	26	$	26

	December 31, 2012
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	18	$	—	$	18	Other current assets
Interest rate	21		—		21		Other noncurrent assets
Total Designated Hedges	39		—		39
Not Designated as Hedges
Commodity	52		—		52		Other current assets
Total Not Designated as Hedges	52		—		52
Total	$	91	$	—	$	91

Effects of derivatives designated as fair value hedges [Table Text Block]

The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below.

		Gain (Loss)
		Three Months Ended March 31,
(In millions)	Income Statement Location	2013			2012
Derivative
Interest rate	Net interest and other	$	(3	)	$	(1	)
Foreign currency	Provision for income taxes	$	(25	)	$	(8	)
Hedged Item
Long-term debt	Net interest and other	$	3		$	1
Accrued taxes	Provision for income taxes	$	25		$	8

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

These commodity derivatives were not designated as hedges and are shown in the table below.

Remaining Term	Bbls per Day	Weighted Average Price per Bbl	Benchmark
Swaps
April 2013 - December 2013	20,000	$96.29	West Texas Intermediate
April 2013 - December 2013	25,000	$109.19	Brent
Option Collars
April 2013 - December 2013	15,000	$90.00 floor / $101.17 ceiling	West Texas Intermediate
April 2013 - December 2013	15,000	$100.00 floor / $116.30 ceiling	Brent

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Incentive Based Compensation Plans (Tables)

3 Months Ended

Mar. 31, 2013

Incentive Based Compensation Plans [Abstract]

Table of Incentive based compensation activity [Table Text Block]

The following table presents a summary of stock option and restricted stock award activity for the first quarter of 2013: 

	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2012	19,536,965				$26.19	4,177,884			$29.02
Granted	1,002,400		(a)		$32.86	137,722			$33.04
Options Exercised/Stock Vested	(839,273	)			$21.33	(493,840	)		$30.66
Cancelled	(215,262	)			$35.17	(78,778	)		$28.98
Outstanding at March 31, 2013	19,484,830				$26.65	3,742,988			$28.96

^(a)    The weighted average grant date fair value of stock option awards granted was $10.50 per share.

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Accounting Standards

3 Months Ended

Mar. 31, 2013

Accounting Standards Disclosure [Abstract]

Accounting Standards [Text Block]

Accounting Standards

Not Yet Adopted

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within United States generally accepted accounting principles ("U.S. GAAP"). An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. We are currently evaluating the potential impact of this accounting standards update on our consolidated results of operations, financial position and cash flows.

Recently Adopted

In February 2013, an accounting standards update was issued to improve the reporting of reclassifications out of accumulated other comprehensive income. This standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This accounting standards update was effective for us beginning the first quarter of 2013 and we present the required disclosures in Note14. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

In December 2011, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosures are intended to enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclose both gross information and net information about in-scope financial instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. The accounting standards update was effective for us beginning the first quarter of 2013 and we include the required disclosures in Note 12. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

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Reclassifications out of Accumulated Other Comprehensive Income Reclassifications out of Accumulated Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2013

Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]

Schedule of Amounts Reclassified out of Accumulated Other Comprehensive Income [Table Text Block]

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss for the first quarter of 2013:

	Three Months Ended March 31, 2013
(In millions)		Reclassified to Income (Expense)			Income Statement Line
Accumulated Other Comprehensive Loss Components
Amortization of postretirement and postemployment plans
Actuarial loss		$	(13	)	General and administrative
		5			Provision for income taxes
Total reclassifications for the period		$	(8	)	Net income

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Defined Benefit Postretirement Plans (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pension and Other Postretirement Benefit Contributions [Abstract]
Pension Contributions	$ 9
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year	55
Defined Benefit Plan, Benefits Paid	9
Other Postretirement Benefits Payments	4
United States and Foreign Pension Plans Defined Benefit [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]
Service cost	14	12
Interest cost	15	16
Expected return on plan assets	(17)	(16)
Amortization:
- prior service cost (credit)	2	2
-actuarial loss (gain)	13	12
Net periodic benefit cost	27	26
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Net Periodic Benefit Cost [Line Items]
Service cost	1	1
Interest cost	3	4
Expected return on plan assets	0	0
Amortization:
- prior service cost (credit)	(2)	(2)
-actuarial loss (gain)	0	0
Net periodic benefit cost	$ 2	$ 3

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Incentive Based Compensation Plans (Details 2) (USD $)	3 Months Ended
	Mar. 31, 2013
Stock Options
Beginning year stock option awards	19,536,965
Granted stock option awards	1,002,400	[1]
Exercised stock option awards	(839,273)
Canceled stock option awards	(215,262)
End of year stock option awards	19,484,830
Beginning year weighted average exercise price	$ 26.19
Granted weighted average exercise price	$ 32.86
Exercises weighted average exercise price	$ 21.33
Canceled weighted average exercise price	$ 35.17
End of year weighted average exercise price	$ 26.65

[1] The weighted average grant date fair value of stock option awards granted was $10.50 per share.

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Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revenues and other income:
Sales and other operating revenues, including related party	$ 3,440	$ 2,954
Marketing revenues	430	839
Income from equity method investments	118	78
Net gain on disposal of assets	109	166
Other income	9	3
Total revenues and other income	4,106	4,040
Costs and expenses:
Production	578	514
Marketing, including purchases from related parties	429	842
Other operating	111	92
Exploration	465	135
Depreciation, depletion and amortization	747	574
Impairments	38	262
Taxes other than income	84	68
General and administrative	174	159
Total costs and expenses	2,626	2,646
Income from operations	1,480	1,394
Net interest and other	(72)	(50)
Income before income taxes	1,408	1,344
Provision for income taxes	1,025	927
Net income	$ 383	$ 417
Basic:
Net income, per basic share	$ 0.54	$ 0.59
Diluted:
Net income, per diluted share	$ 0.54	$ 0.59
Dividends paid, per share	$ 0.17	$ 0.17
Weighted average common shares outstanding, basic	708	706
Weighted average common shares outstanding, diluted	712	710

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Fair Value Measurements (Details-Recurring) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	$ 27	$ 92
Derivative Liabilities	26
Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	9	53
Derivative Liabilities	6
Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	18	21
Foreign Exchange Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		18
Derivative Liabilities	20
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liabilities	0
Fair Value, Inputs, Level 1 [Member] | Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liabilities	0
Fair Value, Inputs, Level 1 [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Exchange Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		0
Derivative Liabilities	0
Fair Value Inputs Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	26	91
Derivative Liabilities	26
Fair Value Inputs Level 2 [Member] | Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	8	52
Derivative Liabilities	6
Fair Value Inputs Level 2 [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	18	21
Fair Value Inputs Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		18
Derivative Liabilities	20
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liabilities	0
Fair Value, Inputs, Level 3 [Member] | Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liabilities	0
Fair Value, Inputs, Level 3 [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Exchange Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		0
Derivative Liabilities	0
Fair Value (no inputs) Collateral [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	1	1
Derivative Liabilities	0
Fair Value (no inputs) Collateral [Member] | Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	1	1
Derivative Liabilities	0
Fair Value (no inputs) Collateral [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Fair Value (no inputs) Collateral [Member] | Foreign Exchange Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		0
Derivative Liabilities	$ 0

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating activities:
Net income	$ 383	$ 417
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes	44	(22)
Depreciation, depletion and amortization	747	574
Impairments	38	262
Pension and other postretirement benefits, net	7	(29)
Exploratory dry well costs and unproved property impairments	404	58
Net gain on disposal of assets	(109)	(166)
Equity method investments, net	(48)	(21)
Changes in:
Current receivables, changes in	(4)	(296)
Inventories, changes in	(15)	7
Current accounts payable and accrued liabilities, changes in	(54)	213
All other operating, net	135	(24)
Net cash provided by operating activities	1,528	973
Investing activities:
Additions to property, plant and equipment	(1,375)	(1,017)
Disposal of assets	312	208
Investments - return of capital	18	15
All other investing, net	8	(12)
Net cash used in investing activities	(1,037)	(806)
Financing activities:
Commercial paper, net	(200)	0
Debt repayments	(114)	(53)
Dividends paid	(120)	(121)
All other financing, net	21	17
Net cash used in financing activities	(413)	(157)
Effect of exchange rate changes on cash	6	10
Net increase in cash and cash equivalents	84	20
Cash and cash equivalents at beginning of period	684	493
Cash and cash equivalents at end of period	$ 768	$ 513

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Variable Interest Entities (Details) (Variable Interest Entity, Not Primary Beneficiary [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Variable Interest Entity, Not Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Recorded liability related to unconsolidated VIE	$ 2	$ 3
Maximum exposure to loss related to unconsolidated VIE	$ 711

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. 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, 2013, Marathon’s contract commitments to acquire property, plant and equipment were $1,209 million.

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Income per Common Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Earnings Per Share [Abstract]
Net income	$ 383	$ 417
Weighted average common shares outstanding, basic	708	706
Effect of dilutive securities	4	4
Weighted average common shares outstanding, diluted	712	710
Basic:
Net income, per basic share	$ 0.54	$ 0.59
Diluted:
Net income, per diluted share	$ 0.54	$ 0.59
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	7

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Income per Common Share (Tables)

3 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	Three Months Ended March 31,
	2013				2012
(In millions, except per share data)	Basic		Diluted		Basic		Diluted
Net income	$	383	$	383	$	417	$	417
Weighted average common shares outstanding	708		708		706		706
Effect of dilutive securities	—		4		—		4
Weighted average common shares, including
dilutive effect	708		712		706		710
Per share:
Net income		$0.54		$0.54		$0.59		$0.59

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Basis of Presentation Basis of Presentation (Notes)

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Basis of Presentation [Text Block]

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 ("SEC") 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.

Beginning in the first quarter of 2013, we changed the presentation of our consolidated statements of income, primarily to present additional details of revenues and expenses and to classify certain expenses more consistently with our peer group of independent exploration and production companies. To effect these changes, reclassifications of previously reported amounts were made and are reflected in these consolidated financial statements. As a result of the reclassifications, general and administrative expenses for the first quarter of 2012 increased by $39 million which primarily includes certain costs associated with operations support and operations management. Offsetting reductions are reflected in production, other operating and exploration expenses and taxes other than income.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation 2012 Annual Report on Form 10-K.  The results of operations for the first quarter of 2013 are not necessarily indicative of the results to be expected for the full year.

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statement of Other Comprehensive Income [Abstract]
Net income	$ 383	$ 417
Postretirement and postemployment plans
Change in actuarial loss and other	13	13
Income tax provision on postretirement and postemployment plans	(5)	(5)
Postretirement and postemployment plans, net of tax	8	8
Foreign currency translation and other
Unrealized gain (loss)	(1)	1
Income tax provision on foreign currency translation and other	0	0
Foreign currency translation and other, net of tax	(1)	1
Other comprehensive income	7	9
Comprehensive income	$ 390	$ 426

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Fair Value Measurements

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements [Text Block]

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, 2013 and December 31, 2012 by fair value hierarchy level.

	March 31, 2013
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	8	$	—	$	1	$	9
Interest rate	—		18		—		—		18
Derivative instruments, assets	$	—	$	26	$	—	$	1	$	27
Derivative instruments, liabilities
Commodity	$	—	$	6	$	—	$	—	$	6
Foreign currency	—		20		—		—		20
Derivative instruments, liabilities	$	—	$	26	$	—	$	—	$	26

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	52	$	—	$	1	$	53
Interest rate	—		21		—		—		21
Foreign currency	—		18		—		—		18
Derivative instruments, assets	$	—	$	91	$	—	$	1	$	92

Commodity swaps in Level 2 are measured at fair value with a market approach using prices obtained from exchanges or pricing services, which have been corroborated with data from active markets for similar assets or liabilities.  Commodity options in Level 2 are valued using The Black-Scholes Model.  Inputs to this model include prices as noted above, discount factors, and implied market volatility.  The inputs to this fair value measurement are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.  Collateral deposits related to commodity derivatives are in broker accounts covered by master netting agreements.

Interest rate swaps are measured at fair value with a market approach 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 or liabilities, and are Level 2 inputs.

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,
	2013				2012
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	—	$	38	$	75	$	262

All long-lived assets held for use that were impaired in the first quarters of 2013 and 2012 were held by our North America E&P segment. The fair values of each discussed below were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs.  Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

In the first quarter of 2013, as a result of our decision to wind down operations in the Powder River Basin due to poor economics, an impairment of $15 million was recorded.

In early 2012, production rates from the Ozona development in the Gulf of Mexico declined significantly. Accordingly, our reserve engineers prepared evaluations of our future production as well as our reserves and an impairment of $261 million was recorded in the first quarter of 2012.  As the development produced towards abandonment pressures, further downward revisions of reserves were taken, resulting in an additional impairment recorded in the fourth quarter of 2012. Ozona production ceased in the first quarter of 2013 and an additional $21 million impairment was recorded.

Other impairments of long-lived assets held for use by our North America E&P segment in the first quarters of 2013 and 2012 were a result of reduced drilling expectations, reductions of estimated reserves or declining natural gas prices.

Fair Values – Financial Instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, commercial paper and payables. We believe the carrying values of our receivables, commercial paper and payables 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.

The following table summarizes financial instruments, excluding receivables, commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at March 31, 2013 and December 31, 2012.

	March 31, 2013				December 31, 2012
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other noncurrent assets	$	174	$	169	$	189	$	186
Total financial assets	174		169		189		186
Financial liabilities
Other current liabilities	13		13		13		13
Long-term debt, including current portion(a)	7,347		6,494		7,610		6,642
Deferred credits and other liabilities	146		141		94		94
Total financial liabilities	$	7,506	$	6,648	$	7,717	$	6,749

^(a)      Excludes capital leases.

Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and 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.

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

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Document and Entity Information (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Apr. 30, 2013	Jun. 29, 2012
Document and Entity Information [Abstract]
Document Type	10-Q
Document Period End Date	Mar. 31, 2013
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2013
Amendment Flag	false
Entity Registrant Name	Marathon Oil Corp
Entity Central Index Key	0000101778
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well Known Seasoned Issuer	Yes
Entity Common Stock Shares Outstanding		708,817,008
Entity Public Float			$ 17,991

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Derivatives

3 Months Ended

Mar. 31, 2013

Derivatives Disclosure [Abstract]

Derivatives [Text Block]

Derivatives

For information regarding the fair value measurement of derivative instruments, see Note 11. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. Netting is assessed by counterparty, and as of March 31, 2013 and December 31, 2012, there were no offsetting amounts. Positions by contract were all either assets or liabilities. The following tables present the gross fair values of derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of March 31, 2013 and December 31, 2012.

	March 31, 2013
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	18	$	—	$	18	Other noncurrent assets
Total Designated Hedges	18		—		18
Not Designated as Hedges
Commodity	8		—		8		Other current assets
Total Not Designated as Hedges	8		—		8
Total	$	26	$	—	$	26

	March 31, 2013
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	20	$	20	Other current liabilities
Total Designated Hedges	—		20		20
Not Designated as Hedges
Commodity	—		6		6		Other current liabilities
Total Not Designated as Hedges	—		6		6
Total	$	—	$	26	$	26

	December 31, 2012
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	18	$	—	$	18	Other current assets
Interest rate	21		—		21		Other noncurrent assets
Total Designated Hedges	39		—		39
Not Designated as Hedges
Commodity	52		—		52		Other current assets
Total Not Designated as Hedges	52		—		52
Total	$	91	$	—	$	91

Derivatives Designated as Fair Value Hedges

As of March 31, 2013 and December 31, 2012, we had multiple interest rate swap agreements with a total notional amount of $600 million with a maturity date of October 1, 2017 at a weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate of 4.69 percent and 4.70 percent.

As of March 31, 2013 and December 31, 2012, our foreign currency forwards had an aggregate notional amount of 3,571 million and 3,043 million Norwegian Kroner at a weighted average forward rate of 5.678 and 5.780. These forwards hedge our current Norwegian tax liability and have settlement dates through August 2013.

The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below.

		Gain (Loss)
		Three Months Ended March 31,
(In millions)	Income Statement Location	2013			2012
Derivative
Interest rate	Net interest and other	$	(3	)	$	(1	)
Foreign currency	Provision for income taxes	$	(25	)	$	(8	)
Hedged Item
Long-term debt	Net interest and other	$	3		$	1
Accrued taxes	Provision for income taxes	$	25		$	8

Derivatives not Designated as Hedges

In August 2012, we entered into crude oil derivatives related to a portion of our forecast North America E&P crude oil sales through December 31, 2013. These commodity derivatives were not designated as hedges and are shown in the table below.

Remaining Term	Bbls per Day	Weighted Average Price per Bbl	Benchmark
Swaps
April 2013 - December 2013	20,000	$96.29	West Texas Intermediate
April 2013 - December 2013	25,000	$109.19	Brent
Option Collars
April 2013 - December 2013	15,000	$90.00 floor / $101.17 ceiling	West Texas Intermediate
April 2013 - December 2013	15,000	$100.00 floor / $116.30 ceiling	Brent

The impact of commodity derivative instruments not designated as hedges appears in the sales and operating revenues, including related party, line of our consolidated statements of income and was a net loss of $55 million in the first quarter of 2013 and a net gain of $2 million in the first quarter of 2012.

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 768	$ 684
Receivables	2,466	2,418
Inventories	368	361
Other current assets	175	299
Total current assets	3,777	3,762
Equity method investments	1,304	1,279
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $20,195 and $19,266	28,382	28,272
Goodwill	528	525
Other noncurrent assets	1,118	1,468
Total assets	35,109	35,306
Current liabilities:
Commercial paper	0	200
Accounts payable	2,284	2,324
Payroll and benefits payable	182	217
Accrued taxes	1,892	1,983
Other current liabilities	203	173
Long-term debt due within one year	68	184
Total current liabilities	4,629	5,081
Long-term debt	6,476	6,512
Deferred tax liabilities, noncurrent	2,401	2,432
Defined benefit postretirement plan obligations	850	856
Asset retirement obligations	1,795	1,749
Deferred credits and other liabilities, noncurrent	370	393
Total liabilities	16,521	17,023
Commitments and contingencies
Stockholders' Equity
Preferred stock no shares issued and outstanding (no par value, 26 million shares authorized)	0	0
Common stock issued - 770 million and 770 million shares (par value $1 per share, 1.1 billion shares authorized)	770	770
Common stock, securities exchangeable into common stock - no shares issued and outstanding (no par value, 29 million shares authorized)	0	0
Held in treasury, at cost - 62 million and 63 million shares	(2,527)	(2,560)
Additional paid-in capital	6,618	6,616
Retained earnings	14,153	13,890
Accumulated other comprehensive loss	(426)	(433)
Total equity	18,588	18,283
Total liabilities and stockholders' equity	$ 35,109	$ 35,306

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Segment Information

3 Months Ended

Mar. 31, 2013

Segment Information Disclosure [Abstract]

Segment Information [Text Block]

Segment Information

  Beginning in 2013, we changed our reportable segments and revised our management reporting to better reflect the growing importance of United States unconventional resource plays to our business. All periods presented have been recast to reflect these new segments.

We have three reportable operating segments.  Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers.

• North America E&P ("N.A. E&P") – explores for, produces and markets liquid hydrocarbons and natural gas in North America;

• International E&P ("Int'l E&P") – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as liquefied natural gas ("LNG")and methanol, in Equatorial Guinea;

• 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.

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 excluding certain items not allocated to segments as discussed below, net of income taxes, attributable to the operating segments. Our corporate and operations support 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 and operations support activities, net of associated income tax effects.  Unrealized gains or losses on crude oil derivative instruments, 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 and our consolidated totals for income taxes and depreciation, depletion and amortization 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.

	Three Months Ended March 31, 2013
(In millions)	N.A. E&P			Int'l E&P		OSM		Total
Revenues:
Sales and other operating revenues	$	1,215		$	1,887	$	388	$	3,490
Marketing revenues	345			85		—		430
Segment revenues	$	1,560		$	1,972	$	388	3,920
Unrealized loss on crude oil derivative instruments								(50		)
Total revenues								$	3,870
Segment income (loss)	$	(59	)	$	453	$	38	$	432
Income from equity method investments	—			118		—		118
Depreciation, depletion and amortization	478			207		52		737
Income tax provision (benefit)	(30		)	1,142		13		1,125
Capital expenditures	970			225		45		1,240

	Three Months Ended March 31, 2012
(In millions)	N.A. E&P		Int'l E&P		OSM		Total
Revenues:
Sales and other operating revenues	$	912	$	1,663	$	379	$	2,954
Marketing revenues	775		64		—		839
Total revenues	$	1,687	$	1,727	$	379	$	3,793
Segment income	$	104	$	407	$	38	$	549
Income from equity method investments	1		77		—		78
Depreciation, depletion and amortization	314		200		49		563
Income tax provision	61		971		13		1,045
Capital expenditures	829		138		52		1,019

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)	2013		2012
Total revenues	$	3,870	$	3,793
Less:  Marketing revenues	430		839
Sales and other operating revenues, including related party	$	3,440	$	2,954

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

	Three Months Ended March 31,
(In millions)	2013			2012
Segment income	$	432		$	549
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(71		)	(71		)
Unrealized loss on crude oil derivative instruments	(32		)	—
Impairments	(10		)	(167		)
Net gain on dispositions	64			106
Net income	$	383		$	417

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Dispositions

3 Months Ended

Mar. 31, 2013

Dispositions Disclosure [Abstract]

Dispositions [Text Block]

Dispositions

2013 - North America Exploration and Production ("E&P") Segment

In April 2013, we reached an agreement to sell our interests in the DJ Basin. The transaction is expected to close in mid-2013 and a second quarter loss of approximately $115 million, before closing adjustments, is anticipated on this disposition.

In February 2013, we entered an agreement to convey our interest in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.

In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain, before closing adjustments, was recorded in the first quarter of 2013.

In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million for various indemnities. A $46 million pretax gain, before closing adjustments, was recorded in the first quarter of 2013.

2012 - North America E&P Segment

In January 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million.  This included 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.

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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Basis of Accounting

These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported.  All such adjustments are of a normal recurring nature unless disclosed otherwise.  These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission ("SEC") 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.

Reclassification, Policy [Policy Text Block]

Beginning in the first quarter of 2013, we changed the presentation of our consolidated statements of income, primarily to present additional details of revenues and expenses and to classify certain expenses more consistently with our peer group of independent exploration and production companies. To effect these changes, reclassifications of previously reported amounts were made and are reflected in these consolidated financial statements. As a result of the reclassifications, general and administrative expenses for the first quarter of 2012 increased by $39 million which primarily includes certain costs associated with operations support and operations management. Offsetting reductions are reflected in production, other operating and exploration expenses and taxes other than income.

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Incentive Based Compensation Plans

3 Months Ended

Mar. 31, 2013

Incentive Based Compensation Plans [Abstract]

Incentive Based Compensation [Text Block]

Incentive Based Compensation

Stock option and restricted stock awards

  The following table presents a summary of stock option and restricted stock award activity for the first quarter of 2013: 

	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2012	19,536,965				$26.19	4,177,884			$29.02
Granted	1,002,400		(a)		$32.86	137,722			$33.04
Options Exercised/Stock Vested	(839,273	)			$21.33	(493,840	)		$30.66
Cancelled	(215,262	)			$35.17	(78,778	)		$28.98
Outstanding at March 31, 2013	19,484,830				$26.65	3,742,988			$28.96

^(a)    The weighted average grant date fair value of stock option awards granted was $10.50 per share.

Performance unit awards

 During the first quarter of 2013, we granted 353,600 performance units to certain officers that provide a cash payout upon the achievement of certain performance goals at the end of a 36-month performance period.  The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors.   At the grant date, each unit represents the value of one share of our common stock, while payout after completion of the performance period will be based on the value of anywhere from zero to two times the number of units granted.  Dividend equivalents accrue during the performance period and are paid in cash at the end of the performance period based on the number of shares that would represent the value of the units.  The fair value of these performance units is re-measured on a quarterly basis using the Monte Carlo simulation method.  These performance units are accounted for as liability awards because they are to be settled in cash at the end of the performance period and their fair value is expensed over the performance period.

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Inventories

3 Months Ended

Mar. 31, 2013

Inventory Disclosure [Abstract]

Inventories [Text Block]

Inventories

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

	March 31,		December 31,
(In millions)	2013		2012
Liquid hydrocarbons, natural gas and bitumen	$	54	$	73
Supplies and other items	314		288
Inventories, at cost	$	368	$	361

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Defined Benefit Postretirement Plans

3 Months Ended

Mar. 31, 2013

Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Postretirement Plans [Text Block]

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)	2013			2012			2013			2012
Service cost	$	14		$	12		$	1		$	1
Interest cost	15			16			3			4
Expected return on plan assets	(17		)	(16		)	—			—
Amortization:
– prior service cost (credit)	2			2			(2		)	(2		)
– actuarial loss	13			12			—			—
Net periodic benefit cost	$	27		$	26		$	2		$	3

During the first three months of 2013, we made contributions of $9 million to our funded pension plans.  We expect to make additional contributions up to an estimated $55 million to our funded pension plans over the remainder of 2013.  Current benefit payments related to unfunded pension and other postretirement benefit plans were $9 million and $4 million during the first three months of 2013.

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Income Taxes

3 Months Ended

Mar. 31, 2013

Income Taxes Disclosure [Abstract]

Income Taxes [Text Block]

Income Taxes

The effective income tax rate is influenced by a variety of factors including the geographic 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 items not allocated to segments is presented in Corporate and other unallocated items in Note 6.

Our effective income tax rates in the first three months of 2013 and 2012 were 73 percent and 69 percent.   These rates are higher than the U.S. statutory rate of 35 percent due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax rates are in excess of the U.S. statutory rate.  In Libya, where the statutory tax rate is in excess of 90 percent, there remains uncertainty around sustained production and sales levels.  Reliable estimates of 2013 and 2012 annual ordinary income from our Libyan operations could not 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 first three months of 2013 and 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 65 percent and 64 percent for the first three months of 2013 and 2012.

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Property, Plant and Equipment

3 Months Ended

Mar. 31, 2013

Property Plant And Equipment Disclosure [Abstract]

Property, Plant and Equipment [Text Block]

 Property, Plant and Equipment

	March 31,			December 31,
(In millions)	2013			2012
North America E&P	$	24,500		$	23,748
International E&P	13,429			13,214
Oil Sands Mining	10,171			10,127
Corporate	477			449
Total property, plant and equipment	48,577			47,538
Less accumulated depreciation, depletion and amortization	(20,195		)	(19,266		)
Net property, plant and equipment	$	28,382		$	28,272

In the first quarter of 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed.  Since that time, average sales volumes have increased to near pre-conflict levels.  We and our partners in the Waha concessions continue to assess the condition of our assets in Libya and uncertainty around sustained production and sales levels remains. As of March 31, 2013, our net property, plant and equipment investment in Libya was approximately $748 million.

Exploratory well costs capitalized greater than one year after completion of drilling were $220 million as of March 31, 2013.  The net decrease in such costs from December 31, 2012 primarily related to the conveyance of our interest in the Marcellus natural gas shale play to the operator in February 2013.

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Basis of Presentation Reclassifications (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
General and administrative	$ 174	$ 159
Reclassifications [Member]
General and administrative		$ 39

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Derivatives Derivatives (Details 4-Non Hedges Commodity) (Details) (Not Designated as Hedging Instrument [Member], Commodity [Member])	3 Months Ended
	Mar. 31, 2013
Swap [Member] | West Texas Intermediate [Member]
Exploration and Production Commodity Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	96.29
Underlying, Derivative	20,000
Swap [Member] | Brent [Member]
Exploration and Production Commodity Derivative [Line Items]
Derivative, Swap Type, Average Fixed Price	109.19
Underlying, Derivative	25,000
Option Collar [Member] | West Texas Intermediate [Member]
Exploration and Production Commodity Derivative [Line Items]
Derivative, Average Floor Price	90.00
Derivative, Average Cap Price	101.17
Underlying, Derivative	15,000
Option Collar [Member] | Brent [Member]
Exploration and Production Commodity Derivative [Line Items]
Derivative, Average Floor Price	100.00
Derivative, Average Cap Price	116.30
Underlying, Derivative	15,000

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2013

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information [Text Block]

Supplemental Cash Flow Information

	Three Months Ended March 31,
(In millions)	2013			2012
Net cash provided from operating activities:
Interest paid (net of amounts capitalized)	$	61		$	50
Income taxes paid to taxing authorities	1,003			828
Commercial paper, net:
Commercial paper - issuances	$	200		$	100
- repayments	(400		)	(100		)
Noncash investing activities:
Asset retirement costs capitalized	$	27		$	1
Change in capital expenditure accrual	(105		)	46
Asset retirement obligations assumed by buyer	88			7
Receivable for disposal of assets	50			—

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Defined Benefit Postretirement Plans (Tables)

3 Months Ended

Mar. 31, 2013

Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Defined Benefit Plans Disclosures [Table Text Block]

The following summarizes the components of net periodic benefit cost:

	Three Months Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2013			2012			2013			2012
Service cost	$	14		$	12		$	1		$	1
Interest cost	15			16			3			4
Expected return on plan assets	(17		)	(16		)	—			—
Amortization:
– prior service cost (credit)	2			2			(2		)	(2		)
– actuarial loss	13			12			—			—
Net periodic benefit cost	$	27		$	26		$	2		$	3

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Derivatives (Details 2-Interest Rate Hedges) In Millions, unless otherwise specified	Mar. 31, 2013 USD ($)	Mar. 31, 2013 NOK	Dec. 31, 2012 USD ($)	Dec. 31, 2012 NOK
Interest Rate Fair Value Hedges [Abstract]
Notional Amount of Interest Rate Fair Value Hedge Derivatives	$ 600		$ 600
Weighted-average, LIBOR-based, floating rate	4.69%	4.69%	4.70%	4.70%
Notional Amount of Foreign Currency Derivatives		3,571		3,043
Derivative, Average Forward Exchange Rate	5.678	5.678	5.780	5.780

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Income Taxes (Details)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Effective Tax Rate Reconciliation [Abstract]
Statutory rate	35.00%	35.00%
Effective income tax rate	73.00%	69.00%
Effective income tax rate excluding Libya	65.00%	64.00%
Minimum [Member]
Income Taxes [Line Items]
Statutory income tax rate in Libya	90.00%	90.00%

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Consolidated Balance Sheets Parentheticals (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Consolidated Balance Sheets Parenthetical [Abstract]
Less accumulated depreciation, depletion and amortization	$ (20,195)	$ (19,266)
Preferred stock, no par value	$ 0	$ 0
Preferred stock shares authorized	26,000,000	26,000,000
Preferred stock shares issued	0	0
Preferred stock shares outstanding	0	0
Common stock, par value per share	$ 1	$ 1
Common stock shares authorized	1,100,000,000	1,100,000,000
Common stock, shares issued	770,000,000	770,000,000
Common stock, securities exchangeable, no par value	$ 0	$ 0
Common stock, securities exchangeable, shares authorized	29,000,000	29,000,000
Common stock, securities exchangeable, shares issued	0	0
Common stock, securities exchangeable, shares outstanding	0	0
Held in treasury, shares	62,000,000	63,000,000

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Income per Common Share

3 Months Ended

Mar. 31, 2013

Income Per Common Share Disclosure [Abstract]

Income per Common Share [Text Block]

Income per Common Share

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

	Three Months Ended March 31,
	2013				2012
(In millions, except per share data)	Basic		Diluted		Basic		Diluted
Net income	$	383	$	383	$	417	$	417
Weighted average common shares outstanding	708		708		706		706
Effect of dilutive securities	—		4		—		4
Weighted average common shares, including
dilutive effect	708		712		706		710
Per share:
Net income		$0.54		$0.54		$0.59		$0.59

The per share calculations above exclude 6 million and 7 million stock options and stock appreciation rights for the first quarters of 2013 and 2012 that were antidilutive.

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Commitments to acquire property, plant and equipment	$ 1,209

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Inventories (Tables)

3 Months Ended

Mar. 31, 2013

Inventory Disclosure [Abstract]

Schedule of Inventory, Current [Table Text Block]

	March 31,		December 31,
(In millions)	2013		2012
Liquid hydrocarbons, natural gas and bitumen	$	54	$	73
Supplies and other items	314		288
Inventories, at cost	$	368	$	361

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revenues:
Sales and other operating revenues, including related party	$ 3,440	$ 2,954
Marketing revenues	430	839
Total revenues	3,870	3,793
Income from equity method investments	118	78
Depreciation, depletion and amortization	747	574
Income tax provision (benefit)	1,025	927
North America Exploration and Production [Member]
Revenues:
Sales and other operating revenues, including related party	1,215	912
Marketing revenues	345	775
Total revenues	1,560	1,687
Segment income	(59)	104
Income from equity method investments	0	1
Depreciation, depletion and amortization	478	314
Income tax provision (benefit)	(30)	61
Capital expenditures	970	829
International Exploration and Production [Member]
Revenues:
Sales and other operating revenues, including related party	1,887	1,663
Marketing revenues	85	64
Total revenues	1,972	1,727
Segment income	453	407
Income from equity method investments	118	77
Depreciation, depletion and amortization	207	200
Income tax provision (benefit)	1,142	971
Capital expenditures	225	138
Oil Sands Mining Segment [Member]
Revenues:
Sales and other operating revenues, including related party	388	379
Marketing revenues	0	0
Total revenues	388	379
Segment income	38	38
Income from equity method investments	0	0
Depreciation, depletion and amortization	52	49
Income tax provision (benefit)	13	13
Capital expenditures	45	52
Total All Segments [Member]
Revenues:
Sales and other operating revenues, including related party	3,490	2,954
Marketing revenues	430	839
Total revenues	3,920
Unrealized loss on crude oil derivative instruments	(50)
Segment income	432	549
Income from equity method investments	118	78
Depreciation, depletion and amortization	737	563
Income tax provision (benefit)	1,125	1,045
Capital expenditures	$ 1,240	$ 1,019

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Reclassifications out of Accumulated Other Comprehensive Income Reclassifications out of Accumulated Other Comprehensive Income (Notes)

3 Months Ended

Mar. 31, 2013

Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]

Reclassifications Out of Accumulated Other Comprehensive Loss

Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss for the first quarter of 2013:

	Three Months Ended March 31, 2013
(In millions)		Reclassified to Income (Expense)			Income Statement Line
Accumulated Other Comprehensive Loss Components
Amortization of postretirement and postemployment plans
Actuarial loss		$	(13	)	General and administrative
		5			Provision for income taxes
Total reclassifications for the period		$	(8	)	Net income