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 ~~spin-off (see Note 2),~~reclassifications, general and administrative expenses for the ~~results~~first quarter of 2012 increased by $39 million which primarily includes certain costs associated with operations ~~for our downstream (Refining, Marketing~~support and ~~Transportation) business have been classified as discontinued~~ operations management. Offsetting reductions are reflected in 2011. The disclosures in this report are presented on the basis of continuing operations, unless otherwise stated. Any reference to “Marathon” indicates Marathon Oil Corporation as it existed prior to the June 30, 2011 spin-off.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 ~~(“Marathon Oil”) 2011~~2012 Annual Report on Form 10-K. The results of operations for the first quarter ~~ended March 31, 2012,~~ of 2013 are not necessarily indicative of the results to be expected for the full year.

2. ~~Spin-off Downstream Business~~Accounting Standards

Not Yet Adopted

~~On June 30, 2011,~~In February 2013, an accounting standards update was issued to provide guidance for the ~~spin-off~~recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the ~~downstream business was completed, creating two independent energy companies: Marathon Oil~~obligation is fixed at the reporting date, except for obligations such as asset retirement and ~~Marathon Petroleum Corporation (“MPC”~~environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within United States generally accepted accounting principles ("U.S. GAAP"). ~~On June 30, 2011, stockholders of record as of 5:00 p.m. Eastern Daylight Savings time on June 27, 2011 (the “Record Date”) received one common share of MPC stock~~An entity is required to measure obligations resulting from joint and several liability arrangements for ~~every two common shares of Marathon stock held as~~which the total amount of the ~~Record Date.~~

~~The following table presents selected financial information regarding~~obligation is fixed at the ~~results~~reporting date as the sum of ~~operations~~1) the amount the entity agreed to pay on the basis of ~~our downstream business reported as discontinued operations.~~

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

~~3. Accounting Standards~~

~~Recently Adopted~~

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

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 ~~FASB amended~~disclosures are intended to enable financial statement users to evaluate the ~~reporting standards for comprehensive income~~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 ~~June 2011 to eliminate the option to present the components of Other Comprehensive Income (“OCI”) as part of~~ the statement of ~~changes in stockholders' equity. All non-owner changes in stockholders’ equity~~financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of OCI, and total comprehensive income.offset. The presentation of items that are reclassified from OCI to net income on the income statement is also required. The amendments did not change the items that must be reported in OCI or when an item of OCI must be reclassified to net income. The amendments areaccounting standards update was effective for us beginning ~~with~~ the first quarter of ~~2012, except for~~2013 and we include the ~~presentation of reclassifications, which has been deferred.~~required disclosures in Note 12. Adoption of ~~these amendments~~this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

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

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

4.3. Variable Interest ~~Entities~~Entity

The owners of the Athabasca Oil Sands Project (“AOSP”), in which we hold a 20 percent undivided interest, contracted with a ~~wholly owned~~wholly-owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with ~~a $3~~current liabilities of $2 million ~~current liability~~ 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.~~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 ~~$724~~$711 million as of March 31, ~~2012.~~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.

5.4. Income per Common Share

Basic income per share is based on the weighted average number of common shares ~~outstanding, including securities exchangeable into common shares.~~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

Three Months Ended March 31,
2012 2011
(In millions, except per share data) Basic Diluted Basic Diluted

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

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

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

The per share calculations above exclude 6 million and 7 million ~~and 5 million~~ stock options and stock appreciation rights for the first ~~three months~~quarters of ~~2012~~2013 and ~~2011,~~2012 that were antidilutive.

~~6. Acquisitions~~

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

7.5. 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

OnIn January 3, 2012, we closed on the sale of our ~~Exploration and Production (“E&P”) segment’s~~ interests in several Gulf of Mexico crude oil pipeline systems for proceeds of ~~$206 million.~~$206 million. This ~~includes~~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~~$166 million was recorded in the first quarter of 2012.

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

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

Deferred credits and other liabilities 87
Total liabilities $ 87

~~2011~~

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

8.6. 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 ~~they offer.~~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;

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

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

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

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. ~~Foreign currency remeasurement and transaction~~Unrealized gains or losses ~~are not allocated to operating segments. Impairments,~~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 ~~and our consolidated totals~~ represent amounts related to corporate administrative activities and other unallocated items which are included in “Items not allocated to segments, net of income taxes” in the reconciliation below. Total capital expenditures include accruals but not corporate activities.

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)



	Three Months Ended March 31, 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

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

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

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

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

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

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

~~(a)~~

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

~~(b)~~

~~Significant dispositions are further discussed, on a pretax basis, in Note 7.~~

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~

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


	Three Months Ended March 31,					Three Months Ended March 31,
(In millions)	2012			2011		2013		2012
Total revenues		$	3,791	$	3,671	$	3,870	$	3,793
Less: Sales to related parties			14		15
Sales and other operating revenues		$	3,777	$	3,656
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

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,												Three Months Ended March 31,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011			2013			2012			2013			2012
Service cost	$	12		$	13		$	1		$	1		$	14		$	12		$	1		$	1
Interest cost		16			17			4			4		15			16			3			4
Expected return on plan assets		(16	)		(17	)		-			-		(17		)	(16		)	—			—
Amortization:
– prior service cost (credit)		2			1			(2	)		(2	)	2			2			(2		)	(2		)
– actuarial loss		12			13			-			-		13			12			—			—
Net periodic benefit cost	$	26		$	27		$	3		$	3		$	27		$	26		$	2		$	3

During the first three months of ~~2012,~~2013, we made contributions of ~~$51~~$9 million to our funded pension plans. We expect to make additional contributions up to an estimated ~~$62~~$55 million to our funded pension plans over the remainder of ~~2012.~~2013. Current benefit payments related to unfunded pension and other postretirement benefit plans were $5$9 million and $4$4 million during the first three months of ~~2012.~~2013.

~~10.~~8. Income Taxes

The effective income tax rate is influenced by a variety of factors including the geographic ~~and functional~~ sources of income and the relative magnitude of these sources of income. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to ~~individual~~ items not allocated to segments is ~~reported~~presented in ~~“Corporate~~Corporate and other unallocated ~~items” shown~~items in Note 8.6.

Our effective income tax ~~rate~~rates in the first ~~quarter~~three months of 2013 and 2012 is were 73 percent and 69 ~~percent. This rate is~~percent. These rates are higher than the U.S. statutory rate of 35 percent ~~primarily~~ due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax ~~rate is~~rates are in excess of the U.S. statutory rate. An increase in earnings and associated taxes from foreign jurisdictions, primarily Norway, as compared to prior periods caused an increase in our valuation allowance on current year foreign tax credits. In Libya, where the statutory tax rate is in excess of 90 percent ~~limited~~, there remains uncertainty around sustained production ~~resumed in the fourth quarter~~and sales levels. Reliable estimates of ~~2011~~2013 and ~~liquid hydrocarbon sales resumed in the first quarter of 2012. A reliable estimate of~~ 2012 annual ordinary income from our Libyan operations ~~cannot~~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 ~~ended March 31,~~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 ~~quarter~~three months of ~~2012.~~

Our effective tax rate in the first quarter of 2011 was 54 percent which is higher than the U.S. statutory tax rate of 35 percent primarily due to earnings from foreign jurisdictions where the tax rate is in excess of the U.S. statutory rate2013 and ~~the valuation allowance recorded against 2011 foreign tax credits.~~

2012.

~~MARATHON OIL CORPORATION~~

~~Notes to Consolidated Financial Statements (Unaudited)~~


^(b)	Monthly average AECO day ahead index.

~~Integrated Gas~~

~~Our integrated gas operations include marketing and transportation of products manufactured from natural gas, such as LNG and methanol, in Equatorial Guinea~~

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

We own a 45 percent interest in a methanol plant located in Equatorial Guinea through our investment in Atlantic Methanol Production Company LLC (“AMPCO”). Methanol demand has a direct impact on AMPCO’s earnings. Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices. AMPCO’s plant capacity of 1.1 million tones is about 2 percent of 2011 estimated world demand.

Results of Operations

Consolidated Results of ~~Operations~~Operation

Due to the spin-off of our downstream business on June 30, 2011, which is reported as discontinued operations, income from continuing operations is more representative of Marathon Oil as an independent energy company. Consolidated income ~~from continuing operations~~ before income taxes in the first quarter of ~~2012~~2013 was 365 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 firstquarter of ~~2011 primarily due~~2013 compared to ~~increased liquid hydrocarbon prices. As a result~~69 percent in the first quarter of ~~increased~~2012, with the increase related to higher income from ~~continuing~~ operations ~~before tax~~ in higher tax jurisdictions, primarily Norway ~~the effective tax rate was 69 percent in the first quarter of 2012 compared to 54 percent in the first quarter of 2011.~~

and Libya.

Sales and other operating revenues, including related party ~~Revenues~~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

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

~~E&P segment~~Total sales and other operating revenues increased ~~$85~~$486 million in the first quarter of ~~2012~~2013 from the comparable prior-year ~~period. Included~~period, with increases in ~~our~~each segment. The $303 million increase in the North America E&P segment ~~are supply optimization activities~~was primarily due to liquid hydrocarbon net sales volumes which ~~include~~increased 57 percent over the purchase of commodities from third parties for resale. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points. See the Cost of revenues discussion as revenues from supply optimization approximate the related costs. Higher average crude oil prices in the firstsame quarter of 2012 ~~increased revenues related to supply optimization.~~

~~Revenues from the sale~~. Most of ~~our U.S. production are higher in the first quarter of 2012 primarily as~~this net sales volume increase is a result of ~~higher~~ongoing development programs in the Eagle Ford and Bakken shale resource plays. Partially offsetting this increase were lower liquid hydrocarbon ~~sales volumes~~ and ~~price realizations, partially offset by decreased~~ natural gas ~~sales volumes and price~~ realizations. The following table gives details of net sales volumes and average realizations of our ~~U.S. operations.~~

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

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

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


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


^(b)	Excludes gains and losses on derivative ~~instruments.~~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.

~~Liquid~~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 ~~increased in the first quarter of 2012, reflecting~~from our ~~ongoing development programs primarily in the Eagle Ford and Bakken shale plays,~~African operations as previously discussed. Lower liquid hydrocarbon realizations partially offset ~~by decreased production in~~ the ~~Gulf of Mexico.~~volume impact.

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

Three Months Ended March 31,
2012 2011
International Operating Statistics
    Net liquid hydrocarbon sales (mbbld)(a)

           Europe 97 111
           Africa 52 58
              Total International 149 169
     Liquid hydrocarbon average realizations (per bbl) (b)

           Europe $ 123.76 $ 109.85
           Africa 94.41 81.47
              Total International $ 113.55 $ 100.10

     Net natural gas sales (mmcfd)

           Europe(c)
104 102
           Africa 418 446
              Total International 522 548
     Natural gas average realizations (per mcf) (b)

           Europe $ 9.99 $ 10.29
           Africa 0.24 0.25
              Total International $ 2.19 $ 2.12



	Three Months Ended March 31,
	2013		2012
International E&P Operating Statistics
Net liquid hydrocarbon sales volumes (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)~~
^(c)	Includes natural gas acquired for injection and subsequent resale of 1411 mmcfd and 1514 mmcfd infor the first quarters of ~~2012~~2013 and ~~2011.~~2012.

~~Compared to the first quarter of 2011, international liquid hydrocarbon~~Oil Sands Mining sales and other operating revenues increased $9 million. Synthetic crude oil sales volumes were ~~lower for the first quarter of 2012 primarily in the U.K. This was due to unplanned downtime at Foinaven and the timing of liftings.~~

16 percent~~OSM segmentrevenues~~ ~~increased $73 million~~ 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 2013from the comparable prior-year period. ~~The increase was driven primarily by a 7 percent increase~~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 ~~average realizations~~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 ~~an 18 percent increase in sales volumes as shown in the table below.~~to achieve flexibility within product types and delivery points.

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

~~(a)~~

~~Includes blendstocks.~~

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

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

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

Net gain on disposal of assets in the first quarter of 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 ~~was primarily~~ 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 ~~Cost of revenues~~(“DD&A”) increased $3$173 million in the first quarter of ~~2012~~2013 from the comparable prior-year period, primarily due to our supply optimization activities. Costs related to supply optimization were $775 million in the first quarter of 2012 compared to $738 million in the first quarter of 2011. Excluding costs related to supply optimization, the overall decrease in costs is primarily the result of lower liquid hydrocarbon sales in the U.K. due to the timing of liftings.

~~Depreciation, depletion and amortization (“DD&A”)~~ ~~decreased $61 million in the first quarter of 2012 compared to the same quarter of 2011. Because both our E&P and OSM~~period. Our segments apply the units-of-production method to the majority of their ~~assets,~~assets; therefore, the previously discussed increases ~~or decreases~~ in sales volumes generally result in similar changes in DD&A. ~~Decreased DD&A in the first quarter reflects the impact of lower E&P segment sales volumes, partially offset by increases in the OSM segment.~~ The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in reserves and capitalized costs, can also cause changes in our DD&A. ~~Lower~~A lower International E&P DD&A ~~rates per barrel~~rate in ~~our E&P operations contributed~~the first quarter of 2013, primarily due to reserve increases at the end of 2012 for Norway, compared to the ~~overall lower DD&A.~~same period in 2012 partially offset the impact of higher sales volumes. The following table provides DD&A rates for ~~our E&P and OSM segments.~~each segment.

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



	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

Impairments in the first quarter of ~~2012 relate~~2013 related primarily to the Powder River Basin and to the Ozona development in the Gulf of ~~Mexico (see~~Mexico. Impairments in the first quarter of 2012 were also primarily related to the Ozona development in the Gulf of Mexico. See Note 1311 to the consolidated financial ~~statements).~~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.

~~General~~Net interest and ~~administrative expenses~~other ~~decreased during~~increased $22 million in the first quarter of ~~2012~~2013 from the comparable ~~prior year~~ period of 2012 primarily due to ~~decreased incentive compensation expense.~~ lower capitalized interest in 2013.

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

~~The following table summarizes the components of exploration expenses.~~

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

Provision for income taxes increased ~~$391~~$98 million in the first quarter of ~~2012~~2013 from the comparable period of ~~2011~~2012 primarily due to the increase in pretax income ~~and the resumption of sales~~ in ~~Libya in the first quarter of 2012.~~high tax rate jurisdictions.

The effective income tax rate is influenced by a variety of factors including the geographic ~~and functional~~ sources of income and the relative magnitude of these sources of income. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to ~~individual~~ items not allocated to segments is ~~reported~~shown in ~~“Corporate~~corporate and other unallocated ~~items” shown~~items in ~~Note 8 to~~ the ~~consolidated financial statements.~~segment income table below.

Our effective tax ~~rate~~rates in the first ~~quarter~~ three months of 2013 and 2012 is were 73 percent and 69 ~~percent. This rate is~~percent. These rates are higher than the U.S. statutory rate of 35 percent ~~primarily~~ due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax ~~rate is~~rates are in excess of the U.S. statutory rate. An increase in earnings and associated taxes from foreign jurisdictions, primarily Norway, as compared to prior periods caused an increase in our valuation allowance on current year foreign tax credits. In Libya, where the statutory tax rate is in excess of 90 percent, ~~limited~~there remains uncertainty around sustained production ~~resumed in the fourth quarter~~and sales levels. Reliable estimates of ~~2011~~2013 and ~~liquid hydrocarbon sales resumed in the first quarter of 2012. A reliable estimate of~~ 2012 annual ordinary income from our Libyan operations ~~cannot~~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 firstthree months ~~ended March 31,~~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 ~~quarter~~ three months of ~~2012.~~

~~Segment Results~~

~~Segment income~~ ~~is summarized in the following table.~~2012.

Segment Income (Loss)

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



	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

~~United States~~ North America E&P segment income ~~increased $79~~decreased $163 million in the first quarter of ~~2012~~2013 compared to the same period of ~~2011. Increased~~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, and price realizations and, lower dry well costs and DD&A in the Gulf of Mexico, were partially offset by higher operating costs associated with increased activities in the Eagle Ford and Bakken shale plays in the first quarter of 2012.as discussed above.

International E&P segment income ~~decreased $270~~increased $46 million in the first quarter of ~~2012~~2013 compared to the same period of ~~2011. As previously discussed,~~2012. The increase was primarily related to higher liquid hydrocarbon sales volumes and increased income ~~before tax in~~from equity method investments, partially offset by higher ~~tax jurisdictions resulted in a 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 ~~tax rate~~for us beginning in the first quarter of ~~2012 compared to~~2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the ~~same period~~beginning of ~~2011. Increased liquid hydrocarbon price realizations were mostly offset by~~2014. Early adoption is permitted. We are currently evaluating the ~~declines in sales volumes previously discussed. DD&A was lower in the first quarter~~potential impact of ~~2012 as a result~~this accounting standards update on our consolidated results of ~~lower sales volumes, as well as lower exploration costs in Indonesia.~~

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

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

Cash Flows and Liquidity

Cash Flows

~~Cash Flows~~

Net cash provided by ~~continuing operations~~ operating activitieswas ~~$973~~$1,528 million in the first three months of 2013, compared to $973 million in the first three months of 2012 ~~compared to $1,633~~ 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 ~~2011 reflecting primarily the lower E&P segment sales volumes, lower natural gas realizations and a negative change in working capital.~~2013

, compared to ~~Net cash used in investing activities~~$806 million ~~totaled $806 million~~ in the first ~~quarter~~three months of 2012 ~~compared to $711 million related to continuing operations in the first quarter of 2011.~~. Significant investing activities are additions to property, plant and equipment and disposal of assets. ~~In the first quarter of 2012, most additions to property, plant and equipment were~~Additions in both periods primarily related to ~~our increased~~ spending inon U.S. unconventional resource plays, particularly the Eagle Ford ~~shale~~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 ~~resumption~~sales of ~~drilling~~our Alaska assets and our interest in the Gulf of Mexico. This compares to the first quarter of 2011, when spending on U.S. unconventional resource plays and drilling in Norway, Indonesia and the Iraqi Kurdistan Region accounted for most of the property, plant and equipment additions.Neptune gas plant. In ~~the first quarter of~~ 2012, net proceeds ~~from the sale of assets were $208 million,~~resulted primarily ~~related to~~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 activities was ~~$157~~$413 million in the first ~~quarter~~three months of 2013, compared to $157 million in the first three months of 2012 ~~compared to net cash used~~. Repayments of ~~$2,937~~debt at maturity were $114 million ~~related to continuing operations~~ in the first ~~quarter~~three months of ~~2011. During~~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 ~~quarter~~three months of ~~2012, we repaid $53 million of debt upon its maturity. During the first quarter of 2011, we retired $2.5 billion principal amount of our debt before it was due.~~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-core~~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. ~~We issued and repaid $100 million of commercial paper in the first quarter of 2012.~~ Because of the alternatives available to us ~~including internally generated cash flow~~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

~~Capital Resources~~

At March 31, ~~2012,~~2013, we had no borrowings against our revolving credit facility ~~and no commercial paper outstanding~~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.

~~In April 2012,~~At March 31, 2013, we ~~terminated~~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 $3.0 billion five-year revolving credit facility and replaced it with a new $2.5 billion unsecured five-year revolving credit facility (the “Credit Facility”). The Credit Facility matures in April 2017 but allows us to request two, one-year extensions. It contains an option to increase the commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, and includes sub-facilities for swing-line loans and letters of credit up to an aggregate amount of $100 million and $500 million, respectively. Fees on the unused commitment of each lender range from 10 basis points to 25 basis points per year depending on our credit ratings. Borrowings under the Credit Facility bear interest, at our option, at either (a) the adjusted London Interbank Offered Rate (LIBOR) plus a margin ranging from 87.5 basis points to 162.5 basis points per year depending on our credit ratings or (b) the Base Rate plus a margin ranging from 0.0 basis points to 62.5 basis points depending on our credit ratings. Base Rate is defined as a per annum rate equal to the greatest of (a) the prime rate, (b) the federal funds rate plus one-half of one percent and (c) LIBOR for a one-month interest period plus 1 percent.

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

Shelf Registration

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

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 2024 percent at March 31, ~~2012 and~~ 2013, compared to 25 percent at December 31, ~~2011.~~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		%

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

Capital Requirements

On April ~~25, 2012,~~24, 2013, our Board of Directors approved a dividend of 17 cents per share ~~dividend,~~for the first quarter of 2013, payable June ~~11, 2012~~10, 2013 to stockholders of record at the close of business on May 16, ~~2012.~~

2013.

As ~~discussed~~of March 31, 2013, we plan to make contributions of up to $55 million to our funded pension plans in Note 6 to the consolidated financial statements, the majority of the transactions, in terms of value, related to the Eagle Ford shale are expected to close in the third quarter of 2012, at which time the purchase price of approximately $7672013, $17 million ~~before closing adjustments, will be paid.~~

~~We have increased our capital, investment and exploration budget, excluding acquisition costs, from $4.8 billion to $5.0 billion,~~ of which ~~$4.6 billion will be used for capital expenditures. The increase is a result of the additional acreage being acquired~~were made in ~~the Eagle Ford shale and other adjustments.~~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 ~~and the capital, investment and exploration budget~~ are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. ~~Estimates may differ from actual results.~~ Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The discussion of liquidity above also contains forward-looking statements ~~about our capital, investment and exploration budget~~regarding planned funding of pension plans, which are based on current expectations, estimates and projections and are not guarantees of ~~future~~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 ~~are changes in~~include prices of and demand for liquid hydrocarbons, natural gas and synthetic crude oil, ~~and natural gas,~~ 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.

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

Contractual Cash Obligations

As of March 31, ~~2012,~~2013, our ~~consolidated~~total contractual cash obligations ~~have increased by $128 million from~~were consistent with December 31, ~~2011, primarily related to contracts to acquire property, plant and equipment.~~2012.

~~Critical Accounting Estimates~~

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

Environmental Matters

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.

There have been no ~~other~~ significant changes to our environmental matters subsequent to December 31, ~~2011.~~2012.

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.

~~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 contractSee Part II Item 1. Legal Proceedings for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. Noble is seeking an unspecified amount of damages. We are vigorously defending thisupdated information about ongoing litigation. The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain. We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our ~~2011~~2012 Annual Report on Form 10-K.

~~Disclosures about~~ Additional disclosures regarding our open derivative positions, such as how ~~derivatives~~they are reported in our consolidated financial statements and how ~~the~~their fair values ~~of our derivative instruments~~ are measured, may be found in ~~Note 13~~Notes 11 and ~~Note 14~~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, ~~2012~~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	)

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

~~(a)~~

Fair values of cash and cash equivalents, receivables, 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, ~~2012~~2013 would be ~~$63 million.~~$61 million.

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

Item 4. Controls and Procedures

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

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

~~MARATHON OIL CORPORATION~~

~~Supplemental Statistics (Unaudited)~~

^(a)

Three Months Ended March 31,
(In millions) 2012 2011

Segment Income (Loss)
     Exploration and Production
          United States $ 109 $ 30
          International 368 638
               E&P segment 477 668
     Oil Sands Mining 41 32
     Integrated Gas 4 60
          Segment income 522 760
     Items not allocated to segments, net of income taxes (105 ) (305 )
      Income from continuing operations 417 455
Discontinued Operations(a)
- 541
               Net income $ 417 $ 996
Capital Expenditures(b)

     Exploration and Production
          United States $ 862 $ 349
          International 139 319
               E&P segment 1,001 668
     Oil Sands Mining 52 120
     Integrated Gas - 1
     Corporate 42 6
               Total $ 1,095 $ 795
Exploration Expenses
     United States $ 93 $ 151
     International 49 79
               Total $ 142 $ 230

~~(a)~~

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

~~(b)~~

Capital expenditures include changes in accruals.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended
	March 31,
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

~~MARATHON OIL CORPORATION~~

^(b)	~~Supplemental Statistics (Unaudited)~~

Three Months Ended March 31,
2012 2011

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

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

     Natural Gas Sales (mmcfd)(c)

          United States 344 368

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

     Total Worldwide Sales (mboed) 383 400

     Average Realizations (d)

        Liquid Hydrocarbons (per bbl)
           United States $ 93.63 $ 86.42

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

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

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

IG Operating Statistics
     Net Sales (mtd) (g)

         LNG 6,291 7,822
         Methanol 1,312 1,318

~~(c)~~

Includes natural gas acquired for injection and subsequent resale of 1411 mmcfd and 1514 mmcfd for the first ~~three months~~quarters of ~~2012~~2013 and ~~2011.~~2012.


^(c)	Includes blendstocks.

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 a fixed ~~price~~prices under long-term contracts with Alba Plant LLC, Atlantic Methanol Production Company LLC ~~(“AMPCO”)~~ and Equatorial Guinea LNG Holdings Limited, ~~(“EGHoldings”),~~which are equity method investees. We include our share of ~~Alba Plant LLC’s~~ income from each of these equity method investees in our International E&P ~~segment and we include our share of AMPCO’s and EGHoldings’ income in our Integrated Gas~~ segment.

~~(f)~~

~~Includes blendstocks.~~

~~(g)~~

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

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

We are 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 ~~that~~ the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. ~~There have been no significant changes~~Certain of those matters are discussed below.

Litigation

In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in ~~legal or environmental proceedings during~~ the ~~first~~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 ~~2012.~~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 ~~2011~~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 ~~and its affiliated purchaser~~ during the quarter ended March 31, ~~2012,~~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 Approximate Dollar
Shares Purchased as Value of Shares that
Part of Publicly May Yet Be Purchased
Total Number of Average Price Paid Announced Plans or Under the Plans or
Period
Shares Purchased (a)(b)
per Share
Programs (c)

Programs (c)

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



	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)~~	~~58,812~~
^(a)	120,431 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

In March ~~2012, 28,386~~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)~~

^(c)

We announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion. As of March 31, ~~2012,~~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 (see Note 2 to the consolidated financial statements).~~business.

Item 4. Mine Safety Disclosures

Not applicable.

Item 6. Exhibits

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

4.1 Credit Agreement, dated as of April 5, 2012, among Marathon Oil Corporation, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and UBS Securities LLC, as documentation agents, JP Morgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions named therein. 8-K 4.1 4/10/2012

10.1 Marathon Oil Corporation 2012 Incentive Compensation Plan. DEF 14A App. III 3/8/2012

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

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

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

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

10.2

Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan

12.1

Computation of Ratio of Earnings to Fixed Charges.

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase.

101.DEF

XBRL Taxonomy Extension Definition Linkbase.

101.LAB

XBRL Taxonomy Extension Label Linkbase.



(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended March 31, ~~2012~~2013



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



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

	Three Months Ended March 31,
(In millions)	2012			2011
Net income	$	417		$	996
Other comprehensive income

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

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

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

Other comprehensive income		9			26

Comprehensive income	$	426		$	1,022


	March 31,			December 31,			March 31,			December 31,
(In millions, except per share data)	2012			2011			2013			2012
Assets
Current assets:
Cash and cash equivalents	$	513		$	493		$	768		$	684
Receivables, less allowance for doubtful accounts of zero		2,198			1,917
Receivables from related parties		35			35
Receivables							2,466			2,418
Inventories		296			361		368			361
Prepayments		83			96
Deferred tax assets		87			99
Other current assets		233			223		175			299

Total current assets		3,445			3,224		3,777			3,762

Equity method investments		1,353			1,383		1,304			1,279
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $17,184 and $17,248		25,365			25,324
depletion and amortization of $20,195 and $19,266							28,382			28,272
Goodwill		525			536		528			525
Other noncurrent assets		1,163			904		1,118			1,468

Total assets	$	31,851		$	31,371		$	35,109		$	35,306
Liabilities
Current liabilities:
Commercial paper							$	—		$	200
Accounts payable	$	2,029		$	1,864		2,284			2,324
Payables to related parties		10			18
Payroll and benefits payable		165			193		182			217
Accrued taxes		2,065			2,015		1,892			1,983
Other current liabilities		207			163		203			173
Long-term debt due within one year		197			141		68			184

Total current liabilities		4,673			4,394		4,629			5,081

Long-term debt		4,559			4,674		6,476			6,512
Deferred income taxes		2,540			2,544
Deferred tax liabilities							2,401			2,432
Defined benefit postretirement plan obligations		747			789		850			856
Asset retirement obligations		1,437			1,510		1,795			1,749
Deferred credits and other liabilities		389			301		370			393

Total liabilities		14,345			14,212		16,521			17,023

Commitments and contingencies

Stockholders’ Equity
Preferred stock – no shares issued and outstanding (no par value, 26 million shares
authorized)		-			-
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		770			770
Securities exchangeable into common stock – no shares issued and outstanding
(no par value, 29 million shares authorized)		-			-
Held in treasury, at cost – 65 million and 66 million shares		(2,652	)		(2,716	)
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		6,658			6,680		6,618			6,616
Retained earnings		13,084			12,788		14,153			13,890
Accumulated other comprehensive loss		(361	)		(370	)	(426		)	(433		)
Total equity of Marathon Oil's stockholders		17,499			17,152
Noncontrolling interest		7			7
Total stockholders' equity		17,506			17,159

Total equity							18,588			18,283
Total liabilities and stockholders' equity	$	31,851		$	31,371		$	35,109		$	35,306



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



	INDEX
		Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)		2
	Consolidated Statements of Comprehensive Income (Unaudited)		3
	Consolidated Balance Sheets (Unaudited)		4
	Consolidated Statements of Cash Flows (Unaudited)		5
	Notes to Consolidated Financial Statements (Unaudited)		6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		16	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		26	29
Item 4.	Controls and Procedures		26	29
	Supplemental Statistics (Unaudited)		27	30
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		29	33
Item 1A.	Risk Factors		29	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		29	33
Item 4.	Mine Safety Disclosures		29	33
Item 6.	Exhibits		30	34
	Signatures		32	35

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



	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

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

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

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



		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



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

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



	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



	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

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


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



May ~~4, 2012~~10, 2013		MARATHON OIL CORPORATION

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