UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended ~~September 30, 2012~~March 31, 2013



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

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)



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

5555 San Felipe Street, Houston, TX 77056-2723

(Address of principal executive offices)

(713) 629-6600

(Registrant’s telephone number, including area code)

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

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

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



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

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

Yes o No þ

There were ~~706,417,267~~708,817,008 shares of Marathon Oil Corporation common stock outstanding as of ~~October 31, 2012~~April 30, 2013.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended ~~September 30, 2012~~March 31, 2013

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

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
(In millions, except per share data)	2012			2011			2012			2011			2013			2012
Revenues and other income:
Sales and other operating revenues	$	4,018		$	3,633		$	11,513		$	10,969
Sales to related parties	16			16			43			45
Sales and other operating revenues, including related party													$	3,440		$	2,954
Marketing revenues													430			839
Income from equity method investments	122			123			260			360			118			78
Net gain (loss) on disposal of assets	(12		)	13			126			63
Net gain on disposal of assets													109			166
Other income	17			14			43			36			9			3
Total revenues and other income	4,161			3,799			11,985			11,473			4,106			4,040
Costs and expenses:
Cost of revenues (excludes items below)	1,296			1,600			4,005			4,671
Purchases from related parties	72			57			191			184
Production													578			514
Marketing, including purchases from related parties													429			842
Other operating													111			92
Exploration													465			135
Depreciation, depletion and amortization	625			517			1,779			1,716			747			574
Impairments	8			—			271			307			38			262
General and administrative expenses	139			104			389			371
Other taxes	63			59			208			170
Exploration expenses	176			129			491			504
Taxes other than income													84			68
General and administrative													174			159
Total costs and expenses	2,379			2,466			7,334			7,923			2,626			2,646
Income from operations	1,782			1,333			4,651			3,550			1,480			1,394
Net interest and other	(53		)	(30		)	(160		)	(62		)	(72		)	(50		)
Loss on early extinguishment of debt	—			—			—			(279		)
Income from continuing operations
before income taxes	1,729			1,303			4,491			3,209
Income before income taxes													1,408			1,344
Provision for income taxes	1,279			898			3,231			2,051			1,025			927
Income from continuing operations	450			405			1,260			1,158
Discontinued operations	—			—			—			1,239
Net income	$	450		$	405		$	1,260		$	2,397		$	383		$	417
Per Share Data
Basic:
Income from continuing operations	$0.64			$0.57			$1.79			$1.63
Discontinued operations	—			—			—			$1.74
Net income	$0.64			$0.57			$1.79			$3.37
Diluted:
Income from continuing operations	$0.63			$0.57			$1.78			$1.62
Discontinued operations	—			—			—			$1.73
Net income	$0.63			$0.57			$1.78			$3.35
Net Income:
Basic														$0.54			$0.59
Diluted														$0.54			$0.59
Dividends paid	$0.17			$0.15			$0.51			$0.65				$0.17			$0.17
Weighted average shares:
Basic	706			711			705			712			708			706
Diluted	709			714			709			716			712			710

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
(In millions)	2012			2011			2012			2011			2013			2012
Net income	$	450		$	405		$	1,260		$	2,397		$	383		$	417
Other comprehensive income
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	(90		)	13			(80		)	110			13			13
Spin-off downstream business	—			—			—			968
Income tax benefit (provision) on postretirement and
Income tax provision on postretirement and
postemployment plans	32			6			28			(409		)	(5		)	(5		)
Postretirement and postemployment plans, net of tax	(58		)	19			(52		)	669			8			8
Derivative hedges
Net unrecognized gain (loss)	1			(1		)	1			9
Spin-off downstream business	—			—			—			(7		)
Income tax provision on derivatives	—			—			—			(1		)
Derivative hedges, net of tax	1			(1		)	1			1
Foreign currency translation and other
Unrealized loss	—			—			—			(1		)
Unrealized gain (loss)													(1		)	1
Income tax provision on foreign currency translation and other	—			—			—			—			—			—
Foreign currency translation and other, net of tax	—			—			—			(1		)	(1		)	1
Other comprehensive income (loss)	(57		)	18			(51		)	669
Other comprehensive income													7			9
Comprehensive income	$	393		$	423		$	1,209		$	3,066		$	390		$	426

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	September 30,			December 31,			March 31,			December 31,
(In millions, except per share data)	2012			2011			2013			2012
Assets
Current assets:
Cash and cash equivalents	$	671		$	493		$	768		$	684
Receivables	2,553			1,917			2,466			2,418
Receivables from related parties	22			35
Inventories	324			361			368			361
Prepayments	111			96
Deferred tax assets	87			99
Other current assets	269			223			175			299
Total current assets	4,037			3,224			3,777			3,762
Equity method investments	1,319			1,383			1,304			1,279
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $18,438 and $17,248	27,446			25,324
depletion and amortization of $20,195 and $19,266							28,382			28,272
Goodwill	525			536			528			525
Other noncurrent assets	1,231			904			1,118			1,468
Total assets	$	34,558		$	31,371		$	35,109		$	35,306
Liabilities
Current liabilities:
Commercial paper	$	1,839		$	—		$	—		$	200
Accounts payable	2,335			1,864			2,284			2,324
Payables to related parties	44			18
Payroll and benefits payable	148			193			182			217
Accrued taxes	2,027			2,015			1,892			1,983
Other current liabilities	206			163			203			173
Long-term debt due within one year	183			141			68			184
Total current liabilities	6,782			4,394			4,629			5,081
Long-term debt	4,518			4,674			6,476			6,512
Deferred tax liabilities	2,495			2,544			2,401			2,432
Defined benefit postretirement plan obligations	817			789			850			856
Asset retirement obligations	1,516			1,510			1,795			1,749
Deferred credits and other liabilities	366			301			370			393
Total liabilities	16,494			14,212			16,521			17,023
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued and outstanding (no par value,
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
Securities exchangeable into common stock – no shares issued or
outstanding (no par value, 29 million shares authorized)	—			—			—			—
Held in treasury, at cost – 64 million and 66 million shares	(2,607		)	(2,716		)
Held in treasury, at cost – 62 million and 63 million shares							(2,527		)	(2,560		)
Additional paid-in capital	6,634			6,680			6,618			6,616
Retained earnings	13,688			12,788			14,153			13,890
Accumulated other comprehensive loss	(421		)	(370		)	(426		)	(433		)
Total equity of Marathon Oil's stockholders	18,064			17,152
Noncontrolling interest	—			7
Total equity	18,064			17,159			18,588			18,283
Total liabilities and stockholders' equity	$	34,558		$	31,371		$	35,109		$	35,306

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


	Nine Months Ended						Three Months Ended
	September 30,						March 31,
(In millions)	2012			2011			2013			2012
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	1,260		$	2,397		$	383		$	417
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations	—			(1,239		)
Loss on early extinguishment of debt	—			279
Deferred income taxes	(27		)	(75		)	44			(22		)
Depreciation, depletion and amortization	1,779			1,716			747			574
Impairments	271			307			38			262
Pension and other postretirement benefits, net	(56		)	28			7			(29		)
Exploratory dry well costs and unproved property impairments	287			311			404			58
Net gain on disposal of assets	(126		)	(63		)	(109		)	(166		)
Equity method investments, net	(14		)	16			(48		)	(21		)
Changes in:
Current receivables	(646		)	202			(4		)	(296		)
Inventories	(6		)	47			(15		)	7
Current accounts payable and accrued liabilities	156			361			(54		)	213
All other operating, net	(66		)	113			135			(24		)
Net cash provided by continuing operations	2,812			4,400
Net cash provided by discontinued operations	—			1,090
Net cash provided by operating activities	2,812			5,490			1,528			973
Investing activities:
Acquisitions, net of cash acquired	(806		)	—
Additions to property, plant and equipment	(3,509		)	(2,437		)	(1,375		)	(1,017		)
Disposal of assets	193			385			312			208
Investments - return of capital	42			41			18			15
Investing activities of discontinued operations	—			(493		)
Property deposit	—			(120		)
All other investing, net	49			13			8			(12		)
Net cash used in investing activities	(4,031		)	(2,611		)	(1,037		)	(806		)
Financing activities:
Commercial paper, net	1,839			—			(200		)	—
Debt issuance costs	(9		)	—
Debt repayments	(111		)	(2,843		)	(114		)	(53		)
Purchases of common stock	—			(300		)
Dividends paid	(360		)	(462		)	(120		)	(121		)
Financing activities of discontinued operations	—			2,916
Distribution in spin-off	—			(1,622		)
All other financing, net	26			129			21			17
Net cash provided by (used in) financing activities	1,385			(2,182		)
Net cash used in financing activities							(413		)	(157		)
Effect of exchange rate changes on cash	12			(15		)	6			10
Net increase in cash and cash equivalents	178			682			84			20
Cash and cash equivalents at beginning of period	493			3,951			684			493
Cash and cash equivalents at end of period	$	671		$	4,633		$	768		$	513

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

These consolidated financial statements are unaudited; however, in the opinion of management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission ("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 ~~2011~~2012 Annual Report on Form 10-K. The results of operations for the ~~third~~first quarter ~~and first nine months~~ of ~~2012~~2013 are not necessarily indicative of the results to be expected for the full year.

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

~~On June 30, 2011,~~Not Yet Adopted

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 which are reported as discontinued operations. Transaction costs incurred~~its arrangement among its co-obligors and 2) any amount the entity expects to ~~affect~~pay on behalf of its co-obligors. Disclosure of the ~~spin-off~~nature of ~~$74 million~~ ~~are included in discontinued operations for 2011.~~

Three Months Ended Nine Months Ended
September 30, September 30,
(In millions) 2011 2011
Revenues applicable to discontinued operations $ —
$ 38,602
Pretax income from discontinued operations —
2,012

~~3. Accounting Standards~~

~~Recently Adopted~~

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.

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

In May 2011, the FASB issued an update amending the accounting standards for fair value measurement and disclosure, resulting in common principles and requirements under accounting principles generally accepted in the U.S. (“U.S. GAAP”) and International Financial Reporting Standards (“IFRS”). The amendments change the wording used to describe certain of the U.S.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~GAAP requirements~~In December 2011, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosures are intended to enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclose both gross information and net information about in-scope financial instruments that are either offset in the statement of financial position or subject to ~~clarify the intent~~an enforceable master netting arrangement or similar agreement, irrespective of ~~existing requirements, to change measurement or expand disclosure principles or to conform to the wording used in IFRS.~~whether they are offset. The ~~amendments are to be applied prospectively~~accounting standards update was effective for ~~our interim and annual periods~~us beginning ~~with~~ the first quarter of ~~2012. The adoption~~2013 and we include the required disclosures in Note 12. Adoption of ~~the amendments~~this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows. ~~To the extent they were necessary, we have made the expanded disclosures in Note 13.~~

4.3. Variable Interest Entity

The owners of the Athabasca Oil Sands Project (“AOSP”), in which we hold a 20 percent undivided interest, contracted with a wholly-owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with acurrent liabilities of $2 million and $3 million ~~current liability~~ recorded at ~~September 30, 2012~~March 31, 2013~~, consistent with~~ and December 31, ~~2011.~~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~~variable interest entity (“VIE”). We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore the Corridor Pipeline is not consolidated by ~~Marathon Oil.~~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 $~~697~~711 million as of ~~September 30, 2012~~March 31, 2013. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.

5.4. Income per Common Share

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


	Three Months Ended September 30,								Three Months Ended March 31,
	2012				2011				2013				2012
(In millions, except per share data)	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
Net income	$	450	$	450	$	405	$	405	$	383	$	383	$	417	$	417

Weighted average common shares outstanding	706		706		711		711		708		708		706		706
Effect of dilutive securities	—		3		—		3		—		4		—		4
Weighted average common shares, including
dilutive effect	706		709		711		714		708		712		706		710
Per share:
Net income	$0.64		$0.63		$0.57		$0.57			$0.54		$0.54		$0.59		$0.59

~~MARATHON OIL CORPORATION~~

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

Nine Months Ended September 30,
2012 2011
(In millions, except per share data) Basic Diluted Basic Diluted
Income from continuing operations $ 1,260
$ 1,260
$ 1,158
$ 1,158
Discontinued operations —
—
1,239
1,239
Net income $ 1,260
$ 1,260
$ 2,397
$ 2,397

Weighted average common shares outstanding 705
705
712
712
Effect of dilutive securities —
4
—
4
Weighted average common shares, including
dilutive effect 705
709
712
716
Per share:

Income from continuing operations $1.79 $1.78 $1.63 $1.62
Discontinued operations —
—
$1.74 $1.73
Net income $1.79 $1.78 $3.37 $3.35

The per share calculations above exclude ~~10 million~~ ~~stock options and stock appreciation rights for the~~ ~~third~~ ~~quarter and first~~ ~~nine~~ ~~months of~~ ~~2012, as they were antidilutive. Excluded for the~~ ~~third~~ ~~quarter and first~~ ~~nine~~ ~~months of~~ ~~2011~~ ~~were~~ 96 million and 7 million stock options and stock appreciation ~~rights.~~

~~6. Acquisitions~~

~~We acquired approximately~~ ~~20,000~~ ~~net acres in the core of the Eagle Ford shale during~~rights for the first ~~nine months~~quarters of ~~2012. All Eagle Ford properties are included in our Exploration~~2013 and ~~Production (“E&P”) segment. The largest transaction was the acquisition of Paloma Partners II, LLC, which closed August 1, 2012 for cash consideration of~~ ~~$768 million~~2012~~. This transaction was accounted for as a business combination. Smaller transactions closed during the second quarter of 2012.~~ that were antidilutive.

~~The following table summarizes the amounts allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition date:~~

(In millions)
Assets:
Cash $ 8
Receivables 22
Inventories 1
Total current assets acquired 31
Property, plant and equipment 822
Total assets acquired 853
Liabilities:
Accounts payable 78
Asset retirement obligations 7
Total liabilities assumed 85
Net assets acquired $ 768

The fair values of assets acquired and liabilities assumed were measured primarily using an income approach, specifically utilizing a discounted cash flow analysis. The estimated fair values were based on significant inputs not observable in the market, and therefore represent Level 3 measurements. Significant inputs included estimated reserve volumes, the expected future production profile, estimated commodity prices and assumptions regarding future operating and development costs. A discount rate of approximately ~~10 percent~~ was used in the discounted cash flow analysis. The accounting for this transaction is complete. The pro forma impact of this business combination is not material to our consolidated statements of income for the third quarter and first nine months of 2012 and 2011.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

7.5. Dispositions

~~2012~~2013 - North America Exploration and Production ("E&P") Segment

In April 2013, we reached an agreement to sell our interests in the ~~third~~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 ~~2012,~~2013.

In February 2013, we ~~sold approximately~~ ~~5,800~~ ~~net undeveloped acres~~closed the sale of our interest in the Neptune gas plant, located ~~outside the core of the Eagle Ford shale, held by our E&P segment,~~onshore Louisiana, for proceeds of $9166 million. A $98 millionpretax ~~loss~~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 $18195 million ~~was recorded.~~

~~In May 2012, we executed agreements~~, subject to ~~relinquish our E&P segment’s operatorship of and participating interests in the Bone Bay and Kumawa exploration licenses in Indonesia. As~~ a ~~result, we accrued and reported a~~ ~~$36 million~~ loss on disposal of assets in the second quarter of 2012. Government ratification of the agreements was received during the third quarter of 2012, which released us from our obligations and further commitments related to these licenses, and we paid the amount accrued.

~~In April 2012, we entered into agreements to sell all of our E&P segment’s assets in Alaska. One transaction closed in the second quarter of 2012 with proceeds and a net pretax gain~~six-month escrow of $750 million~~. The remaining transaction, with a value of~~ for various indemnities. A $~~375~~46 million pretax gain, before closing adjustments, ~~is currently under review by the U.S. Federal Trade Commission and the Alaska Attorney General's office, which could impact the closing of this transaction. Assets held for sale are included~~was recorded in the ~~September 30, 2012 balance sheet as follows:~~first quarter of 2013.

(In millions)
Other current assets $ 59
Other noncurrent assets 190
Total assets 249
Other current liabilities 1
Deferred credits and other liabilities 90
Total liabilities $ 91
2012 - North America E&P Segment

In January 2012, we closed on the sale of our ~~E&P segment’s~~ interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $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 million was recorded in the first quarter of 2012.

~~2011~~

~~In September 2011, we sold our Integrated Gas segment's equity interest in a liquefied natural gas (“LNG”) processing facility in Alaska. A gain on the transaction of~~ ~~$8 million~~ ~~was recorded in the third quarter of 2011.~~

~~In April 2011, we assigned a~~ ~~30 percent~~ ~~undivided working interest in our E&P segment’s approximately~~ ~~180,000~~ ~~acres in the Niobrara shale play located within the DJ Basin of southeast Wyoming and northern Colorado for total consideration of~~ ~~$270 million, recording a pretax gain of~~ ~~$39 million. We remain operator of this jointly owned leasehold.~~

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

~~Exploration and Production (“~~North America E~~&P”~~&P ("N.A. E&P") – explores for, produces and markets liquid hydrocarbons and natural gas ~~on a worldwide basis;~~in North America;

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

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

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

~~MARATHON OIL CORPORATION~~

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

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. ~~Impairments,~~Unrealized gains or losses on crude oil derivative instruments, impairments, gains or losses on disposal of assets or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.

Differences between segment totals and our consolidated totals for income taxes and depreciation, depletion and amortization represent amounts related to corporate administrative activities and other unallocated items which are included in “Items not allocated to segments, net of income taxes” in the reconciliation below. Total capital expenditures include accruals but not corporate activities.

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

Three Months Ended September 30, 2012
(In millions) E&P OSM IG Total
Revenues:

Customer $ 3,503
$ 470
$ —
$ 3,973
Related parties 16
—
—
16
Segment revenues $ 3,519
$ 470
$ —
3,989
Unrealized gain on crude oil derivative instruments 45
Total revenues $ 4,034
Segment income $ 486
$ 65
$ 39
$ 590
Income from equity method investments 74
—
48
122
Depreciation, depletion and amortization 556
60
—
616
Income tax provision 1,252
20
9
1,281
Capital expenditures 1,274
41
1
1,316

Three Months Ended September 30, 2011
(In millions) E&P OSM IG Total
Revenues:

Customer $ 3,190
$ 427
$ 16
$ 3,633
Intersegment 6
—
—
6
Related parties 16
—
—
16
Segment revenues $ 3,212
$ 427
$ 16
3,655
Elimination of intersegment revenues

(6 )
Total revenues

$ 3,649
Segment income $ 330
$ 92
$ 55
$ 477
Income from equity method investments 63
—
60
123
Depreciation, depletion and amortization 454
55
—
509
Income tax provision 890
31
19
940
Capital expenditures 684
36
1
721

108

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Nine Months Ended September 30, 2012								Three Months Ended March 31, 2013
(In millions)	E&P		OSM		IG		Total		N.A. E&P			Int'l E&P		OSM		Total
Revenues:
Customer	$	10,284	$	1,184	$	—	$	11,468
Related parties	43		—		—		43
Sales and other operating revenues									$	1,215		$	1,887	$	388	$	3,490
Marketing revenues									345			85		—		430
Segment revenues	$	10,327	$	1,184	$	—	11,511		$	1,560		$	1,972	$	388	3,920
Unrealized gain on crude oil derivative instruments							45
Unrealized loss on crude oil derivative instruments																(50		)
Total revenues							$	11,556								$	3,870
Segment income	$	1,380	$	157	$	56	$	1,593
Segment income (loss)									$	(59	)	$	453	$	38	$	432
Income from equity method investments	176		—		84		260		—			118		—		118
Depreciation, depletion and amortization	1,593		159		—		1,752		478			207		52		737
Income tax provision	3,398		51		15		3,464
Income tax provision (benefit)									(30		)	1,142		13		1,125
Capital expenditures	3,459		136		2		3,597		970			225		45		1,240


	Nine Months Ended September 30, 2011									Three Months Ended March 31, 2012
(In millions)	E&P		OSM		IG		Total			N.A. E&P		Int'l E&P		OSM		Total
Revenues:
Customer	$	9,696	$	1,180	$	93	$	10,969
Intersegment	47		—		—		47
Related parties	45		—		—		45
Segment revenues	$	9,788	$	1,180	$	93	11,061
Elimination of intersegment revenues							(47		)
Sales and other operating revenues										$	912	$	1,663	$	379	$	2,954
Marketing revenues										775		64		—		839
Total revenues							$	11,014		$	1,687	$	1,727	$	379	$	3,793
Segment income	$	1,599	$	193	$	158	$	1,950		$	104	$	407	$	38	$	549
Income from equity method investments	187		—		173		360			1		77		—		78
Depreciation, depletion and amortization	1,541		141		3		1,685			314		200		49		563
Income tax provision	2,101		64		62		2,227			61		971		13		1,045
Capital expenditures	2,101		236		2		2,339			829		138		52		1,019

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,				Three Months Ended March 31,
(In millions)	2012		2011		2012		2011		2013		2012
Total revenues	$	4,034	$	3,649	$	11,556	$	11,014	$	3,870	$	3,793
Less: Sales to related parties	16		16		43		45
Sales and other operating revenues	$	4,018	$	3,633	$	11,513	$	10,969
Less: Marketing revenues									430		839
Sales and other operating revenues, including related party									$	3,440	$	2,954

~~MARATHON OIL CORPORATION~~

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

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

Three Months Ended Nine Months Ended
September 30, September 30,
(In millions) 2012 2011 2012 2011
Segment income $ 590
$ 477
$ 1,593
$ 1,950
Items not allocated to segments, net of income taxes:

Corporate and other unallocated items (158 ) (56 ) (267 ) (209 )
Unrealized gain on crude oil derivative instruments 29
—
29
—
     Gain (loss) on dispositions (11 ) (1 ) 72
23
     Impairments —
—
(167 ) (195 )
Loss on early extinguishment of debt —
—
—
(176 )
     Tax effect of subsidiary restructuring —
—
—
(122 )
Deferred income tax items —
(15 ) —
(65 )
Water abatement - Oil Sands —
—
—
(48 )
Income from continuing operations 450
405
1,260
1,158
Discontinued operations —
—
—
1,239
Net income $ 450
$ 405
$ 1,260
$ 2,397



	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)

9.7. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:


	Three Months Ended September 30,												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		$	12		$	1		$	1		$	14		$	12		$	1		$	1
Interest cost	16			17			4			4			15			16			3			4
Expected return on plan assets	(14		)	(16		)	—			—			(17		)	(16		)	—			—
Amortization:
– prior service cost (credit)	2			1			(2		)	(2		)	2			2			(2		)	(2		)
– actuarial loss	12			12			—			—			13			12			—			—
– net settlement loss^(a)	34			—			—			—
Net periodic benefit cost	$	62		$	26		$	3		$	3		$	27		$	26		$	2		$	3

Nine Months Ended September 30,

Pension Benefits Other Benefits
(In millions) 2012 2011 2012 2011
Service cost $ 37
$ 35
$ 3
$ 3
Interest cost 48
50
11
12
Expected return on plan assets (46 ) (49 ) —
—
Amortization:

– prior service cost (credit) 6
4
(5 ) (5 )
– actuarial loss 37
37
—
—
– net settlement loss^(a)
34
—
—
—
Net periodic benefit cost $ 116
$ 77
$ 9
$ 10


^(a)	Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan's total service and interest costs for the period. Such settlements occurred in our U.S. pension plans during the third quarter of 2012.

~~MARATHON OIL CORPORATION~~

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

During the third quarter of 2012, we recorded the effects of partial settlements of our U.S. pension plans. We remeasured the plans' assets and liabilities as of September 30, 2012 and, as a result, recognized settlement expense along with an increase of ~~$103 million~~ ~~in actuarial losses, net of settlement expenses. The net increase in actuarial losses is reported in other comprehensive income.~~

~~During the~~ first ~~nine~~three months of ~~2012~~2013, we made contributions of $~~162~~9 million to our funded pension plans. We expect to make additional contributions up to an estimated $255 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 $79 million and $124 million during the first ~~nine~~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”~~items in Note 8.6.

Our effective income tax ~~rate~~rates in the first ~~nine~~three months of ~~2012~~2013 ~~was~~and 2012 were 7273 percent and 69 percent. ~~This rate is~~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 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 ~~nine~~three months of 2013 and 2012, an estimated annual effective tax rate was calculated excluding Libya and applied to consolidated ordinary income excluding Libya and the tax provision applicable to Libyan ordinary income was recorded as a discrete item in the period. Excluding Libya, the effective tax rate would be 65 percent and 64 percent for the first ~~nine~~three months of ~~2012~~.

~~Our effective tax rate in the first~~ ~~nine~~2013 ~~months of~~ ~~2011~~ ~~was~~ ~~64 percent~~ ~~which is higher than the U.S. statutory tax rate of~~ ~~35 percent~~ ~~primarily due to earnings from foreign jurisdictions where the tax rates are in excess of the U.S. statutory rate~~ and the valuation allowance recorded against 2011 foreign tax credits. In addition, in the second quarter of 2011, we recorded a deferred tax charge related to an internal restructuring of our international subsidiaries.2012.

~~The following table summarizes the activity in unrecognized tax benefits:~~

Nine Months Ended September 30,
(In millions) 2012 2011
Beginning balance $ 157
$ 103
Additions based on tax positions related to the current year 2
3
Reductions based on tax positions related to the current year (1 ) (3 )
Additions for tax positions of prior years 97
71
Reductions for tax positions of prior years (66 ) (24 )
Settlements (12 ) (9 )
Ending balance $ 177
$ 141

9. Inventories

If Inventories are carried at the ~~unrecognized tax benefits as~~lower of ~~September 30, 2012~~ ~~were recognized,~~ ~~$114 million~~ ~~would affect our effective income tax rate. There were~~ ~~$143 million~~ ~~of uncertain tax positions as of~~ ~~September 30, 2012~~ ~~for which it is reasonably possible that the amount of unrecognized tax benefits would decrease during the next twelve months.~~cost or market value.



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

1310

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~11. Inventories~~

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

September 30, December 31,
(In millions) 2012 2011
Liquid hydrocarbons, natural gas and bitumen $ 72
$ 147
Supplies and sundry items 252
214
Total inventories, at cost $ 324
$ 361

~~12.~~10. Property, Plant and Equipment

September 30, December 31,
(In millions) 2012 2011
E&P
United States $ 22,167
$ 19,679
International 13,185
12,579
Total E&P 35,352
32,258
OSM 10,070
9,936
IG 38
37
Corporate 424
341
Total property, plant and equipment 45,884
42,572
Less accumulated depreciation, depletion and amortization (18,438 ) (17,248 )
Net property, plant and equipment $ 27,446
$ 25,324



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

In the first quarter of 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed. Since that time, average ~~net liquid hydrocarbon~~ sales volumes have increased to ~~49 thousand~~ ~~barrels per day (“mbbld”) in the third quarter of 2012 and~~ 37 ~~mbbld in the first nine months of 2012.~~near pre-conflict levels. We and our partners in the Waha concessions continue to assess the condition of our assets in Libya and uncertainty around sustained production and sales levels remains. As of March 31, 2013, our net property, plant and equipment investment in Libya was approximately $748 million.

Exploratory well costs capitalized greater than one year after completion of drilling ~~(“suspended”)~~ were $~~207~~220 million as of ~~September 30, 2012~~March 31, 2013. The net decrease in such costs from December 31, ~~2011~~2012 primarily related to ~~changes~~the conveyance of our interest in ~~three areas. Norway exploration costs of~~ ~~$55 million~~ ~~incurred between 2009 and 2011 have been suspended for greater than one year, pending commencement of~~ the ~~Boyla development which was submitted~~Marcellus natural gas shale play to the ~~Norwegian government for approval~~operator in ~~June and approved in October 2012. Drilling on the Shenandoah prospect in the Gulf of Mexico resumed in June 2012. Costs of~~ ~~$38 million~~ ~~related to Shenandoah are no longer suspended. The Innsbruck well was reentered in September 2012; therefore, costs of~~ ~~$60 million~~ ~~related to the prospect are no longer suspended.~~February 2013.

~~MARATHON OIL CORPORATION~~

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

~~13.~~11. Fair Value Measurements

Fair Values - Recurring

The following ~~table presents~~tables present assets and liabilities accounted for at fair value on a recurring basis as of ~~September 30,~~March 31, 2013 and December 31, 2012 by fair value hierarchy level.


	September 30, 2012										March 31, 2013
(In millions)	Level 1		Level 2		Level 3		Collateral		Total		Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	47	$	—	$	1	$	48	$	—	$	8	$	—	$	1	$	9
Interest rate	—		22		—		—		22		—		18		—		—		18
Foreign currency	—		20		—		—		20
Derivative instruments, assets	—		89		—		1		90		$	—	$	26	$	—	$	1	$	27
Derivative instruments, liabilities
Commodity	—		2		—		—		2		$	—	$	6	$	—	$	—	$	6
Foreign currency	—		1		—		—		1		—		20		—		—		20
Derivative instruments, liabilities	$	—	$	3	$	—	$	—	$	3	$	—	$	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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

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

~~As of~~ ~~December 31, 2011, balances related to interest rate swaps accounted for at fair value on a recurring basis were noncurrent assets of~~ ~~$5 million~~ ~~measured at fair value using actionable broker quotes which are Level 2 inputs. There were no other significant recurring fair value measurements as of~~ ~~December 31, 2011~~.

Fair Values - Nonrecurring

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


	Three Months Ended September 30,								Three Months Ended March 31,
	2012				2011				2013				2012
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	2	$	8	$	—	$	—	$	—	$	38	$	75	$	262

Nine Months Ended September 30,
2012 2011
(In millions) Fair Value Impairment Fair Value Impairment
Long-lived assets held for use $ 77
$ 271
$ 226
$ 282
Intangible assets $ —
$ —
$ —
$ 25

Our E&P segment’s Ozona development in the Gulf of Mexico began production in December 2011. During the first quarter of 2012, production rates declined significantly and have remained below initial expectations. Accordingly, our reserve engineers performed an evaluation of our future production as well as our reserves which concluded in early April 2012. This resulted in a

~~MARATHON OIL CORPORATION~~

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

~~2 million~~ ~~barrel of oil equivalent reduction in proved reserves and a~~ ~~$261 million~~ ~~impairment charge~~All long-lived assets held for use that were impaired in the first ~~quarter~~quarters of ~~2012.~~2013 and 2012 were held by our North America E&P segment. The fair ~~value~~values of ~~the Ozona development was determined~~each discussed below were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs. Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated ~~liquid hydrocarbon~~commodity prices ~~based on the Louisiana Light Sweet 12-month price range, as we think production will not be significant beyond twelve months,~~ adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

In ~~May 2011, significant water~~the first quarter of 2013, as a result of our decision to wind down operations in the Powder River Basin due to poor economics, an impairment of $15 million was recorded.

In early 2012, production ~~and reservoir pressure declines occurred at our E&P segment’s Droshky~~rates from the Ozona development in the Gulf of ~~Mexico. Consequently,~~ ~~3.4 million~~ ~~barrels~~Mexico declined significantly. Accordingly, our reserve engineers prepared evaluations of ~~oil equivalent of proved~~our future production as well as our reserves ~~were written off~~ and a ~~$273 million~~an impairment of ~~this long-lived asset to fair value~~$261 million was recorded in the ~~second~~first quarter of ~~2011. The~~2012. As the development produced towards abandonment pressures, further downward revisions of reserves were taken, resulting in an additional impairment recorded in the fourth quarter of 2012. Ozona production ceased in the first quarter of 2013 and an additional $~~226~~21 million ~~fair value of the Droshky development~~impairment was ~~determined using an income approach based upon internal estimates of future production levels, prices and discount rate, all Level 3 inputs.~~recorded.

In the second quarter of 2011, our outlook for U.S. natural gas prices indicated that it was unlikely that sufficient U.S. demand for LNG would materialize by 2021, which is when our rights lapse under arrangements at the Elba Island, Georgia regasification facility. Using an income approach based upon internal estimates of natural gas prices and future deliveries, which are Level 3 inputs, we determined that the contract had no remaining fair value and recorded a full impairment of this intangible asset held in our Integrated Gas segment.

Other impairments of long-lived assets held for use by our North America E&P segment in the ~~third quarter~~first quarters of 2013 and ~~first nine months of~~ 2012 ~~and 2011~~ were a result of reduced drilling expectations, ~~reduction~~reductions of estimated reserves or declining natural gas prices. ~~The fair values of those assets were measured using an income approach based upon internal estimates of future production levels, commodity prices and discount rate, which are Level 3 inputs.~~

Fair Values – ~~Reported~~Financial Instruments

Our current assets and liabilities include financial instruments, the most significant of which are ~~accounts~~ receivables, commercial paper and payables. We believe the carrying values of ~~these accounts~~our receivables, commercial paper and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table summarizes financial instruments, excluding ~~trade accounts~~ receivables, ~~and~~commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at ~~September 30, 2012~~March 31, 2013 and December 31, ~~2011~~:2012.


	September 30, 2012				December 31, 2011				March 31, 2013				December 31, 2012
	Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount		Value		Amount		Value		Amount
Financial assets
Other current assets	$	135	$	134	$	146	$	148
Other noncurrent assets	158		158		68		68		$	174	$	169	$	189	$	186
Total financial assets	293		292		214		216		174		169		189		186
Financial liabilities
Other current liabilities	13		13		—		—		13		13		13		13
Long-term debt, including current portion^(a)	5,639		4,653		5,479		4,753		7,347		6,494		7,610		6,642
Deferred credits and other liabilities	100		101		36		38		146		141		94		94
Total financial liabilities	$	5,752	$	4,767	$	5,515	$	4,791	$	7,506	$	6,648	$	7,717	$	6,749

^(a) Excludes capital leases.

Fair values of our ~~remaining~~ financial assets included in ~~other current assets and~~ other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.

Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, is used to measure the fair value of such debt. Because these quotes cannot be independently verified to an active

~~MARATHON OIL CORPORATION~~

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

market they are considered Level 3 inputs. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

~~14.~~

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

12. Derivatives

For information regarding the fair value measurement of derivative instruments, see Note ~~13.~~11. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. Netting is assessed by counterparty, and as of March 31, 2013 and December 31, 2012, there were no offsetting amounts. Positions by contract were all either assets or liabilities. The following ~~table presents~~tables present the gross fair values of ~~derivatives~~derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of ~~September 30, 2012~~March 31, 2013. and December 31, 2012.


	September 30, 2012							March 31, 2013
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	20	$	—	$	20	Other current assets
Interest rate	22		—		22		Other noncurrent assets	$	18	$	—	$	18	Other noncurrent assets
Total Designated Hedges	42		—		42			18		—		18

Not Designated as Hedges
Commodity	30		—		30		Other current assets	8		—		8		Other current assets
Commodity	20		—		20		Other noncurrent assets
Total Not Designated as Hedges	50		—		50			8		—		8
Total	$	92	$	—	$	92		$	26	$	—	$	26



	March 31, 2013
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	20	$	20	Other current liabilities
Total Designated Hedges	—		20		20

Not Designated as Hedges
Commodity	—		6		6		Other current liabilities
Total Not Designated as Hedges	—		6		6
Total	$	—	$	26	$	26

September 30, 2012
(In millions) Asset Liability Net Liability Balance Sheet Location
Fair Value Hedges
     Foreign currency $ —
$ 1
$ 1
Other current liabilities
Total Designated Hedges —
1
1

Not Designated as Hedges
     Commodity —
5
5
Other current liabilities
Total Not Designated as Hedges —
5
5

     Total $ —
$ 6
$ 6

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



	December 31, 2012
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	18	$	—	$	18	Other current assets
Interest rate	21		—		21		Other noncurrent assets
Total Designated Hedges	39		—		39

Not Designated as Hedges
Commodity	52		—		52		Other current assets
Total Not Designated as Hedges	52		—		52
Total	$	91	$	—	$	91

Derivatives Designated as Fair Value Hedges

As of ~~September 30,~~March 31, 2013 and December 31, 2012,, we had multiple interest rate swap agreements with a total notional amount of $600 million with a maturity date of October 1, 2017 at a weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate of ~~4.71~~4.69 percent and 4.70 percent.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

As of ~~September 30,~~March 31, 2013 and December 31, 2012, our foreign currency forwards had an aggregate notional amount of ~~3,939~~3,571 million and 3,043 million Norwegian Kroner at a weighted average forward rate of ~~5.911~~5.678 and 5.780. These forwards hedge our current Norwegian tax liability and have settlement dates through ~~February 2013.~~

~~In connection with the debt retired in February and March 2011 discussed in Note 15, we settled interest rate swaps with a notional amount of~~ ~~$1,450 million~~August 2013.

~~MARATHON OIL CORPORATION~~

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

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


		Gain (Loss)
		Three Months Ended						Nine Months Ended							Gain (Loss)
		September 30,						September 30,							Three Months Ended March 31,
(In millions)	Income Statement Location	2012			2011			2012			2011			Income Statement Location	2013			2012
Derivative
Interest rate	Net interest and other	$	6		$	26		$	17		$	25		Net interest and other	$	(3	)	$	(1	)
Interest rate	Loss on early extinguishment of debt	—			—			—			29
Foreign currency	Provision for income taxes	$	22		$	—		$	(18	)	$	—		Provision for income taxes	$	(25	)	$	(8	)
Hedged Item
Long-term debt	Net interest and other	$	(6	)	$	(26	)	$	(17	)	$	(25	)	Net interest and other	$	3		$	1
Long-term debt	Loss on early extinguishment of debt	—			—			—			(29		)
Accrued taxes	Provision for income taxes	$	(22	)	$	—		$	18		$	—		Provision for income taxes	$	25		$	8

Derivatives not Designated as Hedges

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

Term Bbls per Day Weighted Average Price per Bbl Benchmark
Swaps
October 2012 - December 2013 20,000 $96.29 West Texas Intermediate
October 2012 - December 2013 25,000 $109.19 Brent
Option Collars
October 2012 - December 2013 15,000 $90.00 floor / $101.17 ceiling West Texas Intermediate
October 2012 - December 2013 15,000 $100.00 floor / $116.30 ceiling Brent



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

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

Gain (Loss)
Three Months Ended Nine Months Ended
September 30, September 30,
(In millions) Income Statement Location 2012 2011 2012 2011
Commodity Sales and other operating revenues $ 45
$ 2
$ 46
$ 3

~~15. Debt~~

On ~~October 29, 2012, we issued~~ ~~$1 billion~~ ~~aggregate principal amount of senior notes bearing interest at~~ ~~0.9 percent~~ ~~with a maturity date of~~ ~~November 1, 2015~~ ~~and~~ ~~$1 billion~~ ~~aggregate principal amount of senior notes bearing interest at~~ ~~2.8 percent~~ ~~with a maturity date of~~ ~~November 1, 2022. Interest on the senior notes is payable semi-annually beginning May 1, 2013. The proceeds are being used to pay off commercial paper and for general corporate purposes.~~

~~At September 30, 2012, we had no borrowings against our revolving credit facility, described below, and~~ ~~$1,839 million~~ ~~in commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.~~

~~In April 2012, we terminated our~~ ~~$3.0 billion~~ ~~five-year revolving credit facility and replaced it with a new~~ ~~$2.5 billion~~ ~~unsecured five-year revolving credit facility (the “Credit Facility”). The Credit Facility matures in~~ ~~April 2017~~ ~~but allows us to request two one-year extensions. It contains an option to increase the commitment amount by up to an additional~~ ~~$1.0 billion, subject to the consent of any increasing lenders, and includes sub-facilities for swing-line loans and letters of credit up to an aggregate amount of~~ ~~$100 million~~ ~~and~~ ~~$500 million, respectively. Fees on the unused commitment of each lender range from~~ 10 ~~basis points to~~ 25 ~~basis points depending on our credit ratings. Borrowings under the Credit Facility bear interest, at our option,~~

1815

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~at either (a) an adjusted LIBOR rate plus a margin ranging from~~ ~~87.5~~ ~~basis points to~~ ~~162.5~~ ~~basis points per year depending on our credit ratings or (b) the Base Rate plus a margin ranging from~~ ~~0.0~~ ~~basis points to~~ ~~62.5~~ basis points depending on our credit ratings. Base Rate is defined as a per annum rate equal to the greatest of (a) the prime rate, (b) the federal funds rate plus one-half of one percent and (c) LIBOR for a one-month interest period plus ~~1 percent~~.

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

~~In the second quarter of 2012, we retired the remaining~~ ~~$23 million~~ ~~principal amount of our~~ ~~5.375 percent~~ ~~revenue bonds due December 2013. No gain or loss was recorded on this early extinguishment of debt. During the first quarter of 2012,~~ ~~$53 million~~ ~~principal amount of debt carrying a~~ ~~9.375 percent~~ ~~interest rate was repaid at maturity.~~

~~During the first quarter of 2011, we retired~~ ~~$2,498 million~~ ~~aggregate principal amount of debt at a weighted average price equal to~~ ~~112 percent~~ ~~of face value. A~~ ~~$279 million~~ loss on early extinguishment of debt was recognized in the first quarter of 2011. The loss includes related deferred financing and premium costs partially offset by the gain on settled interest rate swaps.

~~16.~~13. Incentive Based Compensation

Stock ~~Option~~option and ~~Restricted Stock Awards~~restricted stock awards

The following table presents a summary of stock option ~~award~~ and restricted stock award activity for the first ~~nine~~ ~~months~~quarter of ~~2012~~2013:


	Stock Options					Restricted Stock				Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value		Number of Shares			Weighted Average Exercise Price		Awards		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2011	21,370,715				$24.41	3,703,978			$25.88
Outstanding at December 31, 2012										19,536,965				$26.19	4,177,884			$29.02
Granted	1,858,872		^(a)		$33.52	2,169,744			$31.61	1,002,400		^(a)		$32.86	137,722			$33.04
Options Exercised/Stock Vested	(1,256,318	)			$18.25	(1,142,195	)		$25.18	(839,273	)			$21.33	(493,840	)		$30.66
Cancelled	(509,748	)			$28.29	(287,278	)		$27.96	(215,262	)			$35.17	(78,778	)		$28.98
Outstanding at September 30, 2012	21,463,521				$25.47	4,444,249			$28.72
Outstanding at March 31, 2013										19,484,830				$26.65	3,742,988			$28.96

^(a) The weighted average grant date fair value of stock option awards granted was $~~9.94~~10.50 per share.

Performance ~~Unit Awards~~unit awards

During the first quarter of ~~2012,~~2013, we granted ~~13 million~~353,600 performance units to ~~executive officers. These units have~~certain officers that provide a cash payout upon the achievement of certain performance goals at the end of a 36-month performance period. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors. At the grant date, each unit represents the value of one share of our common stock, while payout after completion of the performance period will be based on the value of anywhere from zero to two times the number of units granted. Dividend equivalents accrue during the performance period and are paid in cash at the end of the performance period based on the number of shares that would represent the value of the units. The fair value of these performance units is re-measured on a quarterly basis using the Monte Carlo simulation method. These performance units are accounted for as liability awards because they are to be settled in cash at the end of the performance period and their fair value is expensed over the performance period.

~~17. Supplemental Cash Flow Information~~14. Reclassifications Out of Accumulated Other Comprehensive Loss

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

Nine Months Ended September 30,
(In millions) 2012 2011
Net cash provided from operating activities:
Interest paid (net of amounts capitalized) $ 164
$ 197
Income taxes paid to taxing authorities 3,457
2,183
Commercial paper, net:

Commercial paper - issuances $ 10,420
$ —
- repayments (8,581 ) —
Noncash investing activities:

Debt payments made by United States Steel $ 19
$ 18
Liabilities assumed in acquisition 85
—
Change in capital expenditure accrual 170
(61 )



	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

1916

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~18.~~15. Supplemental Cash Flow Information



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

16. Commitments and Contingencies

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

Litigation – In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas, alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. In April 2013, we filed a counterclaim against Noble ~~is seeking~~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 ~~unspecified amount for damages.~~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.

~~Guarantees~~– After our 2009 sale of the subsidiary holding our interest in the Corrib natural gas development offshore Ireland, one guarantee of that entity's performance related to asset retirement obligations remains issued to certain Irish government entities until the Irish government and the current Corrib partners agree to release our guarantee and accept the purchaser's guarantee to replace it. The maximum potential undiscounted payments related to asset retirement obligations under this guarantee as of ~~September 30, 2012~~ ~~are~~ ~~$40 million~~.

Contractual commitments – At ~~September 30, 2012~~ ~~and~~ ~~December~~March 31, ~~2011~~2013, Marathon’s contract commitments to acquire property, plant and equipment were $~~974 million~~ ~~and~~ ~~$664~~1,209 million.

2017

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

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

North America Exploration and Production (“("E~~&P”~~&P") ~~which~~– explores for, produces and markets liquid hydrocarbons and natural gas ~~on a worldwide basis.~~in North America;

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

Oil Sands Mining ~~(“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.

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

Certain sections of this Quarterly Report on Form 10-Q, including Management’s Discussion and Analysis of Financial Condition and Results of Operations ~~include~~contain forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our ~~2011~~2012 Annual Report on Form 10-K. We assume no duty to update these statements as to any future date.

Key Operating and Financial Activities

In the ~~third~~first quarter of ~~2012,~~2013, notable items were:

~~Net liquid hydrocarbon and natural gas~~

Total net sales volumes ~~of 452~~averaged 523 thousand barrels of oil equivalent per day (“mboed”), ~~of which 65 percent was liquid hydrocarbons~~

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

~~Eagle Ford shale average net sales volumes of 40 mboed, an increase of 90 percent from the second quarter of 2012~~

~~Production from Libya increased over the second quarter of 2012, with average net sales of 53 mboed~~

~~Bakken shale average net sales volumes of 30 mboed,~~ a 8722 percent increase over the same quarter of last year

~~Closed the acquisition of Paloma Partners II, LLC~~

~~Assumed operatorship~~Liquid hydrocarbon and synthetic crude oil sales volumes accounted for 93 percent of the ~~Vilje field offshore Norway~~increase

~~Some significant fourth quarter activities through~~ ~~November 7, 2012~~ ~~include:~~

~~Closed acquisition of an additional 4,300 net acres in the core of the~~ Eagle Ford shale averaged net sales volumes of 72 mboed, a four-fold increase

~~Signed agreement~~Bakken shale averaged net sales volumes of 37 mboed, a 46 percent increase

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

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

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

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

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

~~Reentered Gabon by acquiring an interest in an exploration license~~

~~Acquired interests in two onshore exploration blocks in Kenya~~

~~Farmed out 35 percent working interests~~Successful appraisal well on non-operated Shenandoah prospect in the ~~Harir and Safen~~Gulf of Mexico announced

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

Apparent high bidder on two blocks in the ~~Kurdistan Region~~March 2013 Gulf of ~~Iraq~~Mexico lease sale

~~Issued $2 billion~~Unproved property impairments of ~~senior notes~~approximately $340 million recorded related to expiring Eagle Ford leases and leases we do not intend to drill

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

2118

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

Decision made to conclude exploration activities in Poland

Agreement reached to sell interests in DJ Basin

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

Overview and Outlook

~~Exploration and Production~~North America E&P

Production

Net liquid hydrocarbon and natural gas sales volumes averaged ~~452~~198 mboed during the ~~third~~first quarter of 2013 ~~quarter~~ and ~~414 mboed in the first~~ ~~nine~~147 ~~months of~~ ~~2012~~ ~~compared to 349 mboed and 362~~ mboed in the same ~~periods~~period of ~~2011.~~2012, a 35 percent increase. Net liquid hydrocarbon sales volumes increased, ~~in the U.S. for both the~~ ~~third~~ ~~quarter and first~~ ~~nine~~ ~~months of~~ ~~2012~~,primarily reflecting the impact of ~~production from the Eagle Ford shale assets acquired in the fourth quarter of 2011 and~~ our ongoing development programs in the Eagle Ford ~~Bakken~~ and ~~Anadarko Woodford~~Bakken shale resource ~~plays. The resumption~~plays, while net natural gas sales volumes decreased slightly due to the sale of our Alaska assets in January 2013. Excluding the sales volume related to Alaska in both periods, our average net liquid hydrocarbon and natural gas sales volumes increased 47 percent.

In 2013, production growth continued in the Eagle Ford shale play. Average net sales volumes were 72 mboed in the first quarter of 2013 compared to 14 mboed in the same period of 2012. Approximately 64 percent of first quarter 2013 production was crude oil and condensate, 17 percent was natural gas liquids ("NGLs") and 19 percent was natural gas. During the first quarter of 2013, we reached total depth on 76 gross operated wells and brought 68 gross operated wells to sales. We continue to advance our drilling performance, reducing the average time to drill a well from ~~Libya~~28 days in the first quarter of 2012 after production had ceased there in February of 2011 was the most significant increase in international sales volumes. In addition, net liquid hydrocarbon sales volumes from the U.K. were lower in the 2012 periods than in the same periods of 2011 due to turnarounds in the third quarter and the timing of liftings.

~~In 2012, we continued to ramp up operations in the core of the Eagle Ford shale play in Texas. Average net sales volumes from the Eagle Ford shale were 40 mboed and 25 mboed in the~~ ~~third~~ ~~quarter and first~~ ~~nine~~ ~~months of~~ ~~2012. As announced in August, we have reduced our rig count~~ to 18 ~~operated rigs while maintaining four dedicated hydraulic fracturing crews and two more on a spot basis. During the~~ ~~third~~ ~~quarter of~~ ~~2012, we drilled 78 gross wells and brought 73 gross wells to sales for a total of 180 gross wells drilled~~days in the first ~~nine months~~quarter of ~~2012. Our average time~~2013. We expect these drilling times to ~~drill a well in the Eagle Ford shale has decreased to approximately 24 days; therefore, we now expect to drill 250 to 260 gross Eagle Ford wells~~continue dropping during ~~2012, an increase of approximately 20 wells~~2013 as additional efficiencies are gained from previous estimates. In addition to the improvements in the speed and efficiency in drilling and completions, we continue to optimize well spacing which could significantly increase drillable locations and recoverable resources. pad drilling.

We have been performing spacing pilot programs in the Eagle Ford shale which will complete early in 2013 so that we will have applicable technical results by mid-year. To complement drilling and completion activity in the Eagle Ford shale, we continue to build infrastructure to support production growth across the Eagle Ford operating area. ~~We are now able to~~Approximately 148 miles of gathering lines were installed in the first quarter of 2013, while five new central gathering and treating facilities were commissioned, with two additional facilities in various stages of planning or construction. As of March 31, 2013, we transport approximately 6065 percent of our crude oil and condensate by pipeline, with additional contract negotiations and facility designs under way that are expected to push that figure to 75 percent by the end of May. The ability to transport more barrels by pipeline enables us to reduce costs, improve reliability and lessen our environmental footprint.

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

Average net sales volumes from the Bakken shale were ~~30 mboed and 27~~37 mboed in the ~~third~~first quarter ~~and first~~ ~~nine~~ ~~months~~ of ~~2012~~2013 compared to ~~17 mboed and 15~~25 mboed in the same ~~periods~~period of ~~2011.~~2012. Our Bakken ~~shale liquid hydrocarbon volumes averaged~~production averages approximately 90 percent crude oil, 5 percent ~~natural gas liquids~~NGLs and 5 percent natural ~~gas in the first~~ ~~nine~~ ~~months of~~ ~~2012~~.gas. During the ~~third~~first quarter ~~and first~~ ~~nine~~ ~~months~~ of ~~2012~~2013, we ~~drilled~~reached total depth on 18 gross operated wells and brought 22 gross operated wells to sales. Our average time to drill a well was 25 ~~gross and 72 gross wells with seven rigs, with a total of 30 gross and 77 gross wells brought to sales in the~~ ~~third~~ ~~quarter and the first~~ ~~nine~~ ~~months of~~ ~~2012. By the end of October 2012, we had reduced our operated rig count in the Bakken shale to five. We continue to focus on downspacing and development in the Three Forks area.~~days.

In the ~~Anadarko Woodford shale,~~Oklahoma Resource Basins, net sales volumes averaged 1013 mboed ~~and 7 mboed during~~in the ~~third~~first quarter ~~and first~~ ~~nine~~ ~~months~~ of ~~2012~~2013 compared to ~~2 mboed and 2~~5 mboed in the same ~~periods~~period of ~~2011.~~2012. All net sales volumes are from the Anadarko Woodford shale. During the ~~third~~first quarter of ~~2012~~2013, ~~eight~~four gross operated wells were brought to ~~sales, with 14 gross~~sales. We anticipate drilling two wells ~~brought to sales~~each in the ~~first~~ ~~nine~~ ~~months of~~ ~~2012. As announced in August, in response to the continued decline in natural gas liquids prices~~Mississippi Lime and low natural gas prices, we have reduced our rig count in the Anadarko Woodford play from six to two. Other areas of potential growth exist in Oklahoma and we are currently evaluating opportunities on legacy assets where the acreage is held by production. FutureGranite Wash formations during 2013.

Exploration

Exploration activity ~~in these Oklahoma resource basins will be dependent upon the recovery of natural gas and natural gas liquids prices.~~

~~In the first quarter 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed and has increased during 2012 so that during the~~ ~~third~~ quarter and first nine months of 2012, net sales volumes averaged 53 mboed and 51 mboed. We and our partners in the Waha concessions continue to assess the condition of our assets in Libya and uncertainty around sustained production and sales levels remains.

In June 2012, we submitted a plan for the development and operation of the Boyla field (PL 340) in the North Sea to the Norwegian Ministry of Petroleum and Energy, which was approved in October 2012. The Boyla field is located approximately 17 miles south of our operated Alvheim field. We hold a 65 percent working interest in the field. First production from Boyla is expected in the fourth quarter of 2014.

In the second quarter of 2012, we completed a four-day turnaround in Norway that was originally scheduled for 14 days in the third quarter. During the third quarter of 2012, we became operator of the Vilje field offshore Norway in which we own a 47 percent interest.

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

~~Our Ozona development~~continues in the Gulf of ~~Mexico began production in December 2011. During the~~Mexico. The first ~~quarter of 2012, production rates declined significantly and have remained below initial expectations. Accordingly, our reserve engineers performed~~

an evaluation of our future production as well as our reserves which concluded in early April 2012. This resulted in a 2 million barrels of oil equivalent reduction in proved reserves and a $261 million impairment charge in the first quarter of 2012.

~~Exploration~~

~~The~~ appraisal well on the Shenandoah prospect located on Walker Ridge Block 51, in ~~the Gulf of Mexico, in~~ which we have a 10 percent outside-operated working interest, ~~is currently drilling. In~~reached total depth in the ~~third~~first quarter of ~~2012, we resumed drilling the exploration well on the Gulf of Mexico Innsbruck prospect on Mississippi Canyon Block 993~~2013. We are currently participating in which we hold a 45 percent operated working interest. Through September 30, 2012, our net costs related to the well were $71 million. The well has drilled through multiple horizons with no commercial hydrocarbons found as of November 6, 2012. We anticipate reaching total depth within the next few days at a total net cost, including asset retirement obligations and leasehold costs, of approximately $100 million.

~~In the second quarter of 2012,~~ a Gunflint prospect appraisal well ~~confirmed expected reservoir properties and continuity, establishing the commercial viability of the field. The Gunflint discovery is~~ located on Mississippi Canyon Block 948 and we have a 15 percent outside-operated working interest in the prospect. During the second quarter of 2012, the well costs and related unproved property costs related to the Kilchurn well were charged to exploration expenses.

~~We continue exploratory drilling in Poland~~992 where we hold ~~a 51~~an 18 percent non-operated working ~~interest in 10 operated concessions and a~~interest.

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

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

International E&P

Production

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

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

The production decline in the Alvheim area offshore Norway continues to be less severe than expected. These better-than-expected results have ~~drilled 4 exploratory wells~~been achieved through continued strong operational performance that delivered availability of 97 percent in the first quarter of 2013, reservoir and ~~are currently~~well performance at the upper end of expectations primarily due to a delay in anticipated water breakthrough at the Volund field and sustained contributions from the recently completed development drilling a fifth well. We have collected extensive data, including well logs and core samples, which are being evaluated. We plan to begin a sixth well by year end 2012 which should reach total depth in 2013. program.

Exploration

In the Kurdistan Region of Iraq, we began drilling our first operated exploration well on the Harir block in July 2012 and plan to drill an operated exploration well on the Safen block in the first quarter of 2013. After the farm out discussed below, we havehold 45 percent operated working interests in both the Harir and Safen blocks. OnCurrent exploratory drilling includes the ~~non-operated Atrush block, we participated~~Mirawa well which began in ~~an appraisal~~March 2013 on the Harir Block and the Safen well ~~during~~which commenced drilling in April 2013 on the Safen Block. Both of these wells are expected to reach projected total depth in the third quarter of 2013 with testing programs to follow on each well.

Additionally, following the successful appraisal program on the non-operated Atrush Block, a declaration of commerciality was filed with the government and a plan of development is anticipated to be filed in May 2013. Drilling of the Atrush-3 appraisal well commenced in March. On the non-operated Sarsang block, the Mangesh and Gara exploration wells began drilling in the second half of 2012. ~~Additionally, we participated in a non-operated well that commenced~~Both wells are currently drilling and are expected to reach total depth during the second quarter of 2013, with testing programs to follow on each well. Also on the Sarsang block, the East Swara Tika well is expected to begin drilling late in ~~September 2012.~~the second quarter or early in the third quarter of 2013. We hold a 2015 percent working interest in the Atrush block and a 25 percent working interest in the Sarsang block.

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

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

Offshore Norway, the Darwin (formerly Veslemoy) exploration well was drilled in the first quarter of ~~2012,~~2013 on PL 531 in which we hold a 10 percent non-operated fully-carried working interest. Gas shows were recorded in the Paleocene objective section, although no hydrocarbons were found in the Cretaceous section and the well has been plugged and abandoned. We expect drilling to commence in the third quarter of 2013 on the ~~Birchwood oil sands lease located~~Sverdrup exploration well on PL 330, in ~~Alberta, Canada,~~which we ~~conducted~~hold a ~~seismic survey~~30 percent non-operated working interest.

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

Oil Sands Mining

Our Oil Sands Mining operations consist of a proposed 12 thousand barrel per day (“mbbld”) steam assisted gravity drainage ("SAGD") project at Birchwood. Pending regulatory approval, project sanction is expected in 2014, with first oil projected in 2017. We have a 10020 percent non-operated working interest in ~~Birchwood.~~the Athabasca Oil Sands Project (“AOSP”). Our net synthetic crude oil sales were 51 mbbld in the first quarter of 2013 compared to 44 mbbld in the same period of 2012. Both mines and the upgrader experienced significantly improved reliability during the first quarter of 2013. Primarily because of reliability improvements, combined production from the Jack Pine and Muskeg River mines set a record bitumen production rate in the first quarter of 2013. In addition, upgrader availability was 100 percent for the entire first quarter of 2013, allowing the facility to maximize production of lighter synthetic crude oils, which improved realizations and profit margins.

Acquisitions and Dispositions

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

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

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

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

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

We ~~continually evaluate ways~~continue to progress the potential sale of assets in an ongoing effort to optimize our portfolio for profitable growth, ~~through acquisitions and dispositions,~~ with a previously stated goal of divesting between $1.5 billion and $3 billion over the period of 2011 through 2013. To date, we have ~~entered into agreements for~~agreed upon or completed approximately ~~$1.1~~$1.3 billion in ~~divestitures, of which more than $700 million have been completed. Included in the $1.1 billion noted above is the pending sale of our Alaska assets which is discussed below.~~

On November 1, 2012, we closed the acquisition of an additional 4,300 net acres in the core of the Eagle Ford shale at a transaction cost of approximately $232 million before closing adjustments. This acquisition increased our average working interest by 5 to 7 percent in four core areas of mutual interest, included wells producing 3 net mboed at closing, and added 40 net drilling locations to our inventory. The closing of this transaction combined with the acquisition of Paloma Partners II, LLC ("Paloma acquisition"), brings our acquisitions thus far in 2012 in the core of the play to almost 25,000 additional net acres at an approximate cost of $1 billion. The Paloma acquisition closed in August 2012 as discussed below. We now have approximately 230,000 net acres in the core of the Eagle Ford shale. The unproved property costs related to an additional 100,000 non-core net acres were impaired in the third quarter of 2012 as discussed below in Results of Operations.

In October 2012, we entered into an agreement to acquire a 20 percent non-operated working interest in the South Omo concession onshore Ethiopia with an effective date of August 17, 2012. An exploration well is anticipated to commence drilling in South Omo during the fourth quarter of 2012. Cash consideration for this transaction will be $40 million, before closing adjustments, with an additional payment of $10 million due upon declaration of a commercial discovery. ~~We expect to close the transaction, subject to necessary Ethiopian government approvals, before the end of 2012.~~

We acquired approximately 20,000 net acres in the core of the Eagle Ford shale during the first nine months of 2012. The largest transaction was the acquisition of Paloma Partners II, LLC, which closed August 1, 2012 for cash consideration of $768 million. In addition to the over 17,100 net acres acquired, at closing 17 gross operated and 9 gross non-operated wells were producing an average of 9 net mboed, of which 70 percent was liquid hydrocarbons. Smaller transactions closed during the second quarter of 2012. See Note 6 to the consolidated financial statements for further details of the Paloma acquisition.

~~In the third quarter of 2012, we sold approximately 5,800 net undeveloped acres located outside the core of the Eagle Ford shale for proceeds of $9 million, recording a loss of $18 million.~~

In July 2012, we entered into an agreement to acquire outside-operated positions in two onshore exploration blocks in northwest Kenya. Upon closing the $35 million transaction in October 2012, we now hold a 50 percent working interest in Block 9, where an exploration well is currently planned in mid-2013, and a 15 percent working interest in Block 12A.

Also in July 2012, we agreed to farm out interests in the Harir and Safen blocks in the Kurdistan Region of Iraq. The transaction closed in October 2012 and we received cash proceeds of $140 million, so that we now have a 45 percent working interest and carry the KRG for an additional 11 percent in each of the two blocks.

In June 2012, we entered an agreement to acquire a 21 percent outside-operated working interest in the Diaba License G4-223 and its related permit onshore Gabon. The transaction closed in October 2012. The start of exploration drilling is expected in the first quarter of 2013.

During June 2012, we signed a new production sharing contract with the government of Equatorial Guinea for the exploration of Block A-12 offshore Bioko Island, located immediately west of our operated Alba Field. We have an 80 percent operated working interest in this block. The contract was ratified by the government in the third quarter of 2012. We also acquired an additional interest in Block D, bringing our working interest to 80 percent.

In May 2012, we executed agreements to relinquish our E&P segment’s operatorship of and participating interests in the Bone Bay and Kumawa exploration licenses in Indonesia. As a result, we accrued and reported a $36 million loss on disposal of assets in the second quarter of 2012. Government ratification of the agreements was received during the third quarter of 2012, which released us from our obligations and further commitments related to these licenses, and we paid the amount accrued.

In April 2012, we entered agreements to sell our Alaska assets. One transaction closed in the second quarter of 2012 with proceeds and a net gain of $7 million. The remaining transaction, with a value of $375 million before closing adjustments, is currently under review by the Federal Trade Commission and the Alaska Attorney General's office, which could impact the closing of this transaction.

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

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

~~Oil Sands Mining~~

Our OSM operations consist of a 20 percent non-operated working interest in the Athabasca Oil Sands Project (“AOSP”). As announced in October 2012, we have engaged in discussions with respect to a potential sale of a portiondevelopment of our ~~20 percent interest. Given the uncertainty of such a transaction, potential proceeds have not been included in our previously stated goal of divesting between $1.5 billion~~in-situ assets is dependent on obtaining regulatory approval and ~~$3 billion between 2011 and 2013.~~

~~Our net synthetic crude oil sales were 53 mbbld and 47 mbbld in the~~ ~~third~~ ~~quarter and first~~ ~~nine~~ ~~months of~~ ~~2012~~ ~~compared to 50 mbbld and 43 mbbld in the same periods of~~ ~~2011. The upgrader expansion was completed and commenced operations in the third quarter of 2011 and subsequent periods’ sales volumes have increased as a result. With production capacity at the AOSP~~

~~now at 255,000 gross barrels per day, the focus will be on improving operating efficiencies and adding capacity through debottlenecking.~~

The Energy and Resources Conservation Board, Alberta’s primary energy regulator, conditionally approved the AOSP’s Quest Carbon Capture and Storage (“Quest CCS”) project in July 2012. The AOSP partners approved Quest CCS in the third quarter of 2012.

The above discussion contains forward-looking statements with regard to discussions with respect to a potential sale of a portion of our 20 percent interest in the AOSP. The potential sale of a portion of our interest in the AOSP is subject to successful negotiations and execution of definitive agreements.future development plans. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

~~Integrated Gas~~

LNG and methanol sales from Equatorial Guinea are conducted through equity method investees that purchase dry gas from our E&P assets in Equatorial Guinea. Our share of LNG sales totaled 7,065 metric tonnes per day (“mtd”) for the ~~third~~ ~~quarter and 6,277 mtd for the first~~ ~~nine~~ ~~months of~~ ~~2012~~ ~~compared to 6,935 mtd and 7,121 mtd in the same periods of~~ ~~2011~~. For the first nine months, LNG sales volumes are below the prior year due to a turnaround in the second quarter of 2012 at the facility in Equatorial Guinea, but primarily because the first nine months of 2011 also included LNG sales from Alaska, which ceased when our interest in that production facility was sold in the third quarter of 2011.

Market Conditions

~~Exploration and Production~~

Prevailing prices for the various qualities of crude oil and natural gas that we produce significantly impact our revenues and cash flows. ~~Prices~~Worldwide prices have been volatile in recent years. The following table lists benchmark crude oil and natural gas price averages relative to our North America E&P and International E&P segments in the ~~third~~first ~~quarter and first~~ ~~nine~~ ~~months~~quarters of ~~2012~~2013 ~~compared to the same periods in~~and ~~2011~~2012.

Three Months Ended September 30, Nine Months Ended September 30,
Benchmark 2012 2011 2012 2011
WTI crude oil (Dollars per barrel)
$92.20 $89.54 $96.16 $95.47
Brent (Europe) crude oil (Dollars per barrel)
$109.61 $113.46 $112.17 $111.93
Henry Hub natural gas (Dollars per million

British thermal units ("mmbtu"))^(a)
$2.81 $4.19 $2.59 $4.16



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


^(a)	Settlement date average.

North America E&P

~~Average~~Liquid hydrocarbons – The quality, location and composition of our liquid hydrocarbon production mix will cause our U.S. liquid hydrocarbon realizations to differ from the WTI benchmark. Light sweet crude contains less sulfur and tends to be lighter than sour crude oil ~~benchmark prices increased 3 percent in~~so that refining it is less costly and produces higher value products; therefore, light sweet crude is considered of higher quality and typically sells at a price that approximates WTI or at a premium to WTI. The percentage of our North America E&P crude and condensate production that is sweet crude has been increasing as onshore production from the ~~third~~ ~~quarter of~~ ~~2012~~ ~~compared to the same quarter of~~ ~~2011. Our international crude oil production is relatively sweet~~Eagle Ford and a majority is sold in relation to the Brent crude oil benchmark, which was 3 percent lower in the third quarter of 2012 than the same quarter of 2011. Both crude benchmarks were relatively flat on average when comparing the nine-month periods of 2012Bakken shale plays increases and ~~2011.~~

~~Our domestic crude oil production was about 35 percent sour in the~~ ~~third~~ ~~quarter and 42 percent sour in the first~~ ~~nine~~ ~~months of~~ ~~2012~~ ~~compared to 64 percent and 62 percent in the same periods of~~ ~~2011. Reduced~~ production from the Gulf of Mexico declines. In the first quarter of 2013, the percentage of our U.S. crude oil and ~~increased onshore~~condensate production that was sweet averaged 74 percent compared to 53 percent in the same period of 2012. In recent years, crude oil sold along the United States Gulf Coast, such as that from the ~~Bakken and~~ Eagle Ford shale, ~~plays contributed~~has been priced at a premium to WTI because the ~~lower sour crude percentage in 2012. Sour crude oil contains more sulfur than light sweet WTI. Sour crude oil also tends to be heavier than and sells~~Louisiana Light Sweet benchmark has been tracking Brent, while production from inland areas farther from large refineries has been at a discount to ~~light sweet crude oil because~~WTI. The proportion of ~~its higher refining costs and lower refined product values.~~our liquid hydrocarbon sales that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays. NGLs were 14 percent of our North America E&P liquid hydrocarbon sales volumes in the first quarter of 2013 compared to 8 percent in the same period of 2012.

Natural gas –A significant portion of our natural gas production in the lower 48 states of the ~~U.S.~~United States is sold at bid-week prices, or first-of-month indices relative to our specific producing areas. Average Henry Hub settlement prices for natural gas were ~~lower~~22 percent higher for the ~~third~~first quarter ~~and first~~ ~~nine~~ ~~months~~ of ~~2012~~2013 compared to the same ~~periods~~period of the prior year. ~~A decline~~

International E&P

Liquid hydrocarbons – Our international crude oil production is relatively sweet and is generally sold in ~~average settlement date Henry Hub natural gas prices began~~relation to the Brent crude benchmark, which was 5 percent lower in ~~September 2011 and continued into 2012. Although prices have stabilized recently, they have not increased appreciably.~~ the first quarter of 2013 than the same quarter of 2012.

Natural gas –Our ~~other~~ major international natural gas-producing regions are Europe and Equatorial Guinea. Natural gas prices in Europe have been considerably higher than in the U.S. in recent ~~periods.~~years. In the case of Equatorial Guinea, our natural gas sales are subject to term contracts, making realized prices in these areas less volatile. The natural gas sales from Equatorial Guinea are at fixed prices; therefore, our reported average natural gas realized prices may not fully track market price movements.

Oil Sands Mining

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

The operating cost structure of the ~~oil sands mining~~Oil Sands Mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production ~~downtime, making per unit~~downtime. Per-unit costs are sensitive to production ~~rate.~~rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company ~~(“AECO”~~("AECO") natural gas sales index and crude oil prices, respectively.

The table below shows benchmark prices that impacted both our revenues and variable costs for the ~~third~~first ~~quarter and first~~ ~~nine~~ ~~months~~quarters of ~~2012~~2013 and ~~2011~~2012:


	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended March 31,
Benchmark	2012	2011	2012	2011	2013		2012
WTI crude oil (Dollars per barrel)	$92.20	$89.54	$96.16	$95.47		$94.36		$103.03
Western Canadian Select (Dollars per barrel)^(a)	$70.49	$72.14	$74.21	$76.10
WCS crude oil (Dollars per barrel)^(a)						$62.41		$81.51
AECO natural gas sales index (Dollars per mmbtu)^(b)	$2.27	$3.70	$2.03	$3.86		$3.16		$2.18


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


^(b)	Monthly average AECO day ahead index.

~~Integrated Gas~~

~~We have a 60 percent ownership in a production facility in Equatorial Guinea, which sells LNG under a long-term contract principally based upon Henry Hub natural gas prices.~~

We own a 45 percent interest in a methanol plant located in Equatorial Guinea. Methanol demand has a direct impact on the plant’s earnings. Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices. The plant capacity of 1.1 million tonnes is about 2 percent of 2011 estimated world demand.

Results of Operations

Consolidated Results of 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 ~~third~~first quarter of ~~2012~~2013 was 335 percent higher than in the same period of ~~2011~~2012 primarily ~~due~~related to the ~~previously discussed resumption of our operations~~22 percent increase in ~~Libya.~~sales volumes on a boe basis. The effective tax rate was 7473 percent in the ~~third~~first quarter of ~~2012~~2013 compared to 69 percent in the ~~third~~first quarter of ~~2011~~2012, with the increase related to higher income from ~~continuing~~ operations ~~in higher tax jurisdictions, primarily Libya.~~

~~Consolidated income from continuing operations before income taxes in the first~~ ~~nine~~ ~~months of~~ ~~2012~~ ~~was 40 percent higher than in the same period of~~ ~~2011~~ ~~primarily due to increased income in Libya. As a result of increased income from continuing operations before tax~~ in higher tax jurisdictions, primarily Norway and ~~Libya, the effective tax rate was 72 percent for the first~~Libya.

Sales and other operating revenues, including related party ~~nine~~ ~~months of~~ ~~2012~~ ~~compared to 64 percent for the same period of~~ ~~2011~~.

~~Revenues~~ are summarized by segment in the following table:

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2012 2011 2012 2011
E&P $ 3,519
$ 3,212
$ 10,327
$ 9,788
OSM 470
427
1,184
1,180
IG —
16
—
93
Segment revenues 3,989
3,655
11,511
11,061
Unrealized gain on crude oil derivative instruments 45
—
45
—
Elimination of intersegment revenues —
(6 ) —
(47 )
Total revenues $ 4,034
$ 3,649
$ 11,556
$ 11,014



	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

~~E&P segment~~Total sales and other operating revenuesincreased ~~$307~~$486 million in the ~~third~~first quarter ~~and $539 million in the first~~ ~~nine~~ ~~months~~ of ~~2012~~2013 from the comparable prior-year ~~periods. Included~~period, with increases in ~~our~~each segment. The $303 million increase in the North America E&P segment are supply optimization activities which include the purchase of commodities from third parties for resale. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points. Volumes associated with supply optimization have been decreasing in 2012was primarily due to ~~market dynamics and related commodity prices have also been lower in 2012. See~~liquid hydrocarbon net sales volumes which increased 57 percent over the ~~Cost of revenues discussion as revenues from supply optimization approximate the related costs.~~

~~Revenues from the sale of our U.S. production are higher in the~~ ~~third~~same quarter ~~and first~~ ~~nine~~ ~~months~~ of 2012 ~~primarily as~~. Most of this net sales volume increase is a result of ~~increased liquid hydrocarbon sales volumes from our U.S.~~ongoing development programs in the Eagle Ford and Bakken shale resource plays. ~~Lower~~Partially offsetting this increase were lower liquid hydrocarbon and natural gas ~~realizations partially offset the volume impact.~~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 September 30, Nine Months Ended September 30,
2012 2011 2012 2011
United States Operating Statistics
     Net liquid hydrocarbon sales (mbbld) ^(a)
111
69
98
73
     Liquid hydrocarbon average realizations (per bbl) ^(b)
$ 83.80
$ 88.89
$ 86.98
$ 91.53

Net natural gas sales (mmcfd)
366
296
343
326
     Natural gas average realizations (per mcf)^(b)
$ 3.61
$ 4.85
$ 3.73
$ 5.04



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

Net natural gas sales volumes (mmcfd)	340		344
Natural gas average realizations (per mcf)^(b)		$3.86		$4.13


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


^(b)	Excludes gains and losses on derivative instruments


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

The $224 million increase in sales and other operating revenues in the International E&P segment was primarily a result of increased liquid hydrocarbon and natural gas ~~liquids.~~

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

~~Revenues~~sales volumes from our ~~international~~African operations ~~are higher in the~~ ~~third~~ ~~quarter and first~~ ~~nine~~ ~~months of~~ ~~2012~~ ~~primarily~~ as ~~a result of the~~ previously ~~discussed resumption of liquid hydrocarbon sales from Libya. Higher average~~discussed. Lower liquid hydrocarbon realizations ~~during~~partially offset the ~~third~~ ~~quarter and first~~ ~~nine~~ ~~months of~~ ~~2012~~ ~~also contributed to the revenue increase for both periods.~~ volume impact.

2723

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2012		2011		2012		2011		2013		2012
International Operating Statistics
Net liquid hydrocarbon sales (mbbld)^(a)
International E&P Operating Statistics
Net liquid hydrocarbon sales volumes (mbbld)^(a)
Europe	94		108		97		102		100		97
Africa	88		34		73		44		80		52
Total International	182		142		170		146
Total International E&P									180		149
Liquid hydrocarbon average realizations (per bbl)^(b)
Europe	$	112.34	$	117.05	$	115.73	$	115.91		$116.13		$123.76
Africa	98.65		63.51		97.00		75.38			$97.13		$94.41
Total International	$	105.71	$	104.24	$	107.69	$	103.75
Total International E&P										$107.68		$113.55

Net natural gas sales (mmcfd)
Net natural gas sales volumes (mmcfd)
Europe^(c)	100		79		102		92		95		104
Africa	485		453		434		440		473		418
Total International	585		532		536		532
Total International E&P									568		522
Natural gas average realizations (per mcf)^(b)
Europe	$	10.10	$	9.81	$	10.05	$	10.07		$12.83		$9.99
Africa	0.63		0.24		0.39		0.24			$0.51		$0.24
Total International	$	2.25	$	1.67	$	2.23	$	1.95
Total International E&P										$2.57		$2.19


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


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


^(c)	Includes natural gas acquired for injection and subsequent resale of 1811 mmcfd and 1614 mmcfd for the ~~third~~first quarters of ~~2012~~2013 and ~~2011, and 16 mmcfd and 15 mmcfd for the first~~ ~~nine~~ ~~months of~~ 2012 ~~and~~ ~~2011~~.

~~OSM segment~~Oil Sands Mining sales and other operating revenuesincreased ~~$43 million in the~~$9 million. Synthetic crude oil sales volumes were ~~third~~16 percent ~~quarter and $4 million~~higher than in the first ~~nine~~ ~~months~~quarter of 2012, ~~compared to~~ reflecting increased reliability of the ~~same periods of~~ ~~2011. The~~mines and upgrader ~~expansion was completed and commenced operations~~ in the ~~third~~first quarter of ~~2011, resulting in higher sales volumes in both periods.~~2013. However, an increase in the discount of WCS to WTI resulted in ~~the~~ decreases in average realizations during the ~~third~~first quarter ~~and first~~ ~~nine~~ ~~months~~ of ~~2012~~2013, partially offsetting the positive volume ~~variance.~~

impact. The following table gives details of net sales volumes and average realizations of our ~~OSM operations.~~Oil Sands Mining segment.

Three Months Ended September 30, Nine Months Ended September 30,
2012 2011 2012 2011
OSM Operating Statistics
Net synthetic crude oil sales (mbbld) ^(a)
53
50
47
43
Synthetic crude oil average realizations (per bbl)
$ 81.13
$ 87.29
$ 83.58
$ 90.91



	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.

~~IG segment revenuesdecreased $16 millionin the~~ ~~third~~ ~~quarter~~Unrealized gains and ~~$93 million in the first~~ ~~nine~~ ~~months of~~ ~~2012~~ ~~compared to the same periods of~~ ~~2011. Sales of LNG from our Alaska operations ceased in the third quarter of~~ ~~2011~~ ~~when we sold our interest in this production facility.~~

~~Unrealized gain~~losses on crude oil derivative instruments is are included in total sales and other operating revenues but are not ~~segment revenues.~~allocated to the segments. In the ~~third~~first quarter ~~and first nine months~~ of ~~2012,~~2013, the net unrealized ~~gain~~loss on crude oil derivative instruments was ~~$45~~$50 million ~~and there was~~ with no comparable crude oil derivative activity in ~~similar periods~~the same period of ~~2011.~~2012. See Note 1412 to the consolidated financial statements and Item 3. Quantitative and Qualitative Disclosures About Market Risk for additional information about our derivative positions.

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

Income from equity method investments~~decreased~~ increased $~~100~~40 million in the ~~first~~ ~~nine~~first ~~months~~quarter of ~~2012~~2013 from the comparable prior-year period, primarily due to ~~lower natural gas prices~~higher LNG realizations and partially due to higher sales volumes since turnarounds ~~early in 2012~~ at our facilities in Equatorial ~~Guinea. Also,~~Guinea reduced sale volumes in ~~January 2012, we sold our equity investments in several Gulf~~the first quarter of ~~Mexico crude oil pipelines.~~2012.

2824

Net gain ~~(loss)~~ on disposal of assets in the ~~third~~first quarter of ~~2012~~2013 ~~primarily reflects an $18~~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 ~~sale~~conveyance of ~~undeveloped acreage outside~~our interest in the ~~core of~~Marcellus natural gas shale play to the ~~Eagle Ford shale resource play.~~operator. The net gain on disposal of assets in the ~~first~~ ~~nine~~first ~~months~~quarter of 2012 consists ~~primarily~~ of the $166 million gain on the sale of our interests in several Gulf of Mexico crude oil pipeline ~~systems, reduced by the $36 million loss on the assignment of our Bone Bay and Kumawa exploration licenses in Indonesia and the $18 million loss on the Eagle Ford acreage.~~systems. See Note 75 to the consolidated financial statements for information about these dispositions.

~~Cost of revenuesdecreased~~Production expenses ~~$304 million~~ ~~and~~increased $~~666~~64 million in the ~~third~~first quarter ~~and first~~ ~~nine~~ ~~months~~ of ~~2012~~2013 from the comparable ~~periods of~~ ~~2011~~ primarily due to our supply optimization activities. Volumes associated with supply optimization have been decreasing in 2012 due to market dynamics and related commodity prices have also been lower in 2012. Comparatively, costs related to supply optimization were lower by $438 million for the ~~third~~ ~~quarter and by $677 million for the first~~ ~~nine~~ ~~months~~period of 2012. ~~Excluding~~The increase is primarily related to increased sales volumes in each segment.

Marketing expenses decreased $413 million in the ~~impact~~first quarter of ~~supply optimization activities, E&P segment operating~~2013 from the same period of 2012, consistent with the marketing revenue decline discussed above.

Exploration expenses ~~have increased~~were higher in ~~proportion to our increased production from U.S. shale plays. Additionally, Integrated Gas segment costs are lower~~the first quarter of 2013 than in the same quarter of 2012, primarily due to ~~the sale of our interest in the Alaska LNG facility in the third~~larger unproved property impairments. The first quarter of ~~2011.~~2013 included $340 million in unproved property impairments on Eagle Ford shale leases that either have expired or that we do not expect to drill or extend. The following table summarizes the components of exploration expenses.



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

Depreciation, depletion and amortization (“DD&A”) increased $~~108 million~~ ~~in the~~ ~~third~~ ~~quarter and~~ ~~$63~~173 million in the first ~~nine~~ ~~months~~quarter of ~~2012~~2013 from the comparable prior-year ~~periods. 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 in sales volumes generally result in similar changes in DD&A. The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in reserves and capitalized costs, can also cause changes in our DD&A. ~~Lower U.S. and~~A lower International E&P DD&A ~~rates~~rate in the ~~third~~first quarter ~~and first~~ ~~nine~~ ~~months~~ of ~~2012~~2013, primarily due to reserve increases at the end of 2012 for Norway, compared to the same ~~periods~~period in ~~2011~~2012 partially offset the impact of higher sales ~~volumes in those periods. Also, there was no depletion of our Alaska assets in the second and third quarters of 2012 because they are held for sale.~~volumes. The following table provides DD&A rates for ~~our E&P and OSM segments.~~each segment.

Three Months Ended September 30, Nine Months Ended September 30,
($ per boe) 2012 2011 2012 2011
DD&A rate

E&P Segment

United States $ 23
$ 24
$ 23
$ 26
International 8
10
9
10
OSM Segment $ 6
$ 6
$ 6
$ 6



	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~~ ~~nine~~first ~~months~~quarter of ~~2012~~2013 related primarily to the Powder River Basin and to the Ozona development in the Gulf of Mexico. Impairments in the ~~first~~ ~~nine~~first ~~months~~quarter of ~~2011~~2012 were also primarily related ~~primarily~~ to the ~~Droshky~~Ozona development in the Gulf of ~~Mexico and an intangible asset for an LNG delivery contract at Elba Island.~~Mexico. See Note 1311 to the consolidated financial statements for information about these impairments.

~~General~~Taxes other than incomeinclude production, severance and ~~administrative expenses~~ ~~increased~~ ~~$35 million~~ad valorem taxes in the ~~third~~ ~~quarter~~United States which tend to increase or decrease in relation to sales volumes and ~~$18 million~~ ~~in the first~~ ~~nine~~ ~~months of~~ ~~2012~~ ~~compared to the same periods in~~ ~~2011~~. The third quarter of 2012 includes pension settlement expense of $34 million. See Note 9 to the consolidated financial statements for information about the pension settlement. The cost increase for the nine-month period of 2012 is lower because 2011 included higher incentive compensation expense due to the increase in Marathon’s stock price in the period leading up to the spin-off. revenues.

~~Exploration expenseswere higher in the~~ ~~third~~ ~~quarter of~~ ~~2012~~ ~~than in the same quarter of~~ ~~2011~~, primarily due to larger unproved property impairments. The third quarter of 2012 included $51 million related to unproved property impairments associated with approximately 100,000 net non-core acres in the Eagle Ford shale. Exploration expenses were lower in the first ~~nine~~ ~~months of~~ ~~2012~~ than in the previous year, primarily due to dry wells in the Gulf of Mexico, Norway and Indonesia in 2011 compared to one dry Gulf of Mexico well plus various U.S. onshore dry wells in 2012; however, higher unproved property impairments in the Marcellus shale, Eagle Ford shale and Indonesia in 2012 partially offset this decrease. Geological and geophysical (“G&G”) costs increased in the nine months of 2012 primarily related to activity in the Kurdistan Region of Iraq and the seismic survey on our Birchwood oil sands in-situ lease.

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

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2012 2011 2012 2011
Unproved property impairments $ 79
$ 16
$ 149
$ 59
Dry well costs 35
31
138
252
G&G 24
39
94
67
Other 38
43
110
126
Total exploration expenses $ 176
$ 129
$ 491
$ 504

Net interest and other increased $~~23 million~~ ~~and~~ ~~$98~~22 million in the ~~third~~first quarter ~~and first~~of ~~nine~~2013 ~~months~~from the comparable period of 2012 ~~from the comparable periods of~~ ~~2011. Foreign currency gains were~~primarily due to lower ~~in the third quarter of 2012 than in the same quarter of 2011. In addition,~~ capitalized interest ~~has been lower~~ in ~~both periods of 2012.~~

~~Loss on early extinguishment of debtrelates to debt retirements in February and March of 2011. See Note 15 to the consolidated financial statements for additional discussion of these transactions.~~2013.

Provision for income taxes increased $~~381 million~~ ~~and~~ ~~$1,180~~98 million in the ~~third~~first quarter ~~and first~~ ~~nine~~ ~~months~~ of ~~2012~~2013 from the comparable ~~periods~~period of ~~2011~~2012 primarily due to the increase in pretax income in high tax rate ~~jurisdictions, including the impact of the previously discussed resumption of sales in Libya in the first quarter of 2012.~~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”~~items in ~~Note 8 to~~ the ~~consolidated financial statements.~~segment income table below.

Our effective tax ~~rate~~rates in the ~~first~~ ~~nine~~first three months of ~~2012~~2013 ~~was 72 percent. This rate is~~and 2012 were 73 percent and 69 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 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 ~~nine~~ three months of2013 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~~ ~~nine~~first three months of ~~2012~~.

~~Our effective tax rate in the first~~ ~~nine~~2013 ~~months of~~ ~~2011~~ ~~was 64 percent which is higher than the U.S. statutory tax rate of 35 percent primarily due to earnings from foreign jurisdictions where the tax rates are in excess of the U.S. statutory rate~~ and the valuation allowance recorded against 2011 foreign tax credits. In addition, in the second quarter of 2011, we recorded a deferred tax charge related to an internal restructuring of our international subsidiaries.2012.

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

Segment ~~Results~~Income (Loss)

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

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2012 2011 2012 2011
E&P

United States $ 110
$ 81
$ 289
$ 237
International 376
249
1,091
1,362
E&P segment 486
330
1,380
1,599
OSM 65
92
157
193
IG 39
55
56
158
Segment income 590
477
1,593
1,950
Items not allocated to segments, net of income taxes:

Corporate and other unallocated items (158 ) (56 ) (267 ) (209 )
Unrealized gain on crude oil derivative instruments 29
—
29
—
Gain (loss) on dispositions (11 ) (1 ) 72
23
Impairments —
—
(167 ) (195 )
Loss on early extinguishment of debt —
—
—
(176 )
Tax effect of subsidiary restructuring —
—
—
(122 )
Deferred income tax items —
(15 ) —
(65 )
Water abatement - Oil Sands —
—
—
(48 )
Income from continuing operations 450
405
1,260
1,158
Discontinued operations —
—
—
1,239
Net income $ 450
$ 405
$ 1,260
$ 2,397



	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 $29~~decreased $163 million in the ~~third~~first quarter ~~and increased $52 million in the first~~ ~~nine~~ ~~months~~ of ~~2012~~ ~~compared to the same periods of~~ ~~2011~~. The income increase in both periods was primarily the result of higher liquid hydrocarbon sales volumes as previously discussed, partially offset by lower liquid hydrocarbon realizations and the impact of increased production operations on DD&A and operating expenses. In addition, exploration expenses were higher primarily due to higher unproved property impairments.

~~International E&P incomeincreased $127 million in the~~ ~~third~~ ~~quarter and decreased $271 million in the first~~ ~~nine~~ ~~months of~~ ~~2012~~ compared to the same periods of 2011. Segment income, before taxes, increased in both periods primarily due to the previously discussed higher liquid hydrocarbon sales volumes and realizations, partially offset by increased operating costs. As previously discussed, increased income before tax in higher tax jurisdictions resulted in a higher effective tax rate in the first ~~nine~~ ~~months of~~ ~~2012~~2013 compared to the same period of ~~2011~~2012. The decrease was primarily the result of unproved property impairments, higher DD&A and lower liquid hydrocarbon realizations, partially offset by higher liquid hydrocarbon sales volumes, as discussed above.

~~OSM~~International E&P segment income ~~decreased $27 million and $36~~increased $46 million in the ~~third~~first quarter ~~and first~~ ~~nine~~ ~~months~~ of ~~2012~~. As previously discussed, lower synthetic crude oil price realizations were the primary reason for the decrease in income. This was partially offset by decreased costs on a per unit basis and higher sales volumes.

~~IG segment incom~~e~~decreased $16 million and $102 million in the~~ ~~third~~ ~~quarter and first~~ ~~nine~~ ~~months of~~ ~~2012~~2013 compared to the same ~~periods~~period of ~~2011~~2012. The increase was primarily ~~due~~related to ~~lower natural gas prices and turnarounds early in~~ ~~2012~~ ~~at our facilities in Equatorial Guinea. In addition, LNG~~higher liquid hydrocarbon sales volumes ~~are lower in the first nine months of 2012 due to the sale of our interest in the Alaska LNG facility in the third quarter of 2011.~~and increased income from equity method investments, partially offset by higher income taxes.

Critical Accounting Estimates

There have been no changes to our critical accounting estimates subsequent to December 31, ~~2011.~~2012.

Accounting Standards Not Yet Adopted

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

3126

Cash Flows and Liquidity

Cash Flows

Net cash provided by ~~continuing operations~~operating activities was $~~2,812~~1,528 million in the first ~~nine~~three months of ~~2012~~2013, compared to $~~4,400~~973 million in the first ~~nine~~three months of ~~2011~~2012 primarily reflecting the impact of ~~lower U.S.~~increased liquid hydrocarbon, ~~and~~ natural gas ~~prices~~and synthetic crude oil sales volumes on operating ~~income and higher cash tax payments. See Note 17 to the consolidated financial statements for amounts of the cash tax payments.~~income.

Net cash used in investing activities totaled $~~4,031~~1,037 million in the first ~~nine~~three months of ~~2012~~2013, compared to $~~2,118~~806 million ~~related to continuing operations~~ in the first ~~nine~~three months of ~~2011~~2012. Significant investing activities are additions to property, plant and equipment and disposal of assets. ~~In the first~~ ~~nine~~ ~~months of~~ ~~2012, most of the additions were~~Additions in ~~the E&P segment with continued~~both periods primarily related to spending on U.S. unconventional resource plays, particularly the Eagle Ford shale. ~~This compares to additions~~Disposals of assets totaled $312 million and $208 million in ~~the~~ first ~~nine~~three months of ~~2011~~2013 ~~which also included spending on U.S. unconventional resource plays, though at a lower level,~~ and ~~drilling in Norway, Indonesia and the Kurdistan Region of Iraq. In the first~~ ~~nine~~2012 ~~months of 2012, expenditures for acquisitions totaled~~ ~~$806 million~~, with 2013 net proceeds primarily related to ~~acquiring additional Eagle Ford shale properties. Deposits totaling $120 million were paid~~the sales of our Alaska assets and our interest in the ~~first~~ ~~nine~~ ~~months~~Neptune gas plant. In 2012, net proceeds resulted primarily from the sale of ~~2011~~ ~~related to the Eagle Ford shale acreage acquisitions that closed later that year.~~our interests in several Gulf of Mexico crude oil pipeline systems.

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

Net cash ~~provided by~~used in financing activities was $~~1,385~~413 million in the first ~~nine~~three months of ~~2012~~2013, compared to ~~net cash~~ ~~used in~~ ~~financing activities related to continuing operations of~~ $~~5,098~~157 million in the first ~~nine~~three months of ~~2011~~2012. ~~During~~Repayments of debt at maturity were $114 million in the first three months of 2013 and $53 million in the first three months of 2012. We also repaid all $200 million of our outstanding commercial paper during the first ~~nine~~three months of ~~2012, we drew a net~~2013. Dividends paid of approximately $~~1,839~~120 million ~~under our commercial paper program, retired $23 million principal amount of debt before it was due and repaid $88 million of debt upon its maturity. During the first~~ ~~nine~~ ~~months of~~ ~~2011~~, we retired $2.5 billion aggregate principal amount of our debt before it was due and distributed $1.6 billion to Marathon Petroleum Corporation in connection with the spin-off of the downstream business. Dividends paid were a significant use of cash in both periods.

Liquidity and Capital Resources

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, the issuance of notes, our committed revolving credit facility and sales of non-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 $10.4 billion and repaid $8.6 billion of commercial paper in the first~~ ~~nine~~ ~~months of~~ ~~2012~~ ~~leaving a balance of~~ ~~$1.8 billion~~ ~~outstanding at~~ ~~September 30, 2012. After~~ ~~September 30, 2012, we continued to utilize our sources of liquidity, including additional issuances of commercial paper and notes as discussed below, to fund working capital requirements.~~ Because of the alternatives available to us as discussed above and our access to capital markets, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, share repurchase program and other amounts that may ultimately be paid in connection with contingencies.

Capital Resources

Credit Arrangements and Borrowings

At ~~September 30, 2012~~March 31, 2013, we had no borrowings against our revolving credit facility ~~described below, and~~ ~~$1.8 billion~~ ~~in commercial paper outstanding~~or under our U.S. commercial paper program that is backed by the revolving credit facility. During the

~~On October 29, 2012, we issued $1 billion aggregate principal amount~~first quarter of ~~senior notes bearing interest at 0.9 percent with a maturity date~~2013, $200 million of November 1, 2015 and $1 billion aggregate principal amount of senior notes bearing interest at 2.8 percent with a maturity date of November 1, 2022. Interest on the senior notes is payable semi-annually beginning May 1, 2013. The proceeds are being used to pay off commercial paper was issued and ~~for general~~$400 million of commercial paper was repaid.

At March 31, 2013, we had $6,544 million in long-term debt outstanding, $68 million of which is due within one year. We do not have any triggers on any of our corporate ~~purposes.~~

In April 2012, we terminated our $3.0 billion five-year revolving credit facility and replaced it with a new $2.5 billion unsecured five-year revolving credit facility (the “Credit Facility”). The Credit Facility matures in April 2017 but allows us to request two one-year extensions. It contains an option to increase the commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, and includes sub-facilities for swing-line loans and letters of credit up to an aggregate amount of $100 million and $500 million, respectively. Fees on the unused commitment of each lender range from 10 basis points to 25 basis points per year depending on our credit ratings. Borrowings under the Credit Facility bear interest, at our option, at either (a) an 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~~debt that ~~requires our ratio of total debt to total capitalization not to 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.

32Shelf 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 24 percent at March 31, 2013, compared to 25 percent at ~~September 30, 2012, compared to 20 percent at~~ December 31, ~~2011~~2012.


	September 30,			December 31,			March 31,			December 31,
(In millions)	2012			2011			2013			2012
Commercial paper	$	1,839		$	—		$	—		$	200
Long-term debt due within one year	183			141			68			184
Long-term debt	4,518			4,674			6,476			6,512
Total debt	6,540			4,815			$	6,544		$	6,896
Cash	671			493			$	768		$	684
Equity	$	18,064		$	17,159		$	18,588		$	18,283
Calculation:
Total debt	$	6,540		$	4,815		$	6,544		$	6,896
Minus cash	671			493			768			684
Total debt minus cash	5,869			4,322			5,776			6,212
Total debt	6,540			4,815			6,544			6,896
Plus equity	18,064			17,159			18,588			18,283
Minus cash	671			493			768			684
Total debt plus equity minus cash	$	23,933		$	21,481		$	24,364		$	24,495
Cash-adjusted debt-to-capital ratio	25		%	20		%	24		%	25		%

Capital Requirements

On ~~October 31, 2012,~~April 24, 2013, our Board of Directors approved a dividend of 17 cents per share for the ~~third~~first quarter of ~~2012~~2013, payable ~~December~~June 10, ~~2012~~2013 to stockholders of record at the close of business on ~~November 21, 2012.~~May 16, 2013.

~~In October and early November 2012,~~As of March 31, 2013, we ~~paid $264~~plan to make contributions of up to $55 million ~~for closed acquisition transactions.~~

~~In the first quarter of 2012, we increased~~to our ~~2012 capital, investment and exploration budget, excluding acquisition costs, from $4.8 billion to $5.0 billion,~~funded pension plans in 2013, $17 million of which ~~$4.6 billion will be used for capital expenditures. The increase reflects development plans for the additional acreage 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 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 ~~discussions~~ also ~~contain~~contains forward-looking statements ~~about our 2012 capital, investment~~regarding planned funding of pension plans, which are based on current expectations, estimates and ~~exploration budget.~~projections and are not guarantees of actual performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially ~~are changes in~~include prices of and demand for liquid hydrocarbons, ~~and~~ natural gas and synthetic crude oil, actions of competitors, disruptions or interruptions of our production or oil sands mining and ~~mining~~bitumen upgrading operations due to unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other operating and economic considerations.

Contractual Cash Obligations

~~The table below provides aggregated information on~~As of March 31, 2013, our ~~consolidated~~total contractual cash obligations ~~to make future payments under existing contracts as of~~ ~~September 30, 2012~~.were consistent with December 31, 2012.

2013- 2015- Later
(In millions) Total 2012 2014 2016 Years
Short and long-term debt (excludes interest) $ 6,504
$ 1,874
$ 250
$ 69
$ 4,311
Lease obligations 281
39
80
65
97
Purchase obligations:

Oil and gas activities^(a)
993
351
505
59
78
Service and materials contracts^(b)
909
45
227
131
506
Transportation and related contracts 1,301
63
317
190
731
Drilling rigs and fracturing crews 894
139
730
25
—
Other 234
57
93
27
57
Total purchase obligations 4,331
655
1,872
432
1,372
Other long-term liabilities reported

in the consolidated balance sheet^(c)
1,122
174
272
253
423
Total contractual cash obligations^(d)
$ 12,238
$ 2,742
$ 2,474
$ 819
$ 6,203



^(a)	Oil and gas activities include contracts to acquire property, plant and equipment and commitments for oil and gas exploration such as costs related to contractually obligated exploratory work programs that are expensed immediately.


^(b)	~~Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.~~


^(c)	Primarily includes obligations for pension and other postretirement benefits including medical and life insurance, which we have estimated through 2021. Also includes amounts for uncertain tax positions.


^(d)	~~This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of~~ ~~$1,516 million~~.

Environmental Matters

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

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

Other Contingencies

~~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.

~~In August 2012, we entered crude oil derivatives related to a portion of~~ Additional disclosures regarding our ~~forecast U.S. E&P crude oil sales through December 31, 2013. Disclosures about~~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 Notes 1311 and 1412 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 ~~September 30, 2012~~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				Incremental Change in IFO from a Hypothetical Price Increase of						Incremental Change in IFO from a Hypothetical Price Decrease of
	10%			25%			10%		25%		10%			25%			10%		25%
Crude oil
Swaps	$	(207	)	$	(519	)	$	207	$	519	$	(127	)	$	(317	)	$	127	$	317
Option Collars	(105		)	(277		)	103		275		(52		)	(160		)	47		155
Total crude oil	(312		)	(796		)	310		794		(179		)	(477		)	174		472
Natural gas
Futures	(1		)	(2		)	1		2		(1		)	(1		)	1		1
Total natural gas	(1		)	(2		)	1		2		(1		)	(1		)	1		1
Total	$	(313	)	$	(798	)	$	311	$	796	$	(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 ~~September 30, 2012~~March 31, 2013 is provided in the following table.


					Incremental							Incremental
					Change in							Change in
(In millions)	Fair Value				Fair Value			Fair Value				Fair Value
Financial assets (liabilities): ^(a)
Interest rate swap agreements	$	22		^(b)	$	1		$	18		^(b)	$	2
Long-term debt, including amounts due within one year	$	(5,639	)	^(b)	$	(206	)	$	(7,347	)	^(b)	$	(231	)


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


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

The aggregate cash flow effect on foreign currency derivative contracts of a hypothetical 10 percent change in exchange rates at ~~September 30, 2012~~March 31, 2013 would be ~~$69 million.~~$61 million.

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. ~~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.~~effective for the period ending March 31, 2013.

In ~~2012,~~the first quarter of 2013, we ~~began a project to~~completed the update of our existing ~~ERP~~Enterprise Resource Planning ("ERP") system. ~~The project includes implementation of~~This update included a new general ledger, consolidations system and reporting tools. This project is currently in testing phases and we expect full implementation in the first half of 2013. We believe that controls over project development and implementation are adequate to assure there will be no material effect, or a reasonable likelihood of a material effect, on our internal control over financial reporting.

~~During the quarter ended~~ ~~September 30, 2012, there~~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.

3629

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
(In millions) 2012 2011 2012 2011
Segment Income
Exploration and Production

United States $ 110
$ 81
$ 289
$ 237
International 376
249
1,091
1,362
E&P segment 486
330
1,380
1,599
Oil Sands Mining 65
92
157
193
Integrated Gas 39
55
56
158
Segment income 590
477
1,593
1,950
Items not allocated to segments, net of income taxes (140 ) (72 ) (333 ) (792 )
Income from continuing operations 450
405
1,260
1,158
Discontinued operations^(a)
—
—
—
1,239
Net income $ 450
$ 405
$ 1,260
$ 2,397
Capital Expenditures^(b)

Exploration and Production

United States $ 1,046
$ 502
$ 2,891
$ 1,407
International 228
182
568
694
E&P segment 1,274
684
3,459
2,101
Oil Sands Mining 41
36
136
236
Integrated Gas 1
1
2
2
Corporate 23
7
82
37
Total $ 1,339
$ 728
$ 3,679
$ 2,376
Exploration Expenses

United States $ 132
$ 75
$ 369
$ 280
International 44
54
122
224
Total $ 176
$ 129
$ 491
$ 504



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


^(a)	~~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.

3730

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2012 2011 2012 2011
E&P Operating Statistics

Net Liquid Hydrocarbon Sales (mbbld)

United States 111
69
98
73

Europe 94
108
97
102
Africa 88
34
73
44
Total International 182
142
170
146
Worldwide 293
211
268
219
Net Natural Gas Sales (mmcfd)

United States 366
296
343
326

Europe^(c)
100
79
102
92
Africa 485
453
434
440
Total International 585
532
536
532
Worldwide 951
828
879
858
Total Worldwide Sales (mboed) 452
349
414
362
Average Realizations ^(d)

Liquid Hydrocarbons (per bbl)

United States $83.80 $88.89 $86.98 $91.53

Europe $112.34 $117.05 $115.73 $115.91
Africa $98.65 $63.51 $97.00 $75.38
Total International $105.71 $104.24 $107.69 $103.75
Worldwide $97.40 $99.24 $100.10 $99.68
Natural Gas (per mcf)
United States $3.61 $4.85 $3.73 $5.04

Europe $10.10 $9.81 $10.05 $10.07
Africa^(e)
$0.63 $0.24 $0.39 $0.24
Total International $2.25 $1.67 $2.23 $1.95
Worldwide $2.77 $2.81 $2.81 $3.12
OSM Operating Statistics

    Net Synthetic Crude Oil Sales (mbbld) ^(f)
53
50
47
43
    Synthetic Crude Oil Average Realizations (per bbl)^(d)
$ 81.13
$ 87.29
$ 83.58
$ 90.91
IG Operating Statistics

     Net Sales (mtd) ^(g)

LNG 7,065
6,935
6,277
7,121
Methanol 1,146
1,366
1,242
1,310



	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


^(c)(b)	Includes natural gas acquired for injection and subsequent resale of 1811 mmcfd and 16 ~~mmcfd for the~~ ~~third~~ ~~quarters of~~ ~~2012~~ ~~and~~ ~~2011, and~~ 16 ~~mmcfd and~~ 1514 mmcfd for the first ~~nine~~ ~~months~~quarters of 2013 and 2012 ~~and~~ ~~2011~~.


^(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 ~~in our E&P segment and we include our share~~from each 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~~these equity method investees in 2011. 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.our International E&P segment.

3832

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

Litigation

In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in ~~legal or environmental proceedings during~~ the ~~first~~ ~~nine~~ ~~months~~District Court of ~~2012~~.Harris County, Texas, alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. We are vigorously defending this litigation. The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain. We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.

Environmental

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

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. The discussion of such risks and uncertainties may be found under Item 1A. Risk Factors in our ~~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 during the quarter ended ~~September 30, 2012,~~March 31, 2013, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934.

Column (a) Column (b) Column (c) Column (d)
Total Number of Average Price
Total Number of
Shares Purchased
as Part of
Publicly Announced

Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Period
Shares Purchased ^(a)(b)
Paid per Share
Plans or Programs^(c)

Plans or Programs^(c)
07/01/12 – 07/31/12 12,285 $25.62 —
$1,780,609,536
08/01/12 – 08/31/12 143,642 $27.59 —
$1,780,609,536
09/01/12 – 09/30/12 38,963 $28.43 —
$1,780,609,536
Total 194,890 $27.63 —



	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)	~~162,184~~120,431 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

In ~~September 2012, 32,706~~March 2013, 26,919 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon Oil.

^(c)

We announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion. As of ~~September 30, 2012,~~March 31, 2013, 78 million split-adjusted common shares had been acquired at a cost of $3,222 million, which includes transaction fees and commissions that are not reported in the table above. Of this total, 66 million shares had been acquired at a cost of $2,922 million prior to the spin-off of the downstream business.

Item 4. Mine Safety Disclosures

Not applicable.

3933

Item 6. Exhibits

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

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

~~3.1~~10.1

~~Amended By-laws~~Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Section 16 Officers granted under Marathon Oil ~~Corporation, effective January 1, 2013.~~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.

4034

SIGNATURES

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



~~November 7, 2012~~May 10, 2013		MARATHON OIL CORPORATION

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

4135

Exhibit Index

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

10.1

Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan

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.



	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	2118
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3529
Item 4.	Controls and Procedures	3629
	Supplemental Statistics (Unaudited)	3730
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	3933
Item 1A.	Risk Factors	3933
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3933
Item 4.	Mine Safety Disclosures	3933
Item 6.	Exhibits	4034
	Signatures	4135



(In millions)
Assets:
Cash	$	8
Receivables	22
Inventories	1
Total current assets acquired	31
Property, plant and equipment	822
Total assets acquired	853
Liabilities:
Accounts payable	78
Asset retirement obligations	7
Total liabilities assumed	85
Net assets acquired	$	768



	Three Months Ended September 30, 2012
(In millions)	E&P		OSM		IG		Total
Revenues:
Customer	$	3,503	$	470	$	—	$	3,973
Related parties	16		—		—		16
Segment revenues	$	3,519	$	470	$	—	3,989
Unrealized gain on crude oil derivative instruments							45
Total revenues							$	4,034
Segment income	$	486	$	65	$	39	$	590
Income from equity method investments	74		—		48		122
Depreciation, depletion and amortization	556		60		—		616
Income tax provision	1,252		20		9		1,281
Capital expenditures	1,274		41		1		1,316



	Three Months Ended September 30, 2011
(In millions)	E&P		OSM		IG		Total
Revenues:
Customer	$	3,190	$	427	$	16	$	3,633
Intersegment	6		—		—		6
Related parties	16		—		—		16
Segment revenues	$	3,212	$	427	$	16	3,655
Elimination of intersegment revenues							(6		)
Total revenues							$	3,649
Segment income	$	330	$	92	$	55	$	477
Income from equity method investments	63		—		60		123
Depreciation, depletion and amortization	454		55		—		509
Income tax provision	890		31		19		940
Capital expenditures	684		36		1		721



Term	Bbls per Day	Weighted Average Price per Bbl	Benchmark
Swaps
October 2012 - December 2013	20,000	$96.29	West Texas Intermediate
October 2012 - December 2013	25,000	$109.19	Brent
Option Collars
October 2012 - December 2013	15,000	$90.00 floor / $101.17 ceiling	West Texas Intermediate
October 2012 - December 2013	15,000	$100.00 floor / $116.30 ceiling	Brent



					2013-		2015-		Later
(In millions)	Total		2012		2014		2016		Years
Short and long-term debt (excludes interest)	$	6,504	$	1,874	$	250	$	69	$	4,311
Lease obligations	281		39		80		65		97
Purchase obligations:
Oil and gas activities^(a)	993		351		505		59		78
Service and materials contracts^(b)	909		45		227		131		506
Transportation and related contracts	1,301		63		317		190		731
Drilling rigs and fracturing crews	894		139		730		25		—
Other	234		57		93		27		57
Total purchase obligations	4,331		655		1,872		432		1,372
Other long-term liabilities reported
in the consolidated balance sheet^(c)	1,122		174		272		253		423
Total contractual cash obligations^(d)	$	12,238	$	2,742	$	2,474	$	819	$	6,203