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~~June 30, ~~2012~~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 þRNo 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 þR 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~~709,671,894 shares of Marathon Oil Corporation common stock outstanding as of ~~October~~July 31, ~~2012~~2013.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended ~~September~~June 30, ~~2012~~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						Six Months Ended
	September 30,						September 30,						June 30,						June 30,
(In millions, except per share data)	2012			2011			2012			2011			2013			2012			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													$	3,419		$	2,975		$	6,859		$	5,919
Marketing revenues													499			757			929			1,606
Income from equity method investments	122			123			260			360			77			60			195			138
Net gain (loss) on disposal of assets	(12		)	13			126			63			(107		)	(28		)	2			138
Other income	17			14			43			36			10			20			19			23
Total revenues and other income	4,161			3,799			11,985			11,473			3,898			3,784			8,004			7,824
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													614			485			1,192			987
Marketing, including purchases from related parties													495			755			924			1,609
Other operating													86			107			197			199
Exploration													133			172			598			307
Depreciation, depletion and amortization	625			517			1,779			1,716			738			580			1,485			1,154
Impairments	8			—			271			307			—			1			38			263
General and administrative expenses	139			104			389			371
Other taxes	63			59			208			170
Exploration expenses	176			129			491			504
Taxes other than income													93			55			177			123
General and administrative													164			154			338			313
Total costs and expenses	2,379			2,466			7,334			7,923			2,323			2,309			4,949			4,955
Income from operations	1,782			1,333			4,651			3,550			1,575			1,475			3,055			2,869
Net interest and other	(53		)	(30		)	(160		)	(62		)	(71		)	(57		)	(143		)	(107		)
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													1,504			1,418			2,912			2,762
Provision for income taxes	1,279			898			3,231			2,051			1,078			1,025			2,103			1,952
Income from continuing operations	450			405			1,260			1,158
Discontinued operations	—			—			—			1,239
Net income	$	450		$	405		$	1,260		$	2,397		$	426		$	393		$	809		$	810
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													$	0.60		$	0.56		$	1.14		$	1.15
Diluted													$	0.60		$	0.56		$	1.14		$	1.14
Dividends paid	$0.17			$0.15			$0.51			$0.65			$	0.17		$	0.17		$	0.34		$	0.34
Weighted average shares:
Basic	706			711			705			712			710			706			709			705
Diluted	709			714			709			716			714			709			713			709

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						Six Months Ended
	September 30,						September 30,						June 30,						June 30,
(In millions)	2012			2011			2012			2011			2013			2012			2013			2012
Net income	$	450		$	405		$	1,260		$	2,397		$	426		$	393		$	809		$	810
Other comprehensive income
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	(90		)	13			(80		)	110			133			(3		)	146			10
Spin-off downstream business	—			—			—			968
Income tax benefit (provision) on postretirement and
Income tax (provision) benefit on postretirement and
postemployment plans	32			6			28			(409		)	(49		)	1			(54		)	(4		)
Postretirement and postemployment plans, net of tax	(58		)	19			(52		)	669			84			(2		)	92			6
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		)	(3		)	(1		)	(4		)	—
Income tax provision on foreign currency translation and other	—			—			—			—
Income tax benefit on foreign currency translation and other													1			—			1			—
Foreign currency translation and other, net of tax	—			—			—			(1		)	(2		)	(1		)	(3		)	—
Other comprehensive income (loss)	(57		)	18			(51		)	669			82			(3		)	89			6
Comprehensive income	$	393		$	423		$	1,209		$	3,066		$	508		$	390		$	898		$	816

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	September 30,			December 31,			June 30,			December 31,
(In millions, except per share data)	2012			2011			2013			2012
Assets
Current assets:
Cash and cash equivalents	$	671		$	493		$	246		$	684
Receivables	2,553			1,917			2,443			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			224			299
Total current assets	4,037			3,224			3,281			3,762
Equity method investments	1,319			1,383			1,244			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 $20,639 and $19,266							27,457			28,272
Goodwill	525			536			499			525
Other noncurrent assets	1,231			904			2,567			1,468
Total assets	$	34,558		$	31,371		$	35,048		$	35,306
Liabilities
Current liabilities:
Commercial paper	$	1,839		$	—		$	—		$	200
Accounts payable	2,335			1,864			2,152			2,324
Payables to related parties	44			18
Payroll and benefits payable	148			193			137			217
Accrued taxes	2,027			2,015			1,397			1,983
Other current liabilities	206			163			254			173
Long-term debt due within one year	183			141			68			184
Total current liabilities	6,782			4,394			4,008			5,081
Long-term debt	4,518			4,674			6,428			6,512
Deferred tax liabilities	2,495			2,544			2,406			2,432
Defined benefit postretirement plan obligations	817			789			739			856
Asset retirement obligations	1,516			1,510			2,039			1,749
Deferred credits and other liabilities	366			301			407			393
Total liabilities	16,494			14,212			16,027			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 – 61 million and 63 million shares							(2,477		)	(2,560		)
Additional paid-in capital	6,634			6,680			6,614			6,616
Retained earnings	13,688			12,788			14,458			13,890
Accumulated other comprehensive loss	(421		)	(370		)	(344		)	(433		)
Total equity of Marathon Oil's stockholders	18,064			17,152
Noncontrolling interest	—			7
Total equity	18,064			17,159			19,021			18,283
Total liabilities and stockholders' equity	$	34,558		$	31,371		$	35,048		$	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						Six Months Ended
	September 30,						June 30,
(In millions)	2012			2011			2013			2012
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	1,260		$	2,397		$	809		$	810
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		)	113			75
Depreciation, depletion and amortization	1,779			1,716			1,485			1,154
Impairments	271			307			38			263
Pension and other postretirement benefits, net	(56		)	28			34			(22		)
Exploratory dry well costs and unproved property impairments	287			311			494			174
Net gain on disposal of assets	(126		)	(63		)	(2		)	(138		)
Equity method investments, net	(14		)	16			—			7
Changes in:
Current receivables	(646		)	202			17			(107		)
Inventories	(6		)	47			(16		)	(18		)
Current accounts payable and accrued liabilities	156			361			(651		)	(450		)
All other operating, net	(66		)	113			75			(6		)
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			2,396			1,742
Investing activities:
Acquisitions, net of cash acquired	(806		)	—
Additions to property, plant and equipment	(3,509		)	(2,437		)	(2,676		)	(2,181		)
Disposal of assets	193			385			333			218
Investments - return of capital	42			41			29			21
Investing activities of discontinued operations	—			(493		)
Property deposit	—			(120		)
All other investing, net	49			13			15			(59		)
Net cash used in investing activities	(4,031		)	(2,611		)	(2,299		)	(2,001		)
Financing activities:
Commercial paper, net	1,839			—			(200		)	550
Debt issuance costs	(9		)	—			—			(9		)
Debt repayments	(111		)	(2,843		)	(148		)	(111		)
Purchases of common stock	—			(300		)
Dividends paid	(360		)	(462		)	(241		)	(240		)
Financing activities of discontinued operations	—			2,916
Distribution in spin-off	—			(1,622		)
All other financing, net	26			129			46			20
Net cash provided by (used in) financing activities	1,385			(2,182		)
Net cash (used in) provided by financing activities							(543		)	210
Effect of exchange rate changes on cash	12			(15		)	8			8
Net increase in cash and cash equivalents	178			682
Net decrease in cash and cash equivalents							(438		)	(41		)
Cash and cash equivalents at beginning of period	493			3,951			684			493
Cash and cash equivalents at end of period	$	671		$	4,633		$	246		$	452

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~~second quarter and first six months of 2012 increased by $24 million and $63 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~~second quarter and first ~~nine~~six months of ~~2012~~2013 are not necessarily indicative of the results to be expected for the full year.

2. ~~Spin-off Downstream Business~~

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

The following table presents selected financial information regarding the results of operations of our downstream business which are reported as discontinued operations. Transaction costs incurred to affect the spin-off 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~~Not Yet Adopted

In ~~September 2011,~~June 2013, the Financial Accounting Standards Board ~~(“FASB”~~("FASB") ~~amended~~ratified the Emerging Issues Task Force consensus on Issue 13-C, which requires that an unrecognized tax benefit or a portion of an unrecognized tax benefit be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. 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 prospectively to unrecognized tax benefits that exist as of the effective date. Early adoption and retrospective application are permitted. We do not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within United States generally accepted accounting principles ("U.S. GAAP"). An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. We do not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position or 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 Note 15. 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 13. 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 $3 million ~~current liability~~ recorded at ~~September~~June 30, ~~2012~~2013, consistent with 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~~728 million as of ~~September~~June 30, ~~2012~~2013. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.

5.4. Income per Common Share

Basic income per share is based on the weighted average number of common shares outstanding. 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 June 30,
	2012				2011				2013				2012
(In millions, except per share data)	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted
Net income	$	450	$	450	$	405	$	405	$	426	$	426	$	393	$	393

Weighted average common shares outstanding	706		706		711		711		710		710		706		706
Effect of dilutive securities	—		3		—		3		—		4		—		3
Weighted average common shares, including
dilutive effect	706		709		711		714		710		714		706		709
Per share:
Net income	$0.64		$0.63		$0.57		$0.57			$0.60		$0.60		$0.56		$0.56

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Nine Months Ended September 30,								Six Months Ended June 30,
	2012				2011				2013				2012
(In millions, except per share data)	Basic		Diluted		Basic		Diluted		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	$	809	$	809	$	810	$	810

Weighted average common shares outstanding	705		705		712		712		709		709		705		705
Effect of dilutive securities	—		4		—		4		—		4		—		4
Weighted average common shares, including
dilutive effect	705		709		712		716		709		713		705		709
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		$1.14		$1.14		$1.15		$1.14

The per share calculations above exclude 106 million stock options and stock appreciation rights for the ~~third~~second quarter ~~quarter~~ and first ~~nine~~six months of 2013. Excluded for the second quarter and first six months of 2012~~, as they were antidilutive. Excluded for the~~ ~~third~~ ~~quarter and first~~ ~~nine~~ ~~months of~~ ~~2011~~ were 910 million and 79 million stock options and stock appreciation rights.

~~6. Acquisitions~~5. Dispositions

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

~~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
Segment

~~The fair values~~In June 2013, we closed the sale 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 observableour interests 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. Dispositions~~

~~2012~~

~~In the third quarter of 2012, we sold approximately~~ ~~5,800~~ ~~net undeveloped acres located outside the core of the Eagle Ford shale, held by our E&P segment,~~DJ Basin for proceeds of $919 million. A ~~pretax~~ loss of $18114 million was ~~recorded.~~

In February 2013, we conveyed our interests in the ~~agreements~~Marcellus natural gas shale play to the operator. A $43 million loss on this transaction was ~~received during~~recorded in the ~~third~~first quarter of ~~2012, which released us from our obligations and further commitments related to these licenses, and we paid the amount accrued.~~ 2013.

In ~~April 2012,~~February 2013, we ~~entered into agreements to sell all~~closed the sale of our ~~E&P segment’s~~interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million gain was recorded in the first quarter of 2013.

In January 2013, we closed the sale of our remaining assets in ~~Alaska. One transaction closed~~Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million which was collected in July 2013. After closing adjustments made in the second quarter of ~~2012 with proceeds and a net pretax~~2013, the gain ofon this sale was $755 million. ~~The remaining~~

2013 - International E&P Segment

In June 2013, we entered into an agreement to sell our non-operated 10 percent working interest in the Production Sharing Contract and Joint Operating Agreement in Block 31 offshore Angola. This transaction, ~~with a value of~~valued at $~~375 million~~1.5 billion before closing adjustments, is ~~currently under review by~~expected to close in the ~~U.S. Federal Trade Commission~~fourth quarter of 2013, subject to government, regulatory and ~~the Alaska Attorney General's office, which could impact the closing of this transaction. Assets~~third-party approvals. Angola Block 31 is reflected as held for sale ~~are included~~ in the ~~September~~June 30, ~~2012~~2013 consolidated balance sheet as follows:


(In millions)
Other current assets	$	59
Other noncurrent assets	190		$	1,550
Total assets	249		1,550
Other current liabilities	1		58
Deferred credits and other liabilities	90		39
Total liabilities	$	91	$	97

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~~

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

2012 - International E&P Segment

In ~~September 2011,~~May 2012, we ~~sold~~reached an agreement to relinquish our ~~Integrated Gas segment's equity interest in a liquefied natural gas (“LNG”) processing facility in Alaska. A gain on the transaction~~operatorship 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~~Bone Bay and ~~the Brynhild and Eirin~~Kumawa exploration ~~areas offshore Norway for net proceeds of~~ ~~$85 million, excluding working capital adjustments.~~licenses in Indonesia. A $6436 million ~~pretax~~payment to settle all of our obligations related to these licenses, including well commitments, was accrued and reported as a loss on ~~this disposition was recorded~~disposal of assets in the ~~fourth~~second quarter of ~~2010.~~2012.

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; and

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									Three Months Ended June 30, 2013
(In millions)	E&P		OSM		IG		Total			N.A. E&P		Int'l E&P		OSM		Total
Revenues:
Customer	$	3,190	$	427	$	16	$	3,633
Intersegment	6		—		—		6
Related parties	16		—		—		16
Sales and other operating revenues										$	1,284	$	1,732	$	353	$	3,369
Marketing revenues										439		51		9		499
Segment revenues	$	3,212	$	427	$	16	3,655			$	1,723	$	1,783	$	362	3,868
Elimination of intersegment revenues							(6		)
Unrealized gain on crude oil derivative instruments																50
Total revenues							$	3,649								$	3,918
Segment income	$	330	$	92	$	55	$	477		$	221	$	382	$	20	$	623
Income from equity method investments	63		—		60		123			—		77		—		77
Depreciation, depletion and amortization	454		55		—		509			490		189		48		727
Income tax provision	890		31		19		940			129		1,004		7		1,140
Capital expenditures	684		36		1		721			904		241		97		1,242

109

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Nine Months Ended September 30, 2012								Three Months Ended June 30, 2012
(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
Segment revenues	$	10,327	$	1,184	$	—	11,511
Unrealized gain on crude oil derivative instruments							45
Sales and other operating revenues									$	833	$	1,813	$	329	$	2,975
Marketing revenues									696		56		5		757
Total revenues							$	11,556	$	1,529	$	1,869	$	334	$	3,732
Segment income	$	1,380	$	157	$	56	$	1,593	$	70	$	373	$	50	$	493
Income from equity method investments	176		—		84		260		—		60		—		60
Depreciation, depletion and amortization	1,593		159		—		1,752		290		228		50		568
Income tax provision	3,398		51		15		3,464		39		1,070		17		1,126
Capital expenditures	3,459		136		2		3,597		1,013		202		43		1,258


	Nine Months Ended September 30, 2011									Six Months Ended June 30, 2013
(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
Sales and other operating revenues										$	2,499	$	3,619	$	741	$	6,859
Marketing revenues										784		136		9		929
Segment revenues	$	9,788	$	1,180	$	93	11,061			$	3,283	$	3,755	$	750	7,788
Elimination of intersegment revenues							(47		)
Unrealized loss on crude oil derivative instruments																—
Total revenues							$	11,014								$	7,788
Segment income	$	1,599	$	193	$	158	$	1,950		$	162	$	835	$	58	$	1,055
Income from equity method investments	187		—		173		360			—		195		—		195
Depreciation, depletion and amortization	1,541		141		3		1,685			968		396		100		1,464
Income tax provision	2,101		64		62		2,227			99		2,146		20		2,265
Capital expenditures	2,101		236		2		2,339			1,874		466		142		2,482



	Six Months Ended June 30, 2012
(In millions)	N.A. E&P		Int'l E&P		OSM		Total
Revenues:
Sales and other operating revenues	$	1,745	$	3,476	$	698	$	5,919
Marketing revenues	1,471		120		15		1,606
Total revenues	$	3,216	$	3,596	$	713	$	7,525
Segment income	$	174	$	780	$	88	$	1,042
Income from equity method investments	1		137		—		138
Depreciation, depletion and amortization	604		428		99		1,131
Income tax provision	100		2,041		30		2,171
Capital expenditures	1,842		340		95		2,277

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 June 30,				Six Months Ended June 30,
(In millions)	2012		2011		2012		2011		2013		2012		2013		2012
Total revenues	$	4,034	$	3,649	$	11,556	$	11,014	$	3,918	$	3,732	$	7,788	$	7,525
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									499		757		929		1,606
Sales and other operating revenues, including related party									$	3,419	$	2,975	$	6,859	$	5,919

1110

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 June 30,						Six Months Ended June 30,
(In millions)	2013			2012			2013			2012
Segment income	$	623		$	493		$	1,055		$	1,042
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(156		)	(77		)	(227		)	(148		)
Unrealized gain (loss) on crude oil derivative instruments	32			—			—			—
Net gain (loss) on dispositions	(73		)	(23		)	(9		)	83
Impairments	—			—			(10		)	(167		)
Net income	$	426		$	393		$	809		$	810

9.7. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:


	Three Months Ended September 30,												Three Months Ended June 30,
	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		$	13		$	1		$	1
Interest cost	16			17			4			4			16			16			3			3
Expected return on plan assets	(14		)	(16		)	—			—			(16		)	(16		)	—			—
Amortization:
– prior service cost (credit)	2			1			(2		)	(2		)	1			2			(1		)	(1		)
– actuarial loss	12			12			—			—			16			13			—			—
– net settlement loss^(a)	34			—			—			—
Net settlement loss^(a)													17			—			—			—
Net periodic benefit cost	$	62		$	26		$	3		$	3		$	48		$	28		$	3		$	3


	Nine Months Ended September 30,												Six Months Ended June 30,
	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011			2013			2012			2013			2012
Service cost	$	37		$	35		$	3		$	3		$	28		$	25		$	2		$	2
Interest cost	48			50			11			12			31			32			6			7
Expected return on plan assets	(46		)	(49		)	—			—			(33		)	(32		)	—			—
Amortization:
– prior service cost (credit)	6			4			(5		)	(5		)	3			4			(3		)	(3		)
– actuarial loss	37			37			—			—			29			25			—			—
– net settlement loss^(a)	34			—			—			—
Net settlement loss^(a)													17			—			—			—
Net periodic benefit cost	$	116		$	77		$	9		$	10		$	75		$	54		$	5		$	6


^(a) (a) Settlements are recognized as they occur, once it is probable that lump sum payments from a plan for a given year will exceed the plan's total service and interest cost for that year. Such settlements were recorded for our U.S. plans in the second quarter of 2013.	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~~second quarter of ~~2012,~~2013, we recorded the effects of partial settlements of our U.S. pension ~~plans. We~~plans and we remeasured the plans' assets and liabilities as of ~~September~~June 30, ~~2012 and,~~2013, using a discount rate of 4.14 percent as of that date. As a result, we recognized ~~settlement expense along with an increase~~a decrease of $~~103~~139 million in actuarial losses, ~~net of settlement expenses. The net increase in actuarial losses is reported~~ in other comprehensive income.

During the first ~~nine~~six months of ~~2012~~2013, we made contributions of $~~162~~28 million to our funded pension plans. We expect to make additional contributions up to an estimated $239 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 $710 million and $127 million during the first ~~nine~~six months of ~~2012~~2013.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~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 in “Corporate and other unallocated items” in Note 8.6.

Our effective income tax ~~rate~~rates in the first ~~nine~~six months of ~~2012~~2013 ~~was~~and 2012 were 72 percent and 71 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~~six months of 2013 and 2012, an estimated annual effective tax ~~rate was~~rates were 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.~~periods. Excluding Libya, the effective tax ~~rate~~rates would be63 percent and 64 percent for the first ~~nine~~six 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

~~If the unrecognized tax benefits as 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.~~

~~MARATHON OIL CORPORATION~~

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

~~11.~~9. Inventories

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


	September 30,		December 31,		June 30,		December 31,
(In millions)	2012		2011		2013		2012
Liquid hydrocarbons, natural gas and bitumen	$	72	$	147	$	48	$	73
Supplies and sundry items	252		214
Total inventories, at cost	$	324	$	361
Supplies and other items					320		288
Inventories, at cost					$	368	$	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



	June 30,			December 31,
(In millions)	2013			2012
North America E&P	$	25,129		$	23,748
International E&P	12,213			13,214
Oil Sands Mining	10,270			10,127
Corporate	484			449
Total property, plant and equipment	48,096			47,538
Less accumulated depreciation, depletion and amortization	(20,639		)	(19,266		)
Net property, plant and equipment	$	27,457		$	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 June 30, 2013, our net property, plant and equipment investment in Libya was approximately $740 million.

Exploratory well costs capitalized greater than one year after completion of drilling ~~(“suspended”)~~ were $~~207~~220 million as of ~~September~~June 30, ~~2012~~2013. The net decrease ~~in such costs~~ from December 31, ~~2011~~2012 primarily related to ~~changes~~the conveyance of our interests 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.

1412

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~13.~~11. Asset Retirement Obligations

The following summarizes the changes in asset retirement obligations during the first six months of 2013:



(In millions)
Beginning balance	$	1,783
Incurred, including acquisitions	8
Settled, including dispositions	(27		)
Accretion expense (included in depreciation, depletion and amortization)	48
Revisions to previous estimates	306
Held for sale	(39		)
Ending balance^(a)	$	2,079

^(a) Includes asset retirement obligations of $40 million classified as a short-term at June 30,2013.

12. 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~~June 30, 2013 and December 31, 2012 by fair value hierarchy level.


	September 30, 2012										June 30, 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	$	—	$	52	$	—	$	—	$	52
Interest rate	—		22		—		—		22		—		6		—		—		6
Foreign currency	—		20		—		—		20
Derivative instruments, assets	—		89		—		1		90		$	—	$	58	$	—	$	—	$	58
Derivative instruments, liabilities
Commodity	—		2		—		—		2
Foreign currency	—		1		—		—		1		$	—	$	30	$	—	$	—	$	30
Derivative instruments, liabilities	$	—	$	3	$	—	$	—	$	3	$	—	$	30	$	—	$	—	$	30



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

Commodity swaps in Level 2 are measured at fair value with a market approach using prices obtained from exchanges or pricing services, which have been corroborated with data from active markets for similar assets ~~and~~or liabilities. Commodity options in Level 2 are valued using ~~The~~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~~

MARATHON OIL CORPORATION

Notes 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~~.Consolidated Financial Statements (Unaudited)

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 June 30,
	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	$	—	$	—	$	—	$	—	$	—	$	1


	Nine Months Ended September 30,								Six Months Ended June 30,
	2012				2011				2013				2012
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	77	$	271	$	226	$	282	$	—	$	38	$	75	$	263
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~~six months 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 and~~ first ~~nine~~six months of ~~2012~~2013 and ~~2011~~2012 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.

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~~June 30, ~~2012~~2013 and December 31, ~~2011~~2012:.


	September 30, 2012				December 31, 2011				June 30, 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		$	165	$	164	$	189	$	186
Total financial assets	293		292		214		216		165		164		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		6,991		6,460		7,610		6,642
Deferred credits and other liabilities	100		101		36		38		141		140		94		94
Total financial liabilities	$	5,752	$	4,767	$	5,515	$	4,791	$	7,145	$	6,613	$	7,717	$	6,749

^(a) Excludes capital leases.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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.~~13. Derivatives

For information regarding the fair value measurement of derivative instruments, see Note ~~13.~~12. 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 June 30, 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~~June 30, 2013 and December 31, 2012.


	September 30, 2012							June 30, 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	$	6	$	—	$	6	Other noncurrent assets
Total Designated Hedges	42		—		42			6		—		6

Not Designated as Hedges
Commodity	30		—		30		Other current assets	52		—		52		Other current assets
Commodity	20		—		20		Other noncurrent assets
Total Not Designated as Hedges	50		—		50			52		—		52
Total	$	92	$	—	$	92		$	58	$	—	$	58



	June 30, 2013
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	30	$	30	Other current liabilities
Total Designated Hedges	—		30		30
Total	$	—	$	30	$	30


	September 30, 2012							December 31, 2012
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	1	$	1	Other current liabilities	$	18	$	—	$	18	Other current assets
Interest rate								21		—		21		Other noncurrent assets
Total Designated Hedges	—		1		1			39		—		39

Not Designated as Hedges
Commodity	—		5		5		Other current liabilities	52		—		52		Other current assets
Total Not Designated as Hedges	—		5		5			52		—		52
Total	$	—	$	6	$	6		$	91	$	—	$	91

~~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.~~MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Derivatives Designated as Fair Value Hedges

As of ~~September~~June 30, 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~~4.68 percent and 4.70 percent.

As of ~~September~~June 30, 2013 and December 31, 2012, our foreign currency forwards had an aggregate notional amount of ~~3,939~~2,965 million and 3,043 million Norwegian Kroner at a weighted average forward rate of ~~5.911~~5.738 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~~December 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 June 30,						Six Months Ended June 30,
(In millions)	Income Statement Location	2012			2011			2012			2011			Income Statement Location	2013			2012			2013			2012
Derivative
Interest rate	Net interest and other	$	6		$	26		$	17		$	25		Net interest and other	$	(12	)	$	12		$	(15	)	$	12
Interest rate	Loss on early extinguishment of debt	—			—			—			29
Foreign currency	Provision for income taxes	$	22		$	—		$	(18	)	$	—		Provision for income taxes	$	(21	)	$	(32	)	$	(46	)	$	(40	)
Hedged Item
Long-term debt	Net interest and other	$	(6	)	$	(26	)	$	(17	)	$	(25	)	Net interest and other	$	12		$	(12	)	$	15		$	(12	)
Long-term debt	Loss on early extinguishment of debt	—			—			—			(29		)
Accrued taxes	Provision for income taxes	$	(22	)	$	—		$	18		$	—		Provision for income taxes	$	21		$	32		$	46		$	40

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
July 2013 - December 2013	20,000	$96.29	West Texas Intermediate
July 2013 - December 2013	25,000	$109.19	Brent
Option Collars
July 2013 - December 2013	15,000	$90.00 floor / $101.17 ceiling	West Texas Intermediate
July 2013 - December 2013	15,000	$100.00 floor / $116.30 ceiling	Brent

The following table summarizes the effect of all derivative instruments not designated as hedges in our consolidated statements of income.

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,~~



		Gain (Loss)
		Three Months Ended					Six Months Ended
		June 30,					June 30,
(In millions)	Income Statement Location	2013		2012			2013		2012
Commodity	Sales and other operating revenues, including related party	$	67	$	(1	)	$	13	$	2

1816

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.~~14. 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~~six months 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	1,381,321		^(a)		$32.85	1,087,731			$32.38
Options Exercised/Stock Vested	(1,256,318	)			$18.25	(1,142,195	)		$25.18	(1,422,488	)			$21.53	(605,209	)		$29.73
Cancelled	(509,748	)			$28.29	(287,278	)		$27.96	(386,186	)			$34.54	(182,958	)		$29.35
Outstanding at September 30, 2012	21,463,521				$25.47	4,444,249			$28.72
Outstanding at June 30, 2013										19,109,612				$26.85	4,477,448			$29.79

^(a) The weighted average grant date fair value of stock option awards granted was $~~9.94~~10.25 per share.

Performance ~~Unit Awards~~unit awards

~~During~~In 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~~15. Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss to net income in their entirety:

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 June 30, 2013			Six Months Ended June 30, 2013
(In millions)	Three Months Ended June 30, 2013			Six Months Ended June 30, 2013			Income Statement Line
Accumulated Other Comprehensive Loss Components
	Income (Expense)
Amortization of postretirement and postemployment plans
Actuarial loss	$	(16	)	$	(29	)	General and administrative
Net settlement loss	(17		)	(17		)	General and administrative
	12			17			Provision for income taxes
Total reclassifications for the period	$	(21	)	$	(29	)	Net income

1917

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

~~18.~~16. Supplemental Cash Flow Information



	Six Months Ended June 30,
(In millions)	2013			2012
Net cash provided from operating activities:
Interest paid (net of amounts capitalized)	$	160		$	113
Income taxes paid to taxing authorities	2,474			2,317
Commercial paper, net:
Commercial paper - issuances	$	2,075		$	4,252
- repayments	(2,275		)	(3,702		)
Noncash investing activities:
Asset retirement costs capitalized	$	314		$	34
Debt payments made by United States Steel	—			14
Change in capital expenditure accrual	(149		)	159
Asset retirement obligations assumed by buyer	92			7
Receivable for disposal of assets	50			—

17. 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~~June 30, ~~2012~~ ~~and~~ ~~December 31, 2011~~2013, Marathon’s contract commitments to acquire property, plant and equipment were $~~974 million~~ ~~and~~ ~~$664~~1,122 million.

2018

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; and

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~~second quarter of ~~2012,~~2013, notable items were:

~~Net liquid hydrocarbon and natural gas~~

Total net sales volumes ~~of 452~~averaged 506 thousand barrels of oil equivalent per day (“mboed”), ~~of which 65~~a 12 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 87 percent~~ increase over the same quarter of last year

North America E&P net sales volumes increased 38 percent over the same quarter of last year

Eagle Ford shale averaged net sales volumes of 80 mboed, a 286 percent increase

Bakken shale averaged net sales volumes of 39 mboed, a 49 percent increase

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

Successful appraisal well on non-operated Gunflint prospect in the Gulf of Mexico announced by operator

Two Gulf of Mexico leases from Lease Sale 227 awarded to us

Entered into agreement to sell our working interest in Angola Block 31 in a transaction valued at $1.5 billion before closing adjustments

Concluded exploration activities in Poland

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

~~Assumed operatorship of the Vilje field offshore Norway~~interests in DJ Basin and recorded a $114 million loss on sale

Some significant ~~fourth~~third quarter activities ~~through~~to ~~November 7, 2012~~August 8, 2013 include:

~~Closed acquisition of an additional 4,300 net acres in the core of the Eagle Ford shale~~

~~Signed agreement for a 20~~Increased dividend 12 percent ~~non-operated interest in the South Omo concession onshore Ethiopia~~

~~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 in the Harir and Safen blocks in the Kurdistan Region of Iraq~~

~~Issued $2 billion of senior notes~~to 19 cents per share

2119

Overview and Outlook

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

Production

Net liquid hydrocarbon and natural gas sales volumes averaged ~~452~~201 mboed and 200 mboed during the ~~third~~second quarter and ~~414~~first six months of 2013 compared to 146 mboed in ~~the first~~ ~~nine~~ ~~months~~both periods of 2012 ~~compared to 349 mboed and 362 mboed~~, for increases of approximately 37 percent in ~~the same periods of 2011.~~both periods. Net liquid hydrocarbon sales volumes increased ~~in the U.S.~~ for both the ~~third~~quarter and the first ~~nine~~six months of ~~2012~~,2013, 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 during the same periods due to the sale of our Alaska assets in January 2013. Excluding the sales ~~from Libya~~volume related to Alaska 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,~~both six-month periods, our average net liquid hydrocarbon and natural gas sales volumes ~~from the U.K. were lower~~increased 50 percent.

Eagle Ford – In 2013, production growth continued in the ~~2012 periods than~~Eagle Ford shale play. Average net sales volumes were 80 mboed and 76 mboed in the second quarter and first six months of 2013 compared to 21 mboed and 18 mboed in the same periods of ~~2011 due~~2012. Approximately 63 percent of the first six months of 2013 production was crude oil and condensate, 17 percent was natural gas liquids ("NGLs") and 20 percent was natural gas. In the second quarter of 2013, we increased the amount of crude oil and condensate transported by pipeline to ~~turnarounds~~70 percent from 65 percent in the ~~third quarter~~previous quarter. The ability to transport more barrels by pipeline enables us to reduce costs, improve reliability and ~~the timing of liftings.~~lessen our environmental footprint.

~~In 2012,~~During the second quarter of 2013, we ~~continued~~reached total depth on 82 gross operated wells and brought 70 gross operated wells 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~~with 158 gross operated wells reaching total depth and ~~25 mboed~~138 gross operated wells brought on line in the ~~third~~ ~~quarter and~~ first ~~nine~~six months of ~~2012~~2013. ~~As announced in August, we have reduced~~With approximately 85 percent pad drilling, which continues to improve efficiencies and reduce costs, our ~~rig count to~~second quarter average spud-to-total depth time was 12 days and spud-to-spud was 18 ~~operated rigs while maintaining four dedicated hydraulic fracturing crews and two more on a spot basis. During the~~ days.

~~third~~ ~~quarter of~~ ~~2012~~, we drilled 78 gross wells and brought 73 gross wells to sales for a total of 180 gross wells drilled in the first nine months of 2012. Our average time 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 during 2012, an increase of approximately 20 wells 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. 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 ~~operating area. We are now able to transport approximately 60 percent of our~~ Eagle Ford ~~production by pipeline.~~operating area, approximately 170 miles of gathering lines were installed in the first six months of 2013, bringing the total to more than 650 miles. We also commissioned six new central gathering and treating facilities and have three additional facilities in various stages of planning or construction, bringing the total to 27.

We continue to evaluate the potential of downspacing to 40-acre and 60-acre units, with the results of the downspacing pilots expected to be released in December 2013. We also continue to evaluate the Austin Chalk and Pearsall formations across our acreage position. To date, we have completed four Austin Chalk wells with average 24-hour initial production ("IP") rates of 980 gross barrels of oil equivalent per day (“boed”) (485 barrels per day ("bbld") of crude oil and condensate, 220 bbld of NGLs and 1.65 million cubic feet per day ("mmcfd") of natural gas). Early Austin Chalk production results suggest that the mix of crude oil and condensate, NGLs and natural gas is similar to Eagle Ford condensate wells. Also in the second quarter of 2013, one Pearsall well was completed with a 24-hour IP rate of 580 gross boed.

Bakken – Average net sales volumes from the Bakken shale were 3039 mboed and 2738 mboed in the ~~third~~second quarter and first ~~nine~~six months ~~months~~ of ~~2012~~2013 compared to ~~17 mboed and 15~~26 mboed in the same periods 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~~second quarter ~~and first~~ ~~nine~~ ~~months~~ of ~~2012~~2013, we ~~drilled 25~~reached total depth on 22 gross operated wells and 72brought 16 gross operated wells ~~with seven rigs, with a total of 30 gross and 77 gross wells brought~~ to ~~sales in~~sales. During the ~~third~~ ~~quarter and the~~ first ~~nine~~six months of 2013~~2012. By the end of October 2012,~~ we ~~had reduced our~~reached total depth on 40 gross operated ~~rig count in the Bakken shale~~wells and brought 38 gross operated wells to ~~five. We continue~~sales. Our second quarter average time to ~~focus on downspacing~~drill a well continued to improve, averaging 15 days spud-to-total depth and ~~development in the Three Forks area.~~22 days spud-to-spud.

InOklahoma Resource Basins – Net sales volumes from the Anadarko Woodford shale ~~net sales volumes~~ averaged 1013 mboed ~~and 7 mboed during~~in the ~~third~~second quarter and first ~~nine~~six months ~~months~~ of ~~2012~~2013 compared to 26 mboed and 25 mboed in the same periods of ~~2011.~~2012. During the ~~third~~second quarter of ~~2012~~2013, ~~eight~~we reached total depth on two gross operated wells and three gross operated wells were brought to sales, ~~with 14 gross wells brought to sales in the first~~ ~~nine~~ ~~months of~~ ~~2012~~. As announced in August, in response to the continued decline in natural gas liquids prices 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. Future 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~~while during the ~~third~~ ~~quarter and~~ first ~~nine~~six months of ~~2012, net sales volumes averaged 53 mboed~~2013 we reached total depth on two gross operated wells and ~~51 mboed.~~brought seven gross operated wells to sales. We ~~and our partners~~anticipate drilling will begin on two wells each in the ~~Waha concessions continue to assess~~Mississippi Lime formation in central Oklahoma and the ~~condition~~Granite Wash formation in northwestern Oklahoma during the second half of ~~our assets in Libya and uncertainty around sustained production and sales levels remains.~~2013.

~~In June 2012, we submitted a plan for the development and operation~~Exploration

Gulf of ~~the Boyla field (PL 340)~~Mexico – Late in the ~~North Sea~~third quarter of 2013, we expect to begin drilling the ~~Norwegian Ministry of Petroleum and Energy, which was approved in October 2012. The Boyla field is~~first exploration well on the Madagascar prospect located ~~approximately 17 miles south of~~on De Soto Canyon Block 757. We reduced our ~~operated Alvheim field. We hold a 65 percent~~ working interest in the ~~field. First production~~Madagascar prospect from ~~Boyla is expected~~100 percent to 70 percent as a result of a farm-down in ~~the fourth quarter of 2014.~~

In the second quarter of ~~2012, we completed~~2013 with no up-front cash proceeds. We anticipate further reducing our interest to a ~~four-day turnaround~~target of 40 to 50 percent working interest by the time of drilling.

We participated in ~~Norway that was originally scheduled for 14 days in~~an appraisal well on the ~~third quarter. During the third quarter of 2012, we became operator of the Vilje field offshore Norway~~Gunflint prospect located on Mississippi Canyon Block 992 in which we ~~own~~hold an 18 percent non-operated working interest. The appraisal well successfully encountered 109 feet of net pay within the primary reservoir targets. After penetrating the initial appraisal targets, the well was deepened to 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~~previously untested Lower Miocene interval. Commercial hydrocarbons were not encountered 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 performeddeeper exploration objective. Additional exploration potential

2220

remains in an ~~evaluation~~adjacent structure to the north, which is a candidate for future exploration following development 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~~confirmed resources.

The first 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~~non-operated working interest, is currently drilling. In the third quarter of 2012, we resumed drilling the exploration well on the Gulf of Mexico Innsbruck prospect on Mississippi Canyon Block 993 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 reachingreached 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 where we hold a 51 percent working interest in 10 operated concessions and a 100 percent working interest in one concession. We have drilled 4 exploratory wells and are currently 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.

~~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~~This appraisal well successfully encountered more than 1,000 net feet of oil pay in multiple high-quality Lower Tertiary-aged reservoirs.

In March 2013, we submitted bids totaling $33 million for 100 percent working interest in two blocks in the ~~farm out discussed~~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. These leases were awarded to us in the second quarter of 2013.

Canada – During the first quarter of 2012, we submitted a regulatory application relating to our Canada in-situ assets at Birchwood, for a proposed 12 thousand barrels per day ("mbbld") steam assisted gravity drainage ("SAGD") demonstration project. We are expecting to receive regulatory approval for this project in 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 262 mboed and 268 mboed during the second quarter and first six months of 2013 compared to 261 mboed and 249 mboed in the same periods of 2012, which is flat for the quarter and an increase of 8 percent for the six-month period. During the first six months of 2013, Libya net liquid hydrocarbon and natural gas sales volumes increased 5 mboed and 13 mboed, compared to the same periods of 2012, primarily due to limited resumption of sales in early 2012 after the 2011 civil unrest. In addition, both the second quarter and first six months of 2013 include 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.

Equatorial Guinea – Average net sales volumes were 97 mboed and 105 mboed in the second quarter and first six months compared to 101 mboed and 103 mboed in the same periods of 2012. The planned turnaround that occurred in April 2013 was safely completed in 22 days, eight days ahead of schedule and below webudget. Sales in the second quarter of 2013 were impacted by the turnaround, but operational availability of 98 percent in the first quarter of 2013 bolstered sales for the six-month period.

Norway – The production decline in the Alvheim area continues to be less than expected. Average net sales volumes from Norway were 88 mboed in both the second quarter and first six months of 2013 compared to 86 mboed and 92 mboed in the same periods of 2012. These better-than-expected results have been achieved through continued strong operational performance that delivered availability of approximately 96 percent in the second quarter and 97 percent in the first quarter of 2013; production optimization from well management; and reservoir and well performance at the upper end of expectations primarily due to a delay in anticipated water breakthrough at the Volund field. A planned 10-day turnaround in Norway is scheduled during the third quarter of 2013.

United Kingdom – Production at non-operated Foinaven was shut-in in mid-July 2013 due to compression and subsea equipment issues and is expected to resume at partial rates in mid-August. Planned pipeline curtailments and a turnaround at Brae in the North Sea in the second half of 2013 will also reduce third quarter 2013 production.

Exploration

Kurdistan Region of Iraq – We hold 45 percent operated working interests in both the Harir and Safen blocks. OnCurrent exploratory drilling includes the Mirawa well which began in March 2013 on the Harir Block and the Safen well which commenced drilling in April 2013 on the Safen Block. The Mirawa well reached total depth in July 2013 and is currently testing. The Safen well is expected to reach projected total depth in August 2013, with testing programs to follow.

Additionally, following the successful appraisal program on the non-operated Atrush ~~block, we participated~~Block a declaration of commerciality was filed with the government in ~~an appraisal well during~~2012, and a plan of development was filed in May 2013. The development plan is currently under review with final approval expected in the third quarter of ~~2012. Additionally, we participated~~2013. We anticipate first production in ~~a non-operated~~2015. The Atrush-3 appraisal well ~~that commenced drilling on the Sarsang block in September 2012.~~has reached total depth and is currently testing. We hold a 2015 percent non-operated working interest in the Atrush Block.

On the non-operated Sarsang block, two exploration wells, the Mangesh and the Gara, began drilling in the second half of 2012 and have reached total depth, with testing programs ongoing. Also on the Sarsang block, the East Swara Tika exploration well began drilling in July 2013 to test additional resource potential to the northeast of the previously announced Swara Tika discovery. We hold a 25 percent working interest in the Sarsang Block.

Ethiopia – The Sabisa-1 exploration well, on the onshore South Omo block in a frontier rift basin, encountered reservoir quality sands, oil and heavy gas shows and a thick shale section. The presence of oil prone source rocks, reservoir sands and good seals is encouraging for the numerous fault bounded traps identified in the basin. Because of mechanical issues, the well was abandoned before a full evaluation could be completed. The rig will mobilize to the nearby Tultule prospect, approximately two miles from the Sabisa-1 during the second half of 2013. We hold a 20 percent non-operated working interest in the South Omo block.

~~During~~Gabon – Exploration drilling began in April 2013 on the Diaman well in the Diaba License G4-223, offshore Gabon, to test the deepwater presalt play. The well reached total depth in the third quarter of 2013. Logging and evaluation are underway. We hold a 21 percent non-operated working interest in the Diaba License.

Norway – We commenced drilling of the Sverdrup exploration well on PL 330 offshore Norway in June 2013 and total depth is expected to be reached in early September 2013. We hold a 30 percent non-operated working interest in this license. 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 ~~Birchwood oil sands lease~~Paleocene objective section, although no hydrocarbons were found in the Cretaceous section and the well has been plugged and abandoned.

Poland – After an extensive evaluation of our exploration activities in Poland and unsuccessful attempts to find commercial levels of hydrocarbons, we have elected to conclude operations in the country. We are evaluating disposition options for our concessions.

Kenya – The first exploratory well on Block 9 is expected to commence before the end of 2013 onshore Kenya where we hold a 50 percent non-operated working interest.

Angola – The Kaombo development, located in Alberta, Canada, we conducted a seismic survey and drilled six water wells. We also submitted a regulatory application for a proposed 12 thousand barrel per day (“mbbld”) steam assisted gravity drainage ("SAGD") project at Birchwood. Pending regulatory approval, project sanctionthe southeastern portion of Block 32, is expected be sanctioned late in ~~2014, with first oil projected~~2013 so that production from the Kaombo development is possible in 2017. ~~We have~~

Oil Sands Mining

Our Oil Sands Mining operations consist of a ~~100~~20 percent non-operated working interest in the Athabasca Oil Sands Project (“AOSP”). Our net synthetic crude oil sales were 43 mbbld and 47 mbbld in the second quarter and first six months of 2013 compared to 44 mbbld in each of the same periods of 2012. Sales were relatively flat in all periods with the exception of the first six months of 2013. The impact of strong reliability experienced at both mines and the upgrader during the first quarter of 2013 was partially offset by unplanned mine downtime and a planned turnaround during the second quarter of 2013.

Acquisitions and Dispositions

In June 2013, we entered into an agreement to sell our non-operated 10 percent working interest in ~~Birchwood.~~the Production Sharing Contract and Joint Operating Agreement in Block 31 offshore Angola. This transaction, valued at $1.5 billion before closing adjustments, is expected to close in the fourth quarter of 2013, subject to government, regulatory and third-party approvals.

~~Acquisitions~~In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A pretax loss of $114 million was recorded in the second quarter of 2013.

In February 2013, we conveyed 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 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 which was collected in July 2013. After closing adjustments made in the second quarter of 2013, the pretax gain on this sale was $55 million.

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.

As previously disclosed, we had engaged in discussions with respect to a potential sale of a portion of our 20 percent outside-operated interest in the AOSP. An agreement was not reached with the prospective purchaser and ~~Dispositions~~negotiations have been terminated. We are not engaged in further discussions with respect to a potential sale of these assets.

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 approximately $1.1 billion in~~agreed upon or completed 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$2.9 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.

The above discussions include forward-looking statements with respect to ~~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, ~~the sale of our Alaska assets,~~ possible increased recoverable resources from optimized well spacing in the Eagle Ford resource play, planned infrastructure improvements in the

Eagle Ford operating area, additional farm-down of our working interest in the ~~expected closing~~Madagascar prospect in the Gulf of ~~an agreement in Ethiopia,~~Mexico, anticipated exploration activity in ~~Ethiopia, Gabon, Poland and~~the Gulf of Mexico, the Kurdistan Region of Iraq, Ethiopia, Gabon, Norway, and Kenya, the development of our in-situ assets, a planned turnaround in Norway, planned pipeline curtailments and turnaround at Brae in the North Sea, expected timing and rate of production returning at Foinaven, the timing of ~~the commencement~~approval of ~~construction~~a plan of development and first ~~oil on~~production for the ~~SAGD project. The~~Atrush Block, plans to exit Poland, the timing of closing the sale of our 10 percent working interest in Block 31 offshore Angola, and the projected asset dispositions through ~~2013 are based on current~~2013. The average times to drill a well and expectations ~~estimates, and projections and are~~as to future drilling times may not ~~guarantees~~be indicative of future ~~performance.~~drilling times. The current production rates may not be indicative of future production rates. 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, planned infrastructure improvements in the Eagle Ford operating area, anticipated exploratory activity in the Gulf of Mexico, the Kurdistan Region of Iraq, Ethiopia, Gabon, Norway, and ~~anticipated drilling rig~~Kenya, a planned turnaround in Norway and ~~drilling activity~~planned pipeline curtailments and turnaround at Brae in the North Sea 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~~10 percent working interest in Block 31 offshore Angola is subject to the satisfaction of customary closing conditions and obtaining necessary government, regulatory and ~~regulatory approvals and customary closing conditions. The agreement in Ethiopia is subject to government~~third-party approvals. The expected timing and rate of production returning at Foinaven, additional farm-down of the our working interest in the Madagascar prospect in the Gulf of Mexico, plans to exit Poland, the timing of ~~commencement~~approval of ~~construction~~a plan of development and first ~~oil on~~production 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~~second quarter and first six months~~nine~~ ~~months~~ 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 June 30,				Six Months Ended June 30,
Benchmark	2013		2012		2013	2012
West Texas Intermediate ("WTI") crude oil (Dollars per barrel)		$94.17		$93.35	$94.26	$98.15
Brent (Europe) crude oil (Dollars per barrel)		$102.58		$108.42	$107.54	$113.45
Henry Hub natural gas (Dollars per million British thermal units ("mmbtu"))^(a)		$4.09		$2.22	$3.71	$2.48


^(a)	Settlement date average.

North America E&P

~~Average~~Liquid hydrocarbons – The quality, location and composition of our liquid hydrocarbon production mix can cause our U.S. liquid hydrocarbon realizations to differ from the WTI benchmark.

Quality – 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 light sweet crude has been increasing as onshore production from the Eagle Ford and Bakken shale plays increases and production from the Gulf of Mexico declines. In the ~~third~~second quarter and first six months ~~quarter~~ of ~~2012~~2013, the percentage of our U.S. crude oil and condensate production that was sweet averaged 75 percent and 74 percent compared to ~~the same quarter of~~ ~~2011~~. Our international crude oil production is relatively sweet 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 2012 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 6245 percent in the same periods of ~~2011~~2012. ~~Reduced production~~

Location – In recent years, crude oil sold along the United States Gulf Coast, such as that from the ~~Gulf of Mexico and increased onshore production from the Bakken and~~ Eagle Ford shale, ~~plays contributed~~has been priced based on the Louisiana Light Sweet benchmark which prices at a premium to ~~the lower sour crude percentage in 2012. Sour crude oil contains more sulfur than light sweet WTI. Sour crude oil also tends~~WTI and tracks closest to ~~be heavier than and sells~~Brent, while production from inland areas farther from large refineries has been at a discount to ~~light sweet crude oil because~~WTI.

Composition – The proportion of ~~its higher refining costs~~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 second quarter and ~~lower refined product values.~~first six months of 2013 compared to 9 percent in the same periods of 2012.

Natural gas –A significant portion of our natural gas production in ~~the lower 48 states of~~ the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas. Average Henry Hub settlement prices for natural gas were ~~lower~~84 percent and 50 percent higher for the ~~third~~second quarter and first six months~~nine~~ ~~months~~ of ~~2012~~2013 compared to the same periods 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~~both the second quarter and ~~continued into 2012. Although prices have stabilized recently, they have not increased appreciably.~~ first six months of 2013 than the same periods 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"). InA decrease in the WTI benchmark prices, coupled with a higher WCS discount from WTI in the first six months of 2013 compared to same period of 2012, created downward pressure on our average realizations. However, in the second quarter of 2013 compared to the second quarter of 2012, the WCS discount from WTI has ~~increased, bringing down our average price realizations. Output mix can be impacted by operational problems or planned unit outages~~narrowed, with the discount remaining at ~~the mines or upgrader.~~these lower levels into July 2013.

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~~second quarter and first six months~~nine~~ ~~months~~ of ~~2012~~2013 and ~~2011~~2012:


	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended June 30,				Six Months Ended June 30,
Benchmark	2012	2011	2012	2011	2013		2012		2013	2012
WTI crude oil (Dollars per barrel)	$92.20	$89.54	$96.16	$95.47		$94.17		$93.35	$94.26	$98.15
Western Canadian Select (Dollars per barrel)^(a)	$70.49	$72.14	$74.21	$76.10
WCS crude oil (Dollars per barrel)^(a)						$75.06		$70.63	$68.74		$76.07
AECO natural gas sales index (Dollars per mmbtu)^(b)	$2.27	$3.70	$2.03	$3.86		$3.45		$1.84	$3.31		$2.04


^(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~~second quarter and first six months ~~quarter~~ of ~~2012~~2013 was 33approximately 6 percent higher than in the same ~~period~~periods of ~~2011~~2012 primarily ~~due~~related to ~~the previously discussed resumption of our operations~~increases in ~~Libya.~~sales volumes. The effective tax rate was 7472 percent in the ~~third~~first six months ~~quarter~~ of ~~2012~~2013 compared to 6971 percent in the ~~third~~first six months ~~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~~Sales and other operating revenues, including related party ~~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 ~~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 June 30,				Six Months Ended June 30,
(In millions)	2013		2012		2013		2012
Sales and other operating revenues, including related party:
North America E&P	$	1,284	$	833	$	2,499	$	1,745
International E&P	1,732		1,813		3,619		3,476
Oil Sands Mining	353		329		741		698
Segment sales and other operating revenues, including related party	$	3,369	$	2,975	$	6,859	$	5,919
Unrealized gain (loss) on crude oil derivative instruments	50		—		—		—
Total sales and other operating revenues, including related party	$	3,419	$	2,975	$	6,859	$	5,919

~~E&P segment~~Total sales and other operating revenuesincreased $444 million ~~increased $307~~and $940 million in the ~~third~~second quarter and ~~$539 million in the~~ first six months~~nine~~ ~~months~~ of ~~2012~~2013 from the comparable prior-year periods. ~~Included~~The $451 million and $754 million increases in ~~our~~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 2012 due to market dynamics and related commodity prices have also been lower in 2012. See 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~~second quarter and first six months of 2013 were primarily due to liquid hydrocarbon net sales volumes which increased ~~nine~~59 percent ~~months~~over the same periods of 2012, primarily ~~as a result of increased liquid hydrocarbon sales volumes from our U.S.~~due to ongoing development programs in the Eagle Ford and Bakken shale resources plays. ~~Lower liquid hydrocarbon and natural gas realizations partially offset the volume impact.~~

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 June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
North America E&P Operating Statistics
Net liquid hydrocarbon sales volumes (mbbld) ^(a)	148	93	145	91
Liquid hydrocarbon average realizations (per bbl) ^{(b) (c)}	$84.51	$84.72	$85.30	$89.23
Net crude oil and condensate sales volumes (mbbld)	126	85	124	83
Crude oil and condensate average realizations (per bbl) ^(b)	$93.75	$89.04	$94.20	$93.25
Net natural gas liquids sales volumes (mbbld)	22	8	21	8
Natural gas liquids average realizations (per bbl) ^(b)	$31.72	$40.54	$33.51	$45.65

Net natural gas sales volumes (mmcfd)	316	319	328	331
Natural gas average realizations (per mcf)^(b)	$4.19	$3.42	$4.02	$3.79


~~(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 average liquid hydrocarbon realizations by $1.22 per bbl and $0.45 per bbl for the second quarter and first six months of 2013. There were no realized gains (losses) on crude oil derivative instruments in the second quarter and first six months of 2012.

As compared to prior year periods, International E&P sales and ~~natural gas liquids.~~

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

~~Revenues from our international operations are higher~~other operating revenues decreased $81 million in the ~~third~~second quarter of 2013 due to lower liquid hydrocarbon realizations and increased $143 million in the first ~~nine~~six months of ~~2012~~ ~~primarily~~2013 as a result of ~~the previously discussed resumption of~~increased liquid hydrocarbon and natural gas sales ~~from Libya. Higher average~~volumes, partially offset by lower liquid hydrocarbon ~~realizations during the~~ ~~third~~ ~~quarter and first~~ ~~nine~~ ~~months of~~ ~~2012~~ ~~also contributed to the revenue increase for both periods.~~ realizations.

2725

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 June 30,		Six Months Ended June 30,
	2012		2011		2012		2011		2013	2012	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		93	99	96	98
Africa	88		34		73		44		84	78	82	65
Total International	182		142		170		146
Total International E&P									177	177	178	163
Liquid hydrocarbon average realizations (per bbl)^(b)
Europe	$	112.34	$	117.05	$	115.73	$	115.91	$106.41	$111.12	$111.43	$117.37
Africa	98.65		63.51		97.00		75.38		$92.92	$96.84	$94.96	$95.87
Total International	$	105.71	$	104.24	$	107.69	$	103.75
Total International E&P									$100.00	$104.82	$103.86	$108.80

Net natural gas sales (mmcfd)
Net natural gas sales volumes (mmcfd)
Europe^(c)	100		79		102		92		89	102	92	103
Africa	485		453		434		440		425	399	449	409
Total International	585		532		536		532
Total International E&P									514	501	541	512
Natural gas average realizations (per mcf)^(b)
Europe	$	10.10	$	9.81	$	10.05	$	10.07	$11.37	$10.05	$12.12	$10.02
Africa	0.63		0.24		0.39		0.24		$0.49	$0.25	$0.50	$0.25
Total International	$	2.25	$	1.67	$	2.23	$	1.95
Total International E&P									$2.37	$2.25	$2.47	$2.22


^(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 188 mmcfd and 1617 mmcfd for the ~~third~~second quarter ~~quarters~~s of ~~2012~~2013 and ~~2011~~2012, and 1610 mmcfd and 15 mmcfd for the first six months~~nine~~ ~~months~~ of ~~2012~~2013 and ~~2011~~2012.

~~OSM segment~~Oil Sands Mining sales and other operating revenuesincreased $24 million and $43 million in the ~~third~~second quarter and ~~$4 million in the~~ first six months~~nine~~ ~~months~~ of ~~2012~~2013 ~~compared to~~from the ~~same periods of~~ ~~2011. The upgrader expansion was completed and commenced operations~~comparable prior-year periods. Synthetic crude oil sales volumes were slightly lower in the ~~third~~second quarter of 2013~~2011~~ than in the ~~, resulting in higher sales volumes in both periods. However, an increase~~second quarter of 2012; however, a decrease in the discount of WCS to WTI in second quarter of 2013resulted in ~~the decreases~~increases in average realizations ~~during~~compared to the prior-year period. Synthetic crude oil sales volumes for the ~~third~~first six months ~~quarter and first~~of ~~nine~~2013 were 7 percent higher than in the first six months of 2012, ~~partially offsetting~~reflecting increased reliability of the ~~positive volume variance.~~

mines and upgrader in the first quarter of 2013. 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 June 30,		Six Months Ended June 30,
	2013	2012	2013	2012
Oil Sands Mining Operating Statistics
Net synthetic crude oil sales volumes (mbbld) ^(a)	43	44	47	44
Synthetic crude oil average realizations (per bbl)	$89.39	$79.31	$84.31	$85.07


^(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~~second quarter ~~and first nine months~~ of ~~2012,~~2013, the net unrealized gain on crude oil derivative instruments was ~~$45~~$50 million while unrealized gains and ~~there~~losses did not have a significant impact on the first six months of 2013. There was no comparable crude oil derivative activity in ~~similar~~the same periods of ~~2011.~~2012. See Note 1413 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 $258 million and $677 million in the second quarter and first six months of 2013 from the comparable prior-year periods. 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. 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~~17 million and $57 million in the second quarter and first six months~~nine~~ ~~months~~ of ~~2012~~2013 from the comparable prior-year ~~period,~~periods, primarily due to ~~lower natural gas prices and turnarounds early in 2012 at our facilities in Equatorial Guinea. Also, in January 2012, we sold our equity investments in several Gulf of Mexico crude oil pipelines.~~higher LNG net sales volumes.

Net gain (loss) on disposal of assets in the ~~third~~second quarter ~~quarter~~ of ~~2012~~2013 ~~primarily reflects an $18~~includes a $114 million loss on the sale of ~~undeveloped acreage outside~~our interests in the ~~core~~DJ Basin. In addition, the first six months of 2013 include a $98 million gain on the sale of our interest in the Neptune gas plant, a $55 million gain on the sale of our remaining assets in Alaska and a $43 million loss on the conveyance of our interests in the Marcellus natural gas shale play to the operator. The net loss on disposal of assets in the second quarter of 2012 reflects $36 million to settle all obligations as a result of the ~~Eagle Ford shale resource play.~~assignment of exploration licenses in Indonesia. The net gain on disposal of assets in the first six months~~nine~~ ~~months~~ 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.~~second quarter Indonesia loss. See Note 75 to the consolidated financial statements for information about these dispositions.

~~Cost of revenuesdecreased~~Production expenses increased $~~304~~129 million and $~~666~~205 million in the ~~third~~second quarter and first six months~~nine~~ ~~months~~ of ~~2012~~2013 from the comparable periods of ~~2011~~2012. The increases are primarily related to increased sales volumes in the North America E&P and International E&P segments and a planned turnaround in the OSM segment during the second quarter of 2013.

Marketing expenses ~~primarily due to our supply optimization activities. Volumes associated~~decreased $260 million and $685 million in the second quarter and first six months of 2013 from the same periods of 2012, consistent with ~~supply optimization have been decreasing~~the marketing revenue decline discussed above.

Exploration expenseswere lower in the second quarter of 2013 than in the same quarter in 2012 due to ~~market dynamics~~lower dry well costs and ~~related commodity prices have also been lower~~geological and geophysical costs. Exploration costs were higher in ~~2012. Comparatively, costs related to supply optimization were lower by $438 million for~~ the ~~third~~first six months ~~quarter and by $677 million for~~of 2013 than in the ~~first~~ ~~nine~~ ~~months~~same period of 2012. Excluding the impact of supply optimization activities, E&P segment operating expenses have increased in proportion to our increased production from U.S. shale plays. Additionally, Integrated Gas segment costs are lower in 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 June 30,				Six Months Ended June 30,
(In millions)	2013		2012		2013		2012
Unproved property impairments	$	40	$	35	$	423	$	70
Dry well costs	50		81		71		104
Geological and geophysical	12		29		39		74
Other	31		27		65		59
Total exploration expenses	$	133	$	172	$	598	$	307

Depreciation, depletion and amortization (“DD&A”) increased $~~108~~158 million and $331 million in the ~~third~~second quarter and first six months~~$63 million~~ ~~in the first~~ ~~nine~~ ~~months~~ of ~~2012~~2013 from the comparable prior-year periods. ~~Because both our E&P and OSM~~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.~~An increase in the North America E&P DD&A rate in the second quarter and first six months of 2013 compared to the same prior-year periods was primarily due to the ongoing development programs in the Eagle Ford and Bakken shale resources plays. A lower International E&P DD&A ~~rates~~rate in the ~~third~~second quarter and first ~~nine~~six months ~~months~~of 2013, primarily due to reserve increases at the end of 2012 and in the second quarter of 2013 for Norway, compared to the same periods in ~~2011~~2012 partially offset the impact of the higher North America E&P rate and 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 June 30,				Six Months Ended June 30,
($ per boe)	2013		2012		2013		2012
DD&A rate
North America E&P		$27		$22		$27		$23
International E&P		$8		$10		$8		$9
Oil Sands Mining		$12		$13		$12		$13

Impairments in the first six months~~nine~~ ~~months~~ of ~~2012~~2013 related ~~primarily~~to the Powder River Basin and to the Ozona development in the Gulf of Mexico. Impairments in the first six months~~nine~~ ~~months~~ of ~~2011~~2012 were also 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 1312 to the consolidated financial statements for information about these impairments.

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

General and administrative expensesincreased ~~$35~~$10 million and $25 million in the ~~third~~second quarter and ~~$18 million~~ ~~in the~~ first ~~nine~~six months of ~~2012~~ ~~compared to~~2013 from the ~~same~~comparable prior year 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.

~~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~~pension settlement charges of $17 million in the second 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. 2013.

~~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 $2314 million and $9836 million in the ~~third~~second quarter and first six months~~nine~~ ~~months~~ of ~~2012~~2013 from the comparable periods of ~~2011~~2012~~. 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~~$53 million and $~~1,180~~151 million in the ~~third~~second quarter ~~quarter~~ and first ~~nine~~six months of ~~2012~~2013 from the comparable periods 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.~~income.

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~~six months of 2013 ~~months of~~and 2012 ~~was~~ were 72 ~~percent. This rate is~~percent and 71 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~~six months of 2013 and 2012 an, estimated annual effective tax ~~rate was~~rates were 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.~~periods. Excluding Libya, the effective tax ~~rate~~rates would be 63 percent and 64 percent for the first ~~nine~~six months of 2013 ~~months of~~and 2012.

~~Our effective tax rate in the first~~ ~~nine~~ ~~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.

~~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

~~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 June 30,						Six Months Ended June 30,
(In millions)	2013			2012			2013			2012
North America E&P	$	221		$	70		$	162		$	174
International E&P	382			373			835			780
Oil Sands Mining	20			50			58			88
Segment income	623			493			1,055			1,042
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(156		)	(77		)	(227		)	(148		)
Unrealized gain (loss) on crude oil derivative instruments	32			—			—			—
Net gain (loss) on dispositions	(73		)	(23		)	(9		)	83
Impairments	—			—			(10		)	(167		)
Net income	$	426		$	393		$	809		$	810

~~United States~~ North America E&P segment income increased ~~$29~~$151 million in the ~~third~~second quarter of 2013 ~~quarter~~ and ~~increased $52~~decreased $12 million in the first ~~nine~~six months of ~~2012~~2013 compared to the same periods of ~~2011~~2012. The ~~income~~ increase in ~~both periods~~the second quarter of 2013 is largely due to increased liquid hydrocarbon net sales volumes primarily in the Eagle Ford and Bakken shale resource plays. The decrease in the first six months of 2013 was primarily the result of unproved property impairments, higher ~~liquid hydrocarbon sales volumes as previously discussed, partially offset by~~DD&A and lower liquid hydrocarbon realizations, ~~and the impact of increased production operations on DD&A and operating expenses. In addition, exploration expenses were~~partially offset by higher ~~primarily due to higher unproved property impairments.~~ liquid hydrocarbon net sales volumes, as discussed above.

International E&P segment income increased ~~$127~~$9 million and $55 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~~ ~~compared to the same period of~~ ~~2011~~.

~~OSM segment incomedecreased $27 million and $36 million in the~~ ~~third~~second quarter and first six months~~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 of ~~2011~~2012. These increases were primarily related to higher liquid hydrocarbon net sales volumes and increased income from equity method investments, partially offset by higher income taxes.

Oil Sands Mining segment incomedecreased $30 million in the second quarter and first six months of 2013 compared to the same periods of 2012. These decreases are primarily due to ~~lower natural gas prices and turnarounds early in~~ ~~2012~~ ~~at our facilities in Equatorial Guinea. In addition, LNG sales volumes are lower~~higher production expenses, including the costs of the scheduled upgrader turnaround in the ~~first nine months of 2012 due to the sale of our interest in the Alaska LNG facility in the third~~second quarter of ~~2011.~~2013.

Critical Accounting Estimates

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

Accounting Standards Not Yet Adopted

31In June 2013, the Financial Accounting Standards Board ("FASB") ratified the Emerging Issues Task Force consensus on Issue 13-C, which requires that an unrecognized tax benefit or a portion of an unrecognized tax benefit be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied prospectively to unrecognized tax benefits that exist as of the effective date. Early adoption and retrospective application are permitted. We do not expect this accounting standards update to have a significant impact on our consolidated results of operations, financial position or cash flows.

Cash Flows and Liquidity

Cash Flows

Net cash provided by ~~continuing operations~~operating activities was $~~2,812~~2,396 million in the first ~~nine~~six months of ~~2012~~2013, compared to $~~4,400~~1,742 million in the first ~~nine~~six months of 2012~~2011~~, 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~~2,299 million in the first ~~nine~~six months of ~~2012~~2013, compared to $~~2,118~~2,001 million ~~related to continuing operations~~ in the first ~~nine~~six 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 $333 million and $218 million in ~~the~~ first ~~nine~~six 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 interests in our Alaska assets, the ~~first~~ ~~nine~~ ~~months~~Neptune gas plant, and the DJ Basin. 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~~543 million in the first ~~nine~~six months of ~~2012~~2013, compared to ~~net cash~~ ~~used in~~$210 million provided by financing activities ~~related to continuing operations~~in the first six months of 2012. Repayments of debt at maturity were $~~5,098~~148 million in the first ~~nine~~six months of 2013~~2011~~ and $111 million in the first six months of 2012. ~~During~~We also repaid a net $200 million of our outstanding commercial paper during the first ~~nine~~six months of 2013 compared to the same period in 2012,, when we drew a net ~~$1,839 million~~ ~~under our commercial paper program, retired $23 million principal amount of debt before it was due and repaid $88~~$550 million of ~~debt upon its maturity. During the first~~commercial paper. Dividends paid of approximately ~~nine~~$241 million ~~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 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~~June 30, ~~2012~~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 first six months of 2013, $2,075 million of commercial paper was issued and $2,275 million of commercial paper was repaid.

~~On October 29, 2012,~~At June 30, 2013, we ~~issued $1~~had $6,496 million in long-term debt outstanding, $68 million of which is due within one year. We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.

The sale of our non-operated 10 percent working interest in Block 31 offshore Angola, a transaction valued at $1.5 billion ~~aggregate principal amount~~before closing adjustments, is expected to close in the fourth quarter of ~~senior notes bearing interest at 0.9 percent with a maturity date of November 1, 2015~~2013, subject to government, regulatory 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~~third-party approvals. We expect to use the ~~senior notes is payable semi-annually beginning May 1, 2013. The~~ proceeds ~~are being used~~from this sale principally to ~~pay off commercial paper~~repurchase shares, but also to strengthen our balance sheet and for general corporate purposes.

~~In April 2012, we terminated our $3.0 billion five-year revolving credit facility and replaced it with~~Shelf Registration

We are a ~~new $2.5 billion unsecured five-year revolving credit facility (the “Credit Facility”). The Credit Facility matures in April 2017 but allows~~"well-known seasoned issuer" for purposes of SEC rules, thereby allowing 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 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.

~~We have~~use a universal shelf registration statement ~~filed with the Securities and Exchange Commission under which~~should we ~~as a well-known seasoned issuer, have the ability~~choose to issue and sell ~~an indeterminate amount of~~ various types of equity and debt securities. Beginning in the first quarter of 2013, we changed our reportable segments and ~~equity securities.~~expect to recast all periods presented to reflect these new segments in our consolidated financial statements no later than upon filing our 2013 Annual Report on Form 10-K with the SEC. When appropriate, we will update and file our universal shelf registration statement.

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 25 percent at ~~September~~June 30, ~~2012~~2013~~, compared to 20 percent at~~ and December 31, ~~2011~~2012.


	September 30,			December 31,			June 30,			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			6,428			6,512
Total debt	6,540			4,815			$	6,496		$	6,896
Cash	671			493			$	246		$	684
Equity	$	18,064		$	17,159		$	19,021		$	18,283
Calculation:
Total debt	$	6,540		$	4,815		$	6,496		$	6,896
Minus cash	671			493			246			684
Total debt minus cash	5,869			4,322			6,250			6,212
Total debt	6,540			4,815			6,496			6,896
Plus equity	18,064			17,159			19,021			18,283
Minus cash	671			493			246			684
Total debt plus equity minus cash	$	23,933		$	21,481		$	25,271		$	24,495
Cash-adjusted debt-to-capital ratio	25		%	20		%	25		%	25		%

Capital Requirements

On ~~October~~July 31, ~~2012,~~2013, our Board of Directors approved a dividend of 1719 cents per share for the ~~third~~second quarter of ~~2012~~2013, a 12 percent increase over the previous quarter, payable ~~December~~September 10, ~~2012~~2013 to stockholders of record at the close of business on ~~November~~August 21, ~~2012.~~2013.

~~In October~~As of June 30, 2013, we plan to make contributions of up to $39 million to our funded pension plans during the remainder of 2013.

Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion. As of June 30, 2013, we had repurchased 78 million common shares at a cost of $3,222 million, with 66 million shares purchased for $2,922 million prior to the spin-off of our downstream business and ~~early November 2012, we paid $264~~12 million ~~for closed acquisition transactions.~~

Inshares acquired at a cost of $300 million in the ~~first~~third quarter of ~~2012, we increased~~2011. Purchases under the program may be in either open market transactions, including block purchases, or in

privately negotiated transactions. This program may be changed based upon our ~~2012 capital, investment~~financial condition or changes in market conditions and ~~exploration budget, excluding acquisition costs, from $4.8 billion~~is subject to ~~$5.0 billion,~~termination prior to completion. The program’s authorization does not include specific price targets or timetables. The timing of ~~which $4.6 billion~~purchases under the program will be ~~used for capital expenditures. The increase reflects development plans for the additional acreage acquired in the Eagle Ford shale~~influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and ~~other adjustments.~~market conditions.

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~~regarding the timing of closing the sale of our ~~2012 capital, investment~~10 percent working interest in Block 31 offshore Angola, including the use of proceeds. The timing of closing the sale of our 10 percent working interest in Block 31 offshore Angola is subject to the satisfaction of customary closing conditions and obtaining necessary government, regulatory and third-party approvals. The expectations with respect to the use of proceeds from the sale of our 10 percent working interest in Block 31 offshore Angola could be affected by changes in the prices and demand for liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of the our exploration ~~budget.~~or production operations, unforeseen hazards such as weather conditions or acts of war or terrorist acts and other operating and economic considerations. The discussion of liquidity above also contains forward-looking statements regarding planned funding of pension plans, which are based on current expectations, estimates and projections and are not guarantees of actual performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially ~~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 June 30, 2013, our ~~consolidated~~total contractual cash obligations ~~to make future payments under existing contracts as of~~were consistent with ~~September 30,~~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.

3431

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, including underlying notional quantities, 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 1312 and 1413 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~~June 30, ~~2012~~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	$	(81	)	$	(203	)	$	81	$	203
Option Collars	(105		)	(277		)	103		275		(30		)	(92		)	34		109
Total crude oil	(312		)	(796		)	310		794		$	(111	)	$	(295	)	$	115	$	312
Natural gas
Futures	(1		)	(2		)	1		2
Total natural gas	(1		)	(2		)	1		2
Total	$	(313	)	$	(798	)	$	311	$	796

Sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of ~~September~~June 30, ~~2012~~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		$	6		^(b)	$	3
Long-term debt, including amounts due within one year	$	(5,639	)	^(b)	$	(206	)	$	(6,991	)	^(b)	$	(241	)


^(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~~June 30, ~~2012~~2013 would be ~~$69 million.~~$49 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~~Rules 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 as of June 30, 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.

3632

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						Six Months Ended
	June 30,						June 30,
(In millions)	2013			2012			2013			2012
Segment Income
North America E&P	$	221		$	70		$	162		$	174
International E&P	382			373			835			780
Oil Sands Mining	20			50			58			88
Segment income	623			493			1,055			1,042
Items not allocated to segments, net of income taxes	(197		)	(100		)	(246		)	(232		)
Net income	$	426		$	393		$	809		$	810
Capital Expenditures^(a)
North America E&P	$	904		$	1,013		$	1,874		$	1,842
International E&P	241			202			466			340
Oil Sands Mining	97			43			142			95
Corporate	15			19			45			63
Total	$	1,257		$	1,277		$	2,527		$	2,340
Exploration Expenses
North America E&P	$	76		$	147		$	511		$	253
International E&P	57			25			87			54
Total	$	133		$	172		$	598		$	307


^(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.

3733

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		Six Months Ended
	June 30,		June 30,
Net Sales Volumes	2013	2012	2013	2012
North America E&P
Crude Oil and Condensate (mbbld)	126	85	124	83
Natural Gas Liquids (mbbld)	22	8	21	8
Total Liquid Hydrocarbons	148	93	145	91
Natural Gas (mmcfd)	316	319	328	331
Total North America E&P (mboed)	201	146	200	146

International E&P
Liquid Hydrocarbons (mbbld)
Europe	93	99	96	98
Africa	84	78	82	65
Total Liquid Hydrocarbons	177	177	178	163
Natural Gas (mmcfd)
Europe^(b)	89	102	92	103
Africa	425	399	449	409
Total Natural Gas	514	501	541	512
Total International E&P (mboed)	262	261	268	249

Oil Sands Mining
Synthetic Crude Oil (mbbld)^(c)	43	44	47	44

Total Company (mboed)	506	451	515	439
Net Sales Volumes of Equity Method Investees
LNG (mtd)	5,820	5,467	6,301	5,879
Methanol (mtd)	973	1,268	1,191	1,290


^(c)(b)	Includes natural gas acquired for injection and subsequent resale of 188 mmcfd and 1617 mmcfd for the ~~third~~second quarter ~~quarters~~s of ~~2012~~2013 and ~~2011~~2012, and 1610 mmcfd and 15 mmcfd for the first six months~~nine~~ ~~months~~ of ~~2012~~2013 and ~~2011~~2012.


^(c)	Includes blendstocks.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)



	Three Months Ended				Six Months Ended
	June 30,				June 30,
Average Realizations^(d)	2013		2012		2013	2012
North America E&P
Crude Oil and Condensate (per bbl)		$93.75		$89.04	$94.20	$93.25
Natural Gas Liquids (per bbl)		$31.72		$40.54	$33.51	$45.65
Total Liquid Hydrocarbons^(e)		$84.51		$84.72	$85.30	$89.23
Natural Gas (per mcf)		$4.19		$3.42	$4.02	$3.79

International E&P
Liquid Hydrocarbons (per bbl)
Europe		$106.41		$111.12	$111.43	$117.37
Africa		$92.92		$96.84	$94.96	$95.87
Total Liquid Hydrocarbons		$100.00		$104.82	$103.86	$108.80
Natural Gas (per mcf)
Europe		$11.37		$10.05	$12.12	$10.02
Africa^(f)		$0.49		$0.25	$0.50	$0.25
Total Natural Gas		$2.37		$2.25	$2.47	$2.22

Oil Sands Mining
Synthetic Crude Oil (per bbl)		$89.39		$79.31	$84.31	$85.07


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


^(e)	Inclusion of realized gains (losses) on crude oil derivative instruments would have increased average liquid hydrocarbon realizations by $1.22 per bbl and $0.45 per bbl for the second quarter and first six months of 2013. There were no realized gains (losses) on crude oil derivative instruments in the same periods 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.

3835

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

Environmental

We executed a settlement agreement with the North Dakota Department of Health regarding voluntary disclosures of potential Clean Air Act violations made in 2009 relating to our operations on state lands in the Bakken shale and paid a fine of $169,800 in June 2013.

SEC Investigation Relating to Libya

On May 25, 2011, we received a subpoena issued by the SEC requiring production of documents related to payments made to the government of Libya, or ~~environmental proceedings during~~to officials and persons affiliated with officials of the ~~first~~ ~~nine~~ ~~months~~government of ~~2012~~.Libya. By letter dated April 26, 2013, the SEC further notified us that they completed their investigation and did not intend to recommend any enforcement action in this matter.

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~~June 30, ~~2012,~~2013, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934.

Column (a) Column (b) Column (c) Column (d)
Total Number of 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)
04/01/13 - 04/30/13	12,135	$33.64	—	$1,780,609,536
05/01/13 - 05/31/13	3,795	$32.05	—	$1,780,609,536
06/01/13 - 06/30/13	36,664	$34.84	—	$1,780,609,536
Total	52,594	$34.36	—


^(a)	~~162,184~~27,051 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

In ~~September 2012, 32,706~~June 2013, 25,543 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~~June 30, ~~2012,~~2013, 78 million split-adjusted common shares had been acquired at a cost of $3,222 million, which includes transaction fees and commissions that are not reported in the table above. Of this total, 66 million shares had been acquired at a cost of $2,922 million prior to the spin-off of the downstream business.

Item 4. Mine Safety Disclosures

Not applicable.

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~~

~~Amended By-laws of Marathon Oil Corporation, effective January 1, 2013.~~

~~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.~~

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

3.1

Restated Certificate of Incorporation of Marathon Oil Corporation.

3.2

Amended By-laws of Marathon Oil Corporation effective May 29, 2013.

3.3

Amended By-Laws of Marathon Oil Corporation effective August 1, 2013.

10.1

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

10-Q

10.4

5/4/2012

001-05153

12.1

Computation of Ratio of Earnings to Fixed Charges.

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase.

101.DEF

XBRL Taxonomy Extension Definition Linkbase.

101.LAB

XBRL Taxonomy Extension Label Linkbase.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.

4037

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~~August 8, 2013		MARATHON OIL CORPORATION

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

4138

Exhibit Index

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

3.1

Restated Certificate of Incorporation of Marathon Oil Corporation.

3.2

Amended By-laws of Marathon Oil Corporation effective May 29, 2013.

3.3

Amended By-Laws of Marathon Oil Corporation effective August 1, 2013.

10.1

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

10-Q

10.4

5/4/2012

001-05153

12.1

Computation of Ratio of Earnings to Fixed Charges.

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase.

101.DEF

XBRL Taxonomy Extension Definition Linkbase.

101.LAB

XBRL Taxonomy Extension Label Linkbase.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.



	INDEX
		Page
~~PART~~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	2119
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3532
Item 4.	Controls and Procedures	3632
	Supplemental Statistics (Unaudited)	3733
~~PART~~Part II - OTHER INFORMATION
Item 1.	Legal Proceedings	3936
Item 1A.	Risk Factors	3936
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3936
Item 4.	Mine Safety Disclosures	3937
Item 6.	Exhibits	4037
	Signatures	4138



(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



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