UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



(Mark One)
	[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the Quarterly Period Ended September 30, ~~2011~~2012



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

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)



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

5555 San Felipe ~~Road,~~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 üþ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of

Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ ü No

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



Large accelerated filer ü þ	Accelerated filer o
Non-accelerated filero (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 üþ

There were ~~703,721,720~~706,417,267 shares of Marathon Oil Corporation common stock outstanding as of October 31, ~~2011.~~2012.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended September 30, ~~2011~~2012



	INDEX
		Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)		2
	Consolidated Statements of Comprehensive Income (Unaudited)		3
	Consolidated Balance Sheets (Unaudited)		4
	Consolidated Statements of Cash Flows (Unaudited)		5
	~~Consolidated Statements of Stockholders’ Equity (Unaudited)~~		6
	Notes to Consolidated Financial Statements (Unaudited)		7	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		23	21
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		36	35
Item 4.	Controls and Procedures		36
	Supplemental Statistics (Unaudited)		37
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		39
Item 1A.	Risk Factors		39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		40	39
Item 4.	Mine Safety Disclosures	39
Item 6.	Exhibits		41	40
	Signatures		42	41

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). ~~Any reference to “Marathon” indicates Marathon Oil Corporation as it existed prior to the June 30, 2011 spin-off of the downstream business.~~

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions, except per share data)	2012			2011			2012			2011
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
Income from equity method investments	122			123			260			360
Net gain (loss) on disposal of assets	(12		)	13			126			63
Other income	17			14			43			36
Total revenues and other income	4,161			3,799			11,985			11,473
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
Depreciation, depletion and amortization	625			517			1,779			1,716
Impairments	8			—			271			307
General and administrative expenses	139			104			389			371
Other taxes	63			59			208			170
Exploration expenses	176			129			491			504
Total costs and expenses	2,379			2,466			7,334			7,923
Income from operations	1,782			1,333			4,651			3,550
Net interest and other	(53		)	(30		)	(160		)	(62		)
Loss on early extinguishment of debt	—			—			—			(279		)
Income from continuing operations
before income taxes	1,729			1,303			4,491			3,209
Provision for income taxes	1,279			898			3,231			2,051
Income from continuing operations	450			405			1,260			1,158
Discontinued operations	—			—			—			1,239
Net income	$	450		$	405		$	1,260		$	2,397
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
Dividends paid	$0.17			$0.15			$0.51			$0.65
Weighted average shares:
Basic	706			711			705			712
Diluted	709			714			709			716

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
	September 30,						September 30,
(In millions)	2012			2011			2012			2011
Net income	$	450		$	405		$	1,260		$	2,397
Other comprehensive income
Postretirement and postemployment plans
Change in actuarial loss and other	(90		)	13			(80		)	110
Spin-off downstream business	—			—			—			968
Income tax benefit (provision) on postretirement and
postemployment plans	32			6			28			(409		)
Postretirement and postemployment plans, net of tax	(58		)	19			(52		)	669
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		)
Income tax provision on foreign currency translation and other	—			—			—			—
Foreign currency translation and other, net of tax	—			—			—			(1		)
Other comprehensive income (loss)	(57		)	18			(51		)	669
Comprehensive income	$	393		$	423		$	1,209		$	3,066

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)



	September 30,			December 31,
(In millions, except per share data)	2012			2011
Assets
Current assets:
Cash and cash equivalents	$	671		$	493
Receivables	2,553			1,917
Receivables from related parties	22			35
Inventories	324			361
Prepayments	111			96
Deferred tax assets	87			99
Other current assets	269			223
Total current assets	4,037			3,224
Equity method investments	1,319			1,383
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $18,438 and $17,248	27,446			25,324
Goodwill	525			536
Other noncurrent assets	1,231			904
Total assets	$	34,558		$	31,371
Liabilities
Current liabilities:
Commercial paper	$	1,839		$	—
Accounts payable	2,335			1,864
Payables to related parties	44			18
Payroll and benefits payable	148			193
Accrued taxes	2,027			2,015
Other current liabilities	206			163
Long-term debt due within one year	183			141
Total current liabilities	6,782			4,394
Long-term debt	4,518			4,674
Deferred tax liabilities	2,495			2,544
Defined benefit postretirement plan obligations	817			789
Asset retirement obligations	1,516			1,510
Deferred credits and other liabilities	366			301
Total liabilities	16,494			14,212
Commitments and contingencies
Stockholders’ Equity
Preferred stock – no shares issued and outstanding (no par value,
26 million shares authorized)	—			—
Common stock:
Issued – 770 million and 770 million shares (par value $1 per share,
1.1 billion shares authorized)	770			770
Securities exchangeable into common stock – no shares issued and
outstanding (no par value, 29 million shares authorized)	—			—
Held in treasury, at cost – 64 million and 66 million shares	(2,607		)	(2,716		)
Additional paid-in capital	6,634			6,680
Retained earnings	13,688			12,788
Accumulated other comprehensive loss	(421		)	(370		)
Total equity of Marathon Oil's stockholders	18,064			17,152
Noncontrolling interest	—			7
Total equity	18,064			17,159
Total liabilities and stockholders' equity	$	34,558		$	31,371

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)



	Nine Months Ended
	September 30,
(In millions)	2012			2011
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	1,260		$	2,397
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		)
Depreciation, depletion and amortization	1,779			1,716
Impairments	271			307
Pension and other postretirement benefits, net	(56		)	28
Exploratory dry well costs and unproved property impairments	287			311
Net gain on disposal of assets	(126		)	(63		)
Equity method investments, net	(14		)	16
Changes in:
Current receivables	(646		)	202
Inventories	(6		)	47
Current accounts payable and accrued liabilities	156			361
All other operating, net	(66		)	113
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
Investing activities:
Acquisitions, net of cash acquired	(806		)	—
Additions to property, plant and equipment	(3,509		)	(2,437		)
Disposal of assets	193			385
Investments - return of capital	42			41
Investing activities of discontinued operations	—			(493		)
Property deposit	—			(120		)
All other investing, net	49			13
Net cash used in investing activities	(4,031		)	(2,611		)
Financing activities:
Commercial paper, net	1,839			—
Debt issuance costs	(9		)	—
Debt repayments	(111		)	(2,843		)
Purchases of common stock	—			(300		)
Dividends paid	(360		)	(462		)
Financing activities of discontinued operations	—			2,916
Distribution in spin-off	—			(1,622		)
All other financing, net	26			129
Net cash provided by (used in) financing activities	1,385			(2,182		)
Effect of exchange rate changes on cash	12			(15		)
Net increase in cash and cash equivalents	178			682
Cash and cash equivalents at beginning of period	493			3,951
Cash and cash equivalents at end of period	$	671		$	4,633

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

MARATHON OIL CORPORATION

~~Consolidated Statements of~~ ~~Income~~ ~~(Unaudited)~~

Three Months Ended Nine Months Ended
September 30, September 30,
(In millions, except per share data) 2011 2010 2011 2010
Revenues and other income:

   Sales and other operating revenues $ 3,633 $ 2,839 $ 10,969 $ 8,287
   Sales to related parties 16 15 45 41
   Income from equity method investments 123 77 360 245
   Net gain on disposal of assets 13 - 63 822
   Other income 14 24 36 52

             Total revenues and other income 3,799 2,955 11,473 9,447
Costs and expenses:
   Cost of revenues (excludes items below) 1,600 1,107 4,671 3,384
   Purchases from related parties 57 57 184 132
   Depreciation, depletion and amortization 517 530 1,716 1,376
   Impairments - - 307 439
   General and administrative expenses 104 108 371 328
   Other taxes 59 44 170 145
   Exploration expenses 129 59 504 282

            Total costs and expenses 2,466 1,905 7,923 6,086

Income from operations 1,333 1,050 3,550 3,361

   Net interest and other (30 ) (16 ) (62 ) (53 )
   Loss on early extinguishment of debt - - (279 ) (92 )

Income from continuing operations before income taxes 1,303 1,034 3,209 3,216

   Provision for income taxes 898 567 2,051 1,758

Income from continuing operations 405 467 1,158 1,458

   Discontinued operations - 229 1,239 404

Net income $ 405 $ 696 $ 2,397 $ 1,862

Per Share Data

   Basic:

       Income from continuing operations $ 0.57 $ 0.66 $ 1.63 $ 2.06
       Discontinued operations $ - $ 0.32 $ 1.74 $ 0.57
       Net income per share $ 0.57 $ 0.98 $ 3.37 $ 2.63

   Diluted:

       Income from continuing operations $ 0.57 $ 0.66 $ 1.62 $ 2.05
       Discontinued operations $ - $ 0.32 $ 1.73 $ 0.57
       Net income per share $ 0.57 $ 0.98 $ 3.35 $ 2.62

   Dividends paid $ 0.15 $ 0.25 $ 0.65 $ 0.74

   Weighted average shares:
       Basic 711 710 712 709
       Diluted 714 712 716 711

~~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
September 30, September 30,
(In millions) 2011 2010 2011 2010
Net income $ 405 $ 696 $ 2,397 $ 1,862
    Other comprehensive income

         Post-retirement and post-employment plans
            Change in actuarial gain (loss) 13 (24 ) 110 134
            Spin-off downstream business - - 968 -
            Income tax benefit  (provision) on post-retirement and
               post-employment plans 6 10 (409 ) (73 )
                  Post-retirement and post-employment plans, net of tax 19 (14 ) 669 61

         Derivative hedges
            Net unrecognized gain (loss) (1 ) 1 9 5
            Spin-off downstream business - - (7 ) -
            Income tax benefit (provision) on derivatives - 0 (1 ) -
                  Derivative hedges, net of tax (1 ) 1 1 5

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

Other comprehensive income 18 (13 ) 669 66

Comprehensive income $ 423 $ 683 $ 3,066 $ 1,928

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

~~MARATHON OIL CORPORATION~~
~~Consolidated~~ ~~Balance~~ ~~Sheets (Unaudited)~~

September 30,
December 31,
(In millions, except per share data) 2011 2010
Assets
Current assets:
    Cash and cash equivalents $ 4,633 $ 3,951
    Receivables, less allowance for doubtful accounts of $2 and $7 1,696 5,972
    Receivables from related parties 25 58
    Inventories 342 3,453
    Other current assets 458 395

            Total current assets 7,154 13,829

Equity method investments 1,431 1,802
Property, plant and equipment, less accumulated depreciation,
   depletion and amortization of $16,731 and $19,805 20,318 32,222
Goodwill 537 1,380
Other noncurrent assets 1,101 781

            Total assets $ 30,541 $ 50,014
Liabilities
Current liabilities:
    Accounts payable $ 1,548 $ 8,000
    Payables to related parties 14 49
    Payroll and benefits payable 129 418
    Accrued taxes 1,904 1,447
    Deferred income taxes - 324
    Other current liabilities 192 580
    Long-term debt due within one year 338 295

            Total current liabilities 4,125 11,113

Long-term debt 4,705 7,601
Deferred income taxes 2,676 3,569
Defined benefit postretirement plan obligations 667 2,171
Asset retirement obligations 1,337 1,354
Deferred credits and other liabilities 275 435

            Total liabilities 13,785 26,243

Commitments and contingencies

Stockholders’ Equity
Preferred stock – no shares issued and outstanding (no par value, 26 million shares
          authorized) - -
Common stock:
     Issued –  770 million and  770 million shares  (par value $1 per share,
          1.1 billion shares authorized) 770 770
     Securities exchangeable into common stock – no shares issued and outstanding
         (no par value, 29 million shares authorized) - -
     Held in treasury, at cost – 66 million and 60 million shares (2,721 ) (2,665 )
Additional paid-in capital 6,675 6,756
Retained earnings 12,352 19,907
Accumulated other comprehensive loss (328 ) (997 )
Noncontrolling interest 8 -
            Total stockholders' equity 16,756 23,771

            Total liabilities and stockholders' equity $ 30,541 $ 50,014

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

~~MARATHON OIL CORPORATION~~

~~Consolidated Statements of~~ ~~Cash~~ ~~Flows (Unaudited)~~

Nine Months Ended
September 30,
(In millions) 2011 2010
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income $ 2,397 $ 1,862
Adjustments to reconcile net income to net cash provided by operating activities:
    Loss on early extinguishment of debt 279 92
    Discontinued operations (1,239 ) (404 )
    Deferred income taxes (75 ) (411 )
    Depreciation, depletion and amortization 1,716 1,376
    Impairments 307 439
    Pension and other postretirement benefits, net 28 (39 )
    Exploratory dry well costs and unproved property impairments 311 122
    Net gain on disposal of assets (63 ) (822 )
    Equity method investments, net 16 34
    Changes in:
          Current receivables 202 (124 )
          Inventories 47 (35 )
          Current accounts payable and accrued liabilities 361 924
    All other operating, net 113 85
               Net cash provided by continuing operations 4,400 3,099
               Net cash provided by (used in) discontinued operations 1,090 (111 )
               Net cash provided by operating activities 5,490 2,988
Investing activities:
   Additions to property, plant and equipment (2,437 ) (2,703 )
   Disposal of assets 385 1,354
   Investments - repayments of loans and return of capital 41 35
   Investing activities of discontinued operations (493 ) (920 )
   Property deposit (120 ) -
   All other investing, net 13 (22 )
               Net cash used in investing activities (2,611 ) (2,256 )
Financing activities:
   Debt repayments (2,843 ) (620 )
   Purchases of common stock (300 ) -
   Dividends paid (462 ) (526 )
   Financing activities of discontinued operations 2,916 (8 )
   Distribution in Spin-off (1,622 ) -
   All other financing, net 129 8
               Net cash used in financing activities (2,182 ) (1,146 )
Effect of exchange rate changes on cash (15 ) -
Net increase (decrease) in cash and cash equivalents 682 (414 )
Cash and cash equivalents at beginning of period 3,951 2,057
Cash and cash equivalents at end of period $ 4,633 $ 1,643

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

~~MARATHON OIL CORPORATION~~

~~Consolidated Statement of Stockholders’~~ ~~Equity~~ ~~(Unaudited)~~

(In millions) Preferred Stock Common Stock Securities Exchangeable for Common Stock Treasury Stock Additional Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Non-controlling Interest Total Stockholders' Equity
December 31, 2010 Balance $ - $ 770 $ - $ (2,665 ) $ 6,756 $ 19,907 $ (997 ) $ - $ 23,771
Shares issued - stock
     based compensation - - - 251 (84 ) - - 167
   Shares repurchased - - - (307 ) - - - (307 )
   Stock-based compensation - - - - (2 ) - - (2 )
   Net income - - - - - 2,397 - 2,397
   Other comprehensive income - - - - - - 82 82
   Dividends paid - - - - - (462 ) - (462 )
   Purchase of subsidiary shares
      from noncontrolling interest - - - - - - - 8 8
   Spin-off of downstream
      business - - - - 5 (9,490 ) 587 (8,898 )
September 30, 2011 Balance $ - $ 770 $ - $ (2,721 ) $ 6,675 $ 12,352 $ (328 ) $ 8 $ 16,756

(Shares in millions) Preferred Stock Common Stock Securities Exchangeable for Common Stock Treasury Stock
December 31, 2010 Balance - 770 - (60 )
Shares issued - stock
based compensation - - - 6
Shares repurchased - - - (12 )
September 30, 2011 Balance - 770 - (66 )

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

~~MARATHON OIL CORPORATION~~

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

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

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

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation ~~2010~~2011 Annual Report on Form 10-K. The results of operations for the third quarter and first nine months ~~ended September 30, 2011~~of 2012 are not necessarily indicative of the results to be expected for the full year.

2. Spin-off Downstream Business

On June 30, 2011, the spin-off of the downstream ~~(Refining, Marketing and Transportation)~~ business was completed, creating two independent energy companies: Marathon Oil ~~Corporation (“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.

In order to affect the spin-off and govern our relationship with MPC after the spin-off, we entered into a Separation and Distribution Agreement, a Tax Sharing Agreement, an Employee Matters Agreement and a Transition Services Agreement. The Separation and Distribution Agreement governed the separation of the downstream business, the distribution of MPC’s shares of common stock to our stockholders, transfer of assets and intellectual property, and other matters related to our relationship with MPC. The Separation and Distribution Agreement provides for cross-indemnities between Marathon Oil and MPC. In general, we have agreed to indemnify MPC for any liabilities relating to our historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and MPC has agreed to indemnify us for any liabilities relating to the historical downstream operations.

The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of Marathon Oil and MPC with respect to taxes and tax benefits, the filing of tax returns, the control of audits and other tax matters. In addition, the Tax Sharing Agreement reflects each company’s rights and obligations related to taxes that are attributable to periods prior to and including the Separation date and taxes resulting from transactions effected in connection with the Separation. In general, under the Tax Sharing Agreement, Marathon Oil is responsible for all U.S. federal, state, local and foreign income taxes attributable to Marathon Oil or any of its subsidiaries for any tax period that begins after the date of the spin-off, and MPC is responsible for all taxes attributable to it or its subsidiaries, whether accruing before, on or after the spin-off. The Tax Sharing Agreement contains covenants intended to protect the tax-free status of the spin-off. These covenants may restrict the ability of Marathon Oil and MPC to pursue strategic or other transactions that otherwise could maximize the values of their respective businesses and may discourage or delay a change of control of either company.

The Employee Matters Agreement contains provisions concerning benefit protection for employees who become MPC employees prior to December 31, 2011, treatment of holders of Marathon stock options, stock appreciation rights, restricted stock and restricted stock units, and cooperation between Marathon Oil and MPC in the sharing of employee information and maintenance of confidentiality. Unvested equity-based compensation awards were converted to awards of the entity where the employee holding them is working post-separation. For vested equity-based compensation awards, employees received both Marathon Oil and MPC awards.

Under the Transition Services Agreement, Marathon Oil and MPC are providing and/or making available various administrative services and assets to each other, for up to a one-year period beginning on the distribution date of the spin-off. The services include: administrative services; accounting services; audit services; health, environmental and safety services; human resource services; information technology services; legal services; natural gas administration services; tax services; and treasury services. In consideration for such services, the companies are paying fees to the other for the services provided, and these fees are generally in amounts intended to allow the party providing services to recover all of its direct and indirect costs incurred in providing these services.

~~MARATHON OIL CORPORATION~~

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

The following table presents the carrying value of assets and liabilities of MPC, immediately preceding the spin-off, which is excluded from the Marathon Oil consolidated balance sheet as a result of the spin-off on June 30, 2011.

(In millions)
Current assets:
Cash and cash equivalents $ 1,622
Receivables 5,041
Inventories 3,679
Other current assets 170
Total current assets of discontinued operations 10,512
Equity method investments 323
Property, plant and equipment 11,935
Goodwill 847
Other noncurrent assets 351
Total assets of discontinued operations $ 23,968

Current liabilities:
Accounts payable $ 7,329
Payroll and benefits payable 222
Accrued and deferred taxes 443
Other current liabilities 461
Long-term debt due within one year 12
Total current liabilities of discontinued operations 8,467
Long-term debt 3,262
Deferred income taxes 1,576
Defined benefit postretirement plan obligations 1,489
Deferred credits and other liabilities 276
Total liabilities of discontinued operations $ 15,070

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~~$74 million are included in discontinued operations for 2011.


		Three Months Ended					Nine Months Ended						Three Months Ended		Nine Months Ended
		September 30,						September 30,					September 30,		September 30,
(In millions)	2011			2010			2011			2010			2011		2011
Revenues applicable to discontinued operations		$	-		$	15,897		$	38,602		$	45,054	$	—	$	38,602
Pretax income from discontinued operations			-			445			2,012			693	—		2,012

3. Accounting Standards

~~Not Yet~~Recently Adopted

In September 2011, the Financial Accounting Standards Board (“FASB”) amended accounting standards to simplify how entities test goodwill for impairment. The ~~amendments reduce~~amendment reduces complexity by allowing an entity the option to make a qualitative evaluation of whether it is necessary to perform the two-step goodwill impairment test. The amendment is effective for our interim and annual periods beginning with the first quarter of 2012. ~~Early adoption is permitted, but we were unable to do so because our 2011 annual goodwill impairment testing was completed prior to the issuance of the amendment.~~ Adoption of this amendment ~~will~~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~~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 ~~other comprehensive income,~~OCI, and ~~the~~ total of comprehensive income. The presentation of items that are reclassified from ~~other comprehensive income~~OCI to net income on the income statement is also required. The amendments did not change the items that must be reported in ~~other comprehensive income~~OCI or when an item of ~~other comprehensive income~~OCI must be reclassified to net income. The

~~MARATHON OIL CORPORATION~~

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

amendments are effective for us beginning with the first quarter of ~~2012. We are still evaluating this reporting standard, but we do~~2012, except for the presentation of reclassifications, which has been deferred. Adoption of these amendments did not ~~expect adoption of this amendment to~~ have ana 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 ~~U.S.~~accounting principles generally accepted ~~accounting principles~~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 either to clarify the intent of existing requirements, to change measurement or expand disclosure principles or to conform to the wording used in IFRS. The amendments are to be applied prospectively ~~and will be effective~~ for our interim and annual periods beginning with the first quarter of 2012. ~~Early application is not permitted. We do not expect~~The adoption of ~~these~~the amendments todid 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. Variable Interest ~~Entities~~Entity

The owners of the Athabasca Oil Sands Project (“AOSP”), in which we hold a 20 percent undivided interest, contracted with a wholly-owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with a $3$3 million current liability recorded at September 30, 2012, consistent with December 31, 2011. Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline. Currently, no third-party shippers use the pipeline. Should shipments be suspended, by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all remaining periods. The contract expires in 2029; however, the shippers can extend its term perpetually. This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a Variable Interest Entity (“VIE”). We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore, the Corridor Pipeline is not consolidated by Marathon Oil. 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 ~~$696~~$697 million as of September 30, ~~2011.~~2012. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.

5. Income per Common Share

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

Three Months Ended September 30,
2011 2010
(In millions, except per share data) Basic Diluted Basic Diluted

Income from continuing operations $ 405 $ 405 $ 467 $ 467
Discontinued operations - - 229 229
Net income $ 405 $ 405 $ 696 $ 696

Weighted average common shares outstanding 711 711 710 710
Effect of dilutive securities - 3 - 2
Weighted average common shares, including
     dilutive effect 711 714 710 712

Per share:
    Income from continuing operations $ 0.57 $ 0.57 $ 0.66 $ 0.66
    Discontinued operations $ - $ - $ 0.32 $ 0.32
    Net income $ 0.57 $ 0.57 $ 0.98 $ 0.98



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

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)


	Nine Months Ended September 30,								Nine Months Ended September 30,
	2011				2010				2012				2011
(In millions, except per share data)	Basic		Diluted		Basic		Diluted		Basic		Diluted		Basic		Diluted

Income from continuing operations	$	1,158	$	1,158	$	1,458	$	1,458	$	1,260	$	1,260	$	1,158	$	1,158
Discontinued operations		1,239		1,239		404		404	—		—		1,239		1,239
Net income	$	2,397	$	2,397	$	1,862	$	1,862	$	1,260	$	1,260	$	2,397	$	2,397

Weighted average common shares outstanding		712		712		709		709	705		705		712		712
Effect of dilutive securities		-		4		-		2	—		4		—		4
Weighted average common shares, including
dilutive effect		712		716		709		711	705		709		712		716

Per share:
Income from continuing operations	$	1.63	$	1.62	$	2.06	$	2.05	$1.79		$1.78		$1.63		$1.62
Discontinued operations	$	1.74	$	1.73	$	0.57	$	0.57	—		—		$1.74		$1.73
Net income	$	3.37	$	3.35	$	2.63	$	2.62	$1.79		$1.78		$3.37		$3.35

The per share calculations above exclude 910 million ~~and 7 million~~ stock options and stock appreciation rights for the third quarter and first nine months of 2012, as they were antidilutive. Excluded for the third quarter and first nine months of 2011 were 9 million and 7 million stock options and stock appreciation rights.

6. Acquisitions

We acquired approximately 20,000 net acres in the core of the Eagle Ford shale during the first nine months of ~~2011,~~2012. All Eagle Ford properties are included in our Exploration and Production (“E&P”) segment. The largest transaction was the acquisition of Paloma Partners II, LLC, which closed August 1, 2012 for cash consideration of $768 million. This transaction was accounted for as ~~they~~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

The fair values of assets acquired and liabilities assumed were ~~antidilutive. Excluded~~measured primarily using an income approach, specifically utilizing a discounted cash flow analysis. The estimated fair values were based on significant inputs not observable in the market, and therefore represent Level 3 measurements. Significant inputs included estimated reserve volumes, the expected future production profile, estimated commodity prices and assumptions regarding future operating and development costs. A discount rate of approximately 10 percent was used in the discounted cash flow analysis. The accounting for this transaction is complete. The pro forma impact of this business combination is not material to our consolidated statements of income for the third quarter and ~~the~~ first nine months of ~~2010 were 12 million stock options~~2012 and ~~stock appreciation rights.~~2011.

MARATHON OIL CORPORATION

~~6. Acquisitions~~Notes to Consolidated Financial Statements (Unaudited)

7. Dispositions

~~During~~2012

In the ~~first nine months~~third quarter of ~~2011,~~2012, we ~~acquired~~sold approximately ~~45,000~~5,800 net undeveloped acres inlocated outside the core of the Eagle Ford shale, ~~formation in south Texas~~held by our E&P segment, for ~~approximately $202 million. This~~proceeds of $9 million. A pretax loss of $18 million was ~~funded from existing cash~~recorded.

In May 2012, we executed agreements to relinquish our E&P segment’s operatorship of and ~~was accounted for as an asset acquisition.~~

~~Early~~participating interests in the ~~fourth~~Bone Bay and Kumawa exploration licenses in Indonesia. As a result, we accrued and reported a $36 million loss on disposal of assets in the second quarter of 2012. Government ratification of the agreements was received during the third quarter of 2012, which released us from our obligations and further commitments related to these licenses, and we paid the amount accrued.

In April 2012, we entered into agreements to sell all of our E&P segment’s assets in Alaska. One transaction closed in the second quarter of 2012 with proceeds and a net pretax gain of $7 million. The remaining transaction, with a value of $375 million before closing adjustments, is currently under review by the U.S. Federal Trade Commission and the Alaska Attorney General's office, which could impact the closing of this transaction. Assets held for sale are included in the September 30, 2012 balance sheet as follows:



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

In January 2012, we closed on the ~~following transactions~~sale of our E&P segment’s interests in ~~Eagle Ford: the previously announced 141,000 net acres from Hilcorp Resources Holdings, LP (“Hilcorp”); additional~~several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million. This includes our equity method interests ~~of approximately 19,000 acres net acres;~~in Poseidon Oil Pipeline Company, L.L.C. and a gas gathering system. Also, during the fourth quarter, we expect to close on an additional 6,800 net acres in Eagle Ford from tag-along rights. The total acquisition cost for these nearly 167,000 net acres and the gathering system is expected to be approximately $4.5 billion, including projected closing adjustments and future carrying costs. These transactions will be funded largely from existing cash. The acreage includes proved and unproved oil and gas assets,Odyssey Pipeline L.L.C., as well as ~~some producing wells. We are~~certain other oil pipeline interests, including the Eugene Island pipeline system. A pretax gain of $166 million was recorded in the ~~process~~first quarter of ~~evaluating the acquisitions to determine whether they will be accounted for as business combinations or as asset acquisitions.~~2012.

2011

~~7. Dispositions~~

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

quarter of 2011.

In April 2011, we assigned a 30 percent undivided working interest in our ~~Exploration and Production (“~~E~~&P”)~~&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~~$270 million, recording a pretax gain of ~~$37~~$39 million. We remain operator of this jointly owned leasehold.

Also in April 2011, we farmed-out a 40 percent working interest in 10 concessions in our E&P segment’s Poland’s Paleozoic Shale play. In late July 2011, we sold an additional 9 percent working interest. A $12 million pretax gain was recorded. We currently hold a 51 percent working interest in these 10 concessions and serve as operator.

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

~~During the first quarter 2010, we closed the sale~~ of a 20 percent outside-operated interest in our E&P segment’s Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola. We received net proceeds of $1.3 billion and recorded a pretax gain on the sale in the amount of $811 million. We retained a 10 percent outside-operated interest in Block 32.2010.

~~Pending disposition~~

In October 2011, we entered into definitive agreements to sell our E&P segment’s equity interests in several Gulf of Mexico crude oil pipeline systems including our 28 percent interest in Poseidon Oil Pipeline Company, L.L.C., our 29 percent interest in Odyssey Pipeline L.L.C., our 23 percent interest in the Eugene Island Pipeline System, and certain other oil pipeline interests. The value of this transaction, subject to further closing adjustments, is approximately $206

~~MARATHON OIL CORPORATION~~

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

million, net of debt. In addition, the Poseidon and Odyssey interests are subject to wavier of rights of first refusal. The carrying value of these assets was $45 million as of September 30, 2011. We expect to close the transaction in the fourth quarter of 2011.

8. Segment Information

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

Exploration and Production (“E&P”) – explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis;

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

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

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

~~Integrated Gas (“IG”) – markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis.~~

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income represents income from continuing operations, net of income taxes, attributable to the operating segments. Our corporate general and administrative costs are not allocated to the operating segments. These costs primarily consist

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

of employment costs (including pension effects), professional services, facilities and other costs associated with corporate activities, net of associated income tax effects. ~~Foreign currency remeasurement and transaction~~Impairments, gains or losses on disposal of assets or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.

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

accruals but not corporate activities.

As discussed in ~~Notes 1 and~~Note 2, our downstream business was spun-off on June 30, 2011 and has been reported as discontinued operations in ~~all periods presented.~~2011.


	Three Months Ended September 30, 2011										Three Months Ended September 30, 2012
(In millions)	E&P			OSM		IG		Total			E&P		OSM		IG		Total

Revenues:
Customer	$	3,190		$	427	$	16	$	3,633		$	3,503	$	470	$	—	$	3,973
Intersegment		6			-		-		6
Related parties		16			-		-		16		16		—		—		16
Segment revenues		3,212			427		16		3,655		$	3,519	$	470	$	—	3,989
Elimination of intersegment revenues		(6	)		-		-		(6	)
Unrealized gain on crude oil derivative instruments																	45
Total revenues	$	3,206		$	427	$	16	$	3,649								$	4,034
Segment income	$	330		$	92	$	55	$	477		$	486	$	65	$	39	$	590
Income from equity method investments		63			-		60		123		74		—		48		122
Depreciation, depletion and amortization		454			55		-		509		556		60		—		616
Income tax provision		890			31		19		940		1,252		20		9		1,281
Capital expenditures		684			36		1		721		1,274		41		1		1,316



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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Three Months Ended September 30, 2010
(In millions) E&P OSM IG Total

Revenues:
    Customer $ 2,605 $ 196 $ 38 $ 2,839
    Intersegment 20 - - 20
    Related parties 15 - - 15
        Segment revenues 2,640 196 38 2,874
    Elimination of intersegment revenues (20 ) - - (20 )
        Total revenues $ 2,620 $ 196 $ 38 $ 2,854
Segment income $ 510 $ 18 $ 41 $ 569
Income from equity method investments 51 - 51 102
Depreciation, depletion and amortization 491 28 1 520
Income tax provision 579 2 21 602
Capital expenditures 586 191 1 778

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

Revenues:
    Customer $ 9,696 $ 1,180 $ 93 $ 10,969
    Intersegment 47 - - 47
    Related parties 45 - - 45
        Segment revenues 9,788 1,180 93 11,061
    Elimination of intersegment revenues (47 ) - - (47 )
        Total revenues $ 9,741 $ 1,180 $ 93 $ 11,014
Segment income $ 1,599 $ 193 $ 158 $ 1,950
Income from equity method investments 187 - 173 360
Depreciation, depletion and amortization 1,541 141 3 1,685
Income tax provision 2,101 64 62 2,227
Capital expenditures 2,101 236 2 2,339

Nine Months Ended September 30, 2010
(In millions) E&P OSM IG Total

Revenues:
    Customer $ 7,622 $ 567 $ 98 $ 8,287
    Intersegment 49 - - 49
    Related parties 41 - - 41
        Segment revenues 7,712 567 98 8,377
    Elimination of intersegment revenues (49 ) - - (49 )
        Total revenues $ 7,663 $ 567 $ 98 $ 8,328
Segment income (loss) $ 1,444 $ (59 ) $ 109 $ 1,494
Income from equity method investments 128 - 142 270
Depreciation, depletion and amortization 1,279 67 3 1,349
Income tax provision (benefit) 1,741 (15 ) 56 1,782
Capital expenditures 1,774 699 2 2,475



	Nine Months Ended September 30, 2012
(In millions)	E&P		OSM		IG		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
Total revenues							$	11,556
Segment income	$	1,380	$	157	$	56	$	1,593
Income from equity method investments	176		—		84		260
Depreciation, depletion and amortization	1,593		159		—		1,752
Income tax provision	3,398		51		15		3,464
Capital expenditures	3,459		136		2		3,597



	Nine Months Ended September 30, 2011
(In millions)	E&P		OSM		IG		Total
Revenues:
Customer	$	9,696	$	1,180	$	93	$	10,969
Intersegment	47		—		—		47
Related parties	45		—		—		45
Segment revenues	$	9,788	$	1,180	$	93	11,061
Elimination of intersegment revenues							(47		)
Total revenues							$	11,014
Segment income	$	1,599	$	193	$	158	$	1,950
Income from equity method investments	187		—		173		360
Depreciation, depletion and amortization	1,541		141		3		1,685
Income tax provision	2,101		64		62		2,227
Capital expenditures	2,101		236		2		2,339

~~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) 2011 2010 2011 2010
Segment income $ 477 $ 569 $ 1,950 $ 1,494
Items not allocated to segments, net of income taxes:
     Corporate and other unallocated items (79 ) (50 ) (215 ) (130 )
     Foreign currency remeasurement of income taxes 23 (37 ) 6 33
     Impairments(a)
- (15 ) (195 ) (286 )
     Loss on early extinguishment of debt(b)
- - (176 ) (57 )
     Tax effect of subsidiary restructuring(c)
- - (122 ) -
     Deferred income tax items(c)
(15 ) - (65 ) (45 )
     Water abatement - Oil Sands(d)
- - (48 ) -
     Gain on dispositions (e)
(1 ) - 23 449
         Income from continuing operations 405 467 1,158 1,458
         Discontinued operations - 229 1,239 404
               Net income $ 405 $ 696 $ 2,397 $ 1,862

~~(a)~~

~~Impairments are discussed in Note 13.~~

~~(b)~~

~~Additional information on debt retired early can be found in Note 15.~~

~~(c)~~

~~Changes in deferred taxes and the non cash tax restructuring are discussed in Note 10.~~

~~(d)~~

~~Oil sands water abatement costs are discussed in Note 19.~~

~~(e)~~

~~Additional information on these gains can be found in Note 7.~~

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						Three Months Ended				Nine Months Ended
	September 30,					September 30,						September 30,				September 30,
(In millions)	2011			2010		2011			2010			2012		2011		2012		2011
Total revenues		$	3,649	$	2,854		$	11,014		$	8,328	$	4,034	$	3,649	$	11,556	$	11,014
Less: Sales to related parties			16		15			45			41	16		16		43		45
Sales and other operating revenues		$	3,633	$	2,839		$	10,969		$	8,287	$	4,018	$	3,633	$	11,513	$	10,969

~~9. Defined Benefit Postretirement Plans~~

~~The following summarizes the components of net periodic benefit cost related to continuing operations:~~

Three Months Ended September 30,
   Pension Benefits Other Benefits
(In millions) 2011 2010 2011 2010
Service cost $ 12 $ 12 $ 1 $ -
Interest cost 17 17 4 4
Expected return on plan assets (16 ) (16 ) - -
Amortization:
    – prior service cost (credit) 1 2 (2 ) (2 )
    – actuarial loss 12 12 - -
    – net settlement - 8 - -
Net periodic benefit cost $ 26 $ 35 $ 3 $ 2

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:

Nine Months Ended September 30,
   Pension Benefits Other Benefits
(In millions) 2011 2010 2011 2010
Service cost $ 35 $ 35 $ 3 $ 2
Interest cost 50 52 12 12
Expected return on plan assets (49 ) (48 ) - -
Amortization:
    – prior service cost (credit) 4 5 (5 ) (5 )
    – actuarial loss 37 37 - -
    – net settlement/curtailment loss - 8 - -
Net periodic benefit cost $ 77 $ 89 $ 10 $ 9



	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

9. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:



	Three Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Service cost	$	12		$	12		$	1		$	1
Interest cost	16			17			4			4
Expected return on plan assets	(14		)	(16		)	—			—
Amortization:
– prior service cost (credit)	2			1			(2		)	(2		)
– actuarial loss	12			12			—			—
– net settlement loss^(a)	34			—			—			—
Net periodic benefit cost	$	62		$	26		$	3		$	3



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


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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

During the first nine months of ~~2011,~~2012, we made contributions ~~related to continuing operations~~ of ~~$43~~$162 million to our funded pension plans. We expect to make additional contributions up to an estimated ~~$13~~$2 million ~~to our funded pension plans~~ over the remainder of ~~2011, most of which were made in October 2011.~~2012. Current benefit payments related to unfunded pension and other postretirement benefit plans ~~of our continuing operations~~ were $4$7 million and ~~$14~~$12 million during the first nine months of ~~2011.~~2012.

10. Income Taxes

~~The following is an analysis of the effective income tax rates for continuing operations for the periods presented:~~

Nine Months Ended September 30,
2011 2010
Statutory U.S. income tax rate 35 % 35 %
Effects of foreign operations, including foreign tax credits 7 19
Change in permanent reinvestment assertion 7 -
Adjustments to valuation allowances 11 -
Tax law changes 2 2
Other tax effects 2 (1 )
Effective income tax rate for continuing operations 64 % 55 %

~~Effects of foreign operations~~

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, and foreign currency remeasurement effects.~~income. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to individual items not allocated to segments is reported in “Corporate and other unallocated items” ~~shown~~ in Note 8.

~~The effects of foreign operations on our~~ Our effective tax rate ~~decreased~~ in the first nine months of ~~2011~~2012 was 72 percent. This rate is higher than the U.S. statutory rate of 35 percent primarily due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax 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 ~~the first nine months of 2010, primarily due to the suspension of all production operations~~prior periods caused an increase in our valuation allowance on current year foreign tax credits. In Libya, ~~in the first quarter of 2011,~~ where the statutory tax rate is in excess of 90 ~~percent. This decrease~~percent, limited production resumed in the fourth quarter of 2011 and liquid hydrocarbon sales resumed in the first quarter of 2012. A reliable estimate of 2012 annual ordinary income from our Libyan operations cannot be made and the range of possible scenarios when including ordinary income from our Libyan operations in the worldwide annual effective tax rate calculation demonstrates significant variability. As such, for the first nine months of 2012, an estimated annual effective tax rate was ~~partially offset by~~calculated excluding Libya and applied to consolidated ordinary income excluding Libya and the tax provision applicable to Libyan ordinary income was recorded as a discrete item in the period. Excluding Libya, the effective tax rate would be 64 percent for the first nine months of 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 ~~of $122 million~~ related to an internal restructuring of our international ~~subsidiaries in the second quarter of 2011.~~

~~Change in permanent reinvestment assertion~~

A principal tax planning strategy available to realize the deferred tax asset for our foreign tax credit benefits relates to the permanent reinvestment of our foreign subsidiaries’ earnings, which is reconsidered quarterly to give effect to changes in our portfolio of producing properties and in our tax profile. In the second quarter of 2011, we recorded $716 million of deferred U.S. tax on undistributed earnings of $2,046 million that we previously intended to permanently reinvest in foreign operations. Offsetting this tax expense were associated foreign tax credits of $488 million. In addition, we reduced our valuation allowance related to foreign tax credits by $228 million due to recognizing deferred U.S. tax on previously undistributed earnings.subsidiaries.

~~Adjustments to valuation allowance~~

The ability to realize the benefit of foreign tax credits is based on certain estimates concerning future operating conditions (particularly as related to prevailing liquid hydrocarbon, natural gas and synthetic crude oil prices), future financial conditions, income generated from foreign sources and Marathon Oil's tax profile in the years that such credits may be claimed. In the third quarter of 2011, we increased the valuation allowance against foreign tax credits by $227

~~MARATHON OIL CORPORATION~~

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

million because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in 2011. A higher price and production outlook over the next several years for Norway due to better than expected performance contributed to our generating excess foreign tax credits.

During the second quarter of 2011, we recorded a valuation allowance of $18 million on our deferred tax assets related to state operating loss carryforwards. Due to the spin-off (see Note 2), we have determined it is more likely than not that we will be unable to realize all recorded deferred tax assets.

~~Tax law changes~~

On July 19, 2011, the U.K. enacted Finance Bill 2011 which increased the rate of the supplementary charge levied on profits from U.K. oil and gas production from 20 percent to 32 percent, effective March 24, 2011. As a result of this legislation, we recorded deferred tax expense of $15 million in the third quarter of 2011.

On May 25, 2011, Michigan enacted legislation that replaced the Michigan Business Tax (“MBT”) with a corporate income tax (“CIT”), effective January 1, 2012. The new CIT legislation eliminates the “book-tax difference deduction” that was provided under the MBT to mitigate the net increase in a taxpayer’s deferred tax liability resulting when Michigan moved from the Single Business Tax, a non-income tax, to the MBT, an income tax, on July 12, 2007. Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date. The total effect of tax law changes on deferred tax balances is recorded as income tax expense related to continuing operations in the period the law is enacted, even if a portion of the deferred tax balances relate to discontinued operations. As a result of the new CIT legislation, we recorded an expense of $32 million in the second quarter of 2011.

The Patient Protection and Affordable Care Act (“PPACA”) and the Health Care and Education Reconciliation Act of 2010 (“HCERA”), (together, the “Acts”) were signed in to law in March 2010. The Acts effectively change the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “MPDIMA”). Under the MPDIMA, the federal subsidy does not reduce our income tax deduction for the costs of providing such prescription drug plans nor is it subject to income tax individually. Beginning in 2013, under the Acts, our income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date. The total effect of tax law changes on deferred tax balances is recorded as income tax expense related to continuing operations in the period the law is enacted, even if a portion of the deferred tax balances relate to discontinued operations. As a result, we have recorded a charge of $45 million in the first quarter of 2010 for the write-off of deferred tax assets to reflect the change in the tax treatment of the federal subsidy.

The following table summarizes the activity in unrecognized tax benefits:


	Nine Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2011			2010			2012			2011
Beginning balance	$	103		$	75		$	157		$	103
Additions based on tax positions related to the current year		3			4		2			3
Reductions based on tax positions related to the current year		(3	)		(4	)	(1		)	(3		)
Additions for tax positions of prior years		71			16		97			71
Reductions for tax positions of prior years		(24	)		(22	)	(66		)	(24		)
Settlements		(9	)		(1	)	(12		)	(9		)
Ending balance	$	141		$	68		$	177		$	141

If the unrecognized tax benefits as of September 30, ~~2011~~2012 were recognized, ~~$90~~$114 million would affect our effective income tax rate. There were ~~$10~~$143 million of uncertain tax positions as of September 30, ~~2011~~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. Inventories

Inventories are carried at the lower of cost or market value. ~~The cost of inventories of crude oil, refined products and merchandise is determined primarily under the last-in, first-out (“LIFO”) method.~~



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

~~A significant portion of our inventories were related to our downstream business (see Note 2) at December 31, 2010.~~

September 30, December 31,
(In millions) 2011 2010
Liquid hydrocarbons, natural gas and bitumen $ 135 $ 1,275
Refined products and merchandise - 1,774
Supplies and sundry items 207 404
Total inventories, at cost $ 342 $ 3,453

12. Property, Plant and Equipment

September 30, December 31,
(In millions) 2011 2010
E&P
    United States $ 14,549 $ 13,532
     International 12,270 11,736
          Total E&P 26,819 25,268
OSM 9,866 9,631
IG 36 47
RM&T(a)
- 16,624
Corporate 328 457
          Total property, plant and equipment 37,049 52,027
Less accumulated depreciation, depletion and amortization (16,731 ) (19,805 )
          Net property, plant and equipment $ 20,318 $ 32,222

~~(a)~~

~~See Note 2 for a discussion of the spin-off of our downstream (RM&T) business.~~



	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

In the first quarter of 2011, production operations in Libya were ~~suspended and we are not currently making deliveries~~suspended. In the fourth quarter of ~~hydrocarbons from our interest~~2011, limited production resumed. Since that time, average net liquid hydrocarbon sales volumes have increased to 49 thousand barrels per day (“mbbld”) in the ~~Waha concession~~third quarter of 2012 and 37 mbbld in ~~eastern Libya. As~~the first nine months of September 30, 2011, our net property, plant and equipment investment in Libya is approximately $758 million and our net proved reserves in Libya were 242 million barrels of oil equivalent (“mmboe”) at December 31, 2010. The return of our operations in Libya to pre-conflict levels is unknown at this time, however, we2012. We and our partners in the Waha ~~concession are assessing~~concessions continue to assess the condition of our assets in Libya and when the resumption of operations will be viable. In addition, payments due to the Libyan government or entities affiliated with the Libyan government have been blocked by the U.S. government under a February 25, 2011 executive order. Such amounts, as of September 30, 2011, primarily related to taxesuncertainty around sustained production and ~~royalties due on our January and February 2011~~ sales ~~totaled approximately $200 million.~~levels remains.

Exploratory well costs capitalized greater than one year after completion of drilling (“suspended”) were ~~$390~~$207 million as of September 30, ~~2011, an increase of $67 million~~2012. The net decrease in such costs from December 31, ~~2010. The resumption of our offshore~~2011 primarily related to changes in three areas. Norway exploration ~~project~~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 to the Norwegian government for approval in ~~2011 reduced the total suspended exploratory well costs by $26 million~~June and approved in ~~the first quarter of 2011.~~October 2012. Drilling on the ~~Innsbruck~~Shenandoah prospect ~~located on Mississippi Canyon Block 993~~ in the Gulf of Mexico resumed in June 2012. Costs of $38 million related to Shenandoah are no longer suspended. The Innsbruck well was ~~suspended~~reentered in ~~the second quarter~~September 2012; therefore, costs of ~~2010 due~~$60 million related to the ~~U.S. Department of Interior’s drilling moratorium. During the third quarter of 2011, we received an exploration permit and~~prospect are ~~in the process of obtaining a rig in order~~no longer suspended.

MARATHON OIL CORPORATION

Notes to ~~resume drilling on this property. Costs of $88 million related to that project have now been capitalized for greater than one year.~~

Consolidated Financial Statements (Unaudited)

13. Fair Value Measurements

Fair Values - Recurring

As of September 30, 2011, balances related to interest rate swaps accounted for at fair value on a recurring basis were assets of $28 million. The interest rate swaps are in Level 2 of the fair value hierarchy and are measured at fair value with a market approach using market price quotes or a price obtained from third-party services such as Bloomberg L.P. which have been corroborated with data from active markets for similar assets and liabilities. The majority of our 2010 derivatives related to our downstream business. The following table presents assets and liabilities accounted for at fair value on a recurring basis as of ~~December 31, 2010~~September 30, 2012 by fair value hierarchy level.



	September 30, 2012
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	47	$	—	$	1	$	48
Interest rate	—		22		—		—		22
Foreign currency	—		20		—		—		20
Derivative instruments, assets	—		89		—		1		90
Derivative instruments, liabilities
Commodity	—		2		—		—		2
Foreign currency	—		1		—		—		1
Derivative instruments, liabilities	$	—	$	3	$	—	$	—	$	3

~~MARATHON OIL CORPORATION~~

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

December 31, 2010
(In millions) Level 1 Level 2 Level 3 Collateral Total
Derivative instruments, assets
     Commodity $ 58 $ - $ 1 $ 81 $ 140
     Interest rate - 32 - - 32
          Derivative instruments, assets 58 32 1 81 172
Derivative instruments, liabilities
     Commodity (102 ) - (3 ) - (105 )
          Derivative instruments, liabilities $ (102 ) $ - $ (3 ) $ - $ (105 )

At December 31, 2010, commodity derivatives in Level 1 are exchange-traded contracts for crude oil, natural gas and refined products measured at fair value with a market approach using the close-of-day settlement price for the market. Commodity ~~derivatives, interest rate derivatives and foreign currency forwards~~swaps in Level 2 are measured at fair value with a market approach using ~~broker price quotes or~~ prices obtained from exchanges or pricing services, which have been corroborated with data from active markets for similar assets and liabilities. Commodity options in Level 2 are valued using The Black-Scholes Model. Inputs to this model include prices as noted above, discount factors, and implied market volatility. The inputs used to estimate fair value 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. ~~or Platt’s, a Division of McGraw-Hill Corporation (“Platt’s”)~~, which have been corroborated with data from active markets for similar assets and ~~liabilities. Collateral deposits~~liabilities, and are Level 2 inputs.

As of December 31, 2011, balances related to ~~both Level 1 and Level 2 commodity derivatives are in broker accounts covered by master netting agreements. Commodity derivatives in Level 3 are measured~~interest rate swaps accounted for at fair value ~~with~~on a ~~market approach using prices obtained from third-party services such as Platt’s and price assessments from other independent brokers.~~

~~The following is a reconciliation~~recurring basis were noncurrent assets of ~~the net beginning and ending balances recorded for derivative instruments classified as Level 3 in the fair value hierarchy.~~

Three Months Ended Nine Months Ended
September 30, September 30,
(In millions) 2011 2010 2011 2010
Beginning balance $ - $ (3 ) $ (2 ) $ 9
          Included in net income - 4 - 23
          Included in other comprehensive income - - - 4
     Transfers to Level 2 - - - (30 )
     Purchases - - - 2
     Settlements - 1 - (6 )
     Spin-off downstream business - - 2 -
Ending balance $ - $ 2 $ - $ 2

~~No instruments~~$5 million measured at fair value using actionable broker quotes which are Level ~~3 inputs~~2 inputs. There were ~~held on September 30, 2011. Net income for the third quarter and first nine months~~no other significant recurring fair value measurements as of ~~2010 included unrealized gains of $3 million related to instruments held on September 30, 2010. See Note 14 for the income statement impacts of our derivative instruments.~~

December 31, 2011.

Fair Values - Nonrecurring

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



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



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

17Our 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)

Three Months Ended September 30,
2011 2010
(In millions) Fair Value Impairment Fair Value Impairment
Equity method investment - - - 25

Nine Months Ended September 30,
2011 2010
(In millions) Fair Value Impairment Fair Value Impairment
Long-lived assets held for use $ 226 $ 282 $ 146 $ 439
Equity method investment - - - 25
Intangible assets $ - $ 25 $ - $ -

2 million barrel of oil equivalent reduction in proved reserves and a $261 million impairment charge in the first quarter of 2012. The fair value of the Ozona development was determined using an income approach based upon internal estimates of future production levels, prices and discount rate, all Level 3 inputs. Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated liquid hydrocarbon prices based on the Louisiana Light Sweet 12-month price range, as we think production will not be significant beyond twelve months, adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

In May 2011, significant water production and reservoir pressure declines occurred at our E&P segment’s Droshky development in the Gulf of Mexico. ~~Plans for a waterflood have been cancelled and the field will be produced to abandonment pressures, expected in the first half of 2012.~~ Consequently, 3.4 million barrels of oil equivalent of proved reserves were written off and a ~~$273~~$273 million impairment of this long-lived asset to fair value was recorded in the second quarter of 2011. The $226 million fair value of the Droshky development was determined using an income approach based upon internal estimates of future production levels, prices and discount rate, all Level 3 inputs.

In the second quarter of 2011, our outlook for U.S. natural gas prices ~~made~~indicated that it was unlikely that sufficient U.S. demand for LNG would materialize by 2021, which is when ~~the~~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.

~~In March 2010, we completed a reservoir study which resulted in a portion~~Other impairments of our Powder River Basin field being removed from plans for future development in our E&P segment. The field’s fair value was measured at $144 million, using an income approach based upon internal estimates of future production levels, prices and discount rate which are Level 3 inputs. This resulted in an impairment of $423 million.

~~Impairments of several other~~ long-lived assets held for use inby our E&P segment ~~that were evaluated~~ in the third quarter and first nine months ~~ended September 30,~~of 2012 and 2011 ~~and 2010~~ were a result of reduced drilling expectations, reduction of estimated reserves or declining natural gas ~~prices, and are also reported above.~~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

The following table summarizes financial instruments, excluding the derivative financial instruments, and their reported fair value by individual balance sheet line item at September 30, 2011 and December 31, 2010:

September 30, 2011 December 31, 2010
Fair Carrying Fair Carrying
(In millions) Value Amount Value Amount
Financial assets
     Other current assets $ 223 $ 220 $ 226 $ 220
     Other noncurrent assets 273 276 396 231
          Total financial assets   496 496 622 451
Financial liabilities
     Long-term debt, including current portion(a)
5,636 4,985 8,364 7,527
     Deferred credits and other liabilities 33 35 66 67
          Total financial liabilities   $ 5,669 $ 5,020 $ 8,430 $ 7,594

~~(a)~~ ~~Excludes capital leases.~~

Our current assets and liabilities include financial instruments, the most significant of which are ~~trade~~ accounts receivables and payables. We believe the carrying values of ~~our current assets~~these accounts receivables and ~~liabilities~~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

~~MARATHON OIL CORPORATION~~

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

insignificance of bad debt expense, which includes an evaluation of counterparty credit risk. ~~Exceptions to this assessment are:~~

~~receivables from United States Steel Corporation (“United States Steel”), which are~~The following table summarizes financial instruments, excluding trade accounts receivables and payables and derivative financial instruments, and their reported ~~in other current assets above and discussed below; and~~

·	~~the current portion of our long-term debt, which is reported with long-term debt above and discussed below.~~

~~The current portion of receivables from United States Steel is reported in other current assets, and the long-term portion is included in other noncurrent assets. The~~ fair value of the receivables from United States Steel is measured using an income approach that discounts the future expected payments over the remaining term of the obligations. Because this receivable is not publicly-tradedby individual balance sheet line item at September 30, 2012 and not easily transferable, a hypothetical market based upon United States Steel’s borrowing rate curve is assumed and the majority of inputs to the calculation are Level 3. The industrial revenue bonds are to be redeemed on or before December 31, 2011 ~~the tenth anniversary of the USX Separation.~~:



	September 30, 2012				December 31, 2011
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other current assets	$	135	$	134	$	146	$	148
Other noncurrent assets	158		158		68		68
Total financial assets	293		292		214		216
Financial liabilities
Other current liabilities	13		13		—		—
Long-term debt, including current portion^(a)	5,639		4,653		5,479		4,753
Deferred credits and other liabilities	100		101		36		38
Total financial liabilities	$	5,752	$	4,767	$	5,515	$	4,791

^(a) Excludes capital leases.

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

~~Over 90 percent~~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. Derivatives

For information regarding the fair value measurement of derivative instruments, see Note 13.

~~The majority of our 2010 derivatives related to our downstream business.~~ The following table presents the gross fair values of ~~derivative~~derivatives instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of September 30, ~~2011 and December 31, 2010.~~2012.



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

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

September 30, 2011
(In millions) Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges
     Interest rate $ 28 $ - $ 28 Other noncurrent assets
Total Designated Hedges 28 - 28

Not Designated as Hedges
     Commodity 1 - 1 Other current assets
Total Not Designated as Hedges 1 - 1

     Total $ 29 $ - $ 29

December 31, 2010
(In millions) Asset Liability Net Asset Balance Sheet Location
Fair Value Hedges
     Interest rate $ 32 $ - $ 32 Other noncurrent assets
Total Designated Hedges 32 - 32

Not Designated as Hedges
     Commodity 58 102 (44 ) Other current assets
Total Not Designated as Hedges 58 102 (44 )

     Total $ 90 $ 102 $ (12 )



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

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

~~MARATHON OIL CORPORATION~~

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

December 31, 2010
(In millions) Asset Liability Net Liability Balance Sheet Location
Not Designated as Hedges

Commodity $ 1 $ 3 $ 2 Other current liabilities

Total Not Designated as Hedges 1 3 2
Total $ 1 $ 3 $ 2

~~Derivatives Designated as Cash Flow Hedges~~

As of ~~September 30,~~December 31, 2011 no, our derivatives outstanding were ~~designated as cash flow hedges.~~

~~Gains~~interest rate swaps that were fair value hedges, which had an asset value of ~~$10~~$5 million ~~related to cash flow hedges were reclassified from accumulated other comprehensive income into net income during~~ and are located on the ~~first quarter of 2011. This amortization was accelerated because the related debt was retired.~~consolidated balance sheet in Other noncurrent assets.

Derivatives Designated as Fair Value Hedges

As of September 30, 2012, we had multiple interest rate swap agreements with a total notional amount of $600 million at a weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate of 4.71 percent.

As of September 30, 2012, our foreign currency forwards had an aggregate notional amount of 3,939 million Norwegian Kroner at a weighted average forward rate of 5.911. 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. We recorded a $29~~$1,450 million ~~gain, which reduced the loss on extinguishment of debt.~~.

MARATHON OIL CORPORATION

~~As of September 30, 2011, we had multiple interest rate swap agreements with a total notional amount of $500 million at a weighted average, LIBOR-based, floating rate of 3.65 percent.~~Notes to Consolidated Financial Statements (Unaudited)

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



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

Gain (Loss)
Three Months Ended Nine Months Ended
September 30, September 30,
(In millions) Income Statement Location 2011 2010 2011 2010
Derivative
Interest rate Net interest and other financing costs $ 26 $ 15 $ 25 $ 39
Hedged Item
Long-term debt Net interest and other financing costs $ (26 ) $ (15 ) $ (25 ) $ (39 )

Derivatives not Designated as Hedges

~~The effect~~In August 2012, we entered crude oil derivatives related to ~~continuing operations~~a portion of our forecast U.S. 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

The following table summarizes the effect of all derivative instruments not designated as hedges in our consolidated statements of income appear on the sales and other operating revenues line as gains of $2 million and $7 million in the third quarters of 2011 and 2010. For the first nine months of 2011 and 2010 the gains were $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

~~3 million and $130 million.~~

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, ~~2011,~~2012, we had no borrowings ~~outstanding, and no borrowings were made during the third quarter and nine months ended September 30, 2011~~ against our ~~$3 billion~~ revolving credit facility, ordescribed below, and $1,839 million in commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

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 ~~February and March~~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 ~~the following~~$2,498 million aggregate principal amount of debt at a weighted average price equal to 112 percent of face value. A ~~$279~~$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. Incentive Based Compensation

~~MARATHON OIL CORPORATION~~

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

(In millions)
6.000% notes due 2012 $ 400
6.125% notes due 2012 450
8.375% secured notes due 2012(a)
448
6.500% debentures due 2014 700
5.900% notes due 2018 40
7.500% debentures due 2019 460
Total debt purchases $ 2,498

~~(a)~~

~~These notes were senior secured notes of Marathon Oil Canada Corporation.~~

Stock Option and Restricted Stock Awards

In April 2010, we retired $500 million in aggregate principal of our debt under two tender offers at a weighted average price equal to 117 percent of face value. As a result of the tender offers, we recorded a loss on extinguishment of debt of $92 million, including the transaction premium as well as the expensing of related deferred financing costs on the debt in the second quarter of 2010.

~~In May 2010, United States Steel redeemed $89 million of certain industrial development and environmental improvement bonds.~~

~~United States Steel has issued calls for the fourth quarter of 2011 on the remaining environmental revenue bonds for which we remained obligated after the USX Separation.~~

~~16. Stock-Based Compensation Plans~~

Pursuant to the Employee Matters Agreement (see Note 2), we made certain adjustments to the exercise price and number of our stock-based compensation awards, under existing antidilution provisions, with the intention of generally preserving the intrinsic value of the awards immediately prior to the spin-off. Outstanding options to purchase common shares of Marathon stock that were vested prior to the spin-off were adjusted so that the holders of the options hold options to purchase common shares of both Marathon Oil and MPC stock. Unvested stock options and restricted stock were converted to those of the entity where the employee holding them is working post-separation. Adjustments to our stock-based compensation awards did not result in additional compensation expense.

The following table ~~presenting~~presents a summary of stock option award and restricted stock award activity for the first nine months ~~ended September 30, 2011 reflects the adjustments discussed above.~~of 2012:

	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2010		24,912,261		$	24.85		2,084,680		$	23.03
											Stock Options					Restricted Stock
											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
Granted		7,676,544	(a)		32.30		2,982,520	(b)		27.85	1,858,872		^(a)		$33.52	2,169,744			$31.61
Options Exercised/Stock Vested		(3,514,758	)		15.05		(869,699	)		28.28	(1,256,318	)			$18.25	(1,142,195	)		$25.18
Cancelled		(403,223	)		23.11		(117,543	)		23.82	(509,748	)			$28.29	(287,278	)		$27.96
Spin-off downstream business		(6,989,110	)		30.94		(289,925	)		21.24
Outstanding at September 30, 2011		21,681,714		$	24.47		3,790,033		$	25.73
Outstanding at September 30, 2012											21,463,521				$25.47	4,444,249			$28.72

^(a) ~~(a)~~ The weighted average grant date fair value of stock option awards granted was ~~$10.45~~$9.94 per share.

~~(b)~~ ~~Beginning in August, 2011, most employees on the U.S., U.K., Canadian and Norwegian payrolls are eligible for a restricted stock grant, based on performance.~~

Performance Unit Awards

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

17. Supplemental Cash Flow Information



	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		)

~~17. Stockholders’ Equity~~

As of September 30, 2011, we had acquired 78 million common shares at a cost of $3,222 million under our $5 billion authorized share repurchase program, including 12 million common shares acquired during the third quarter of 2011 at a cost of $300 million.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

18. ~~Supplemental Cash Flow Information~~

Nine Months Ended September 30,
(In millions) 2011 2010
Net cash provided from operating activities:
     Interest paid (net of amounts capitalized) $ 197 $ 93
     Income taxes paid to taxing authorities 2,183 1,426
Noncash investing and financing activities:
     Debt payments made by United States Steel 18 106

The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures.

Nine Months Ended September 30,
(in millions) 2011 2010
Additions to property, plant and equipment $ 2,437 $ 2,703
Change in capital accruals (61 ) (201 )
Capital expenditures, continuing operations $ 2,376 $ 2,502

~~19.~~ Commitments and Contingencies

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

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

Guarantees~~Other contingencies -~~ –~~During the second quarter of 2011, the AOSP operator determined the need and developed preliminary plans to address water flow into a previously mined and contained section~~ After our 2009 sale of the ~~Muskeg River mine. Our share of the estimated costs~~subsidiary holding our interest in the ~~amount~~Corrib natural gas development offshore Ireland, one guarantee of ~~$64 million was recorded~~that entity's performance related to ~~cost~~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 ~~revenues. At~~ September 30, ~~2011, the remaining liability is $56 million.~~2012 are $40 million.

Contractual commitments– –At September 30, 2012 and December 31, 2011, Marathon’s contract commitments to acquire property, plant and equipment were ~~$2,641 million. The decrease from commitment levels previously reported is primarily due to the spin-off of our downstream business on June 30, 2011. See Note 2 for discussion of the spin-off.~~$974 million and $664 million.

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

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

Exploration and Production (“E&P”) which explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.

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 Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in ~~this Form 10-Q and~~ our ~~2010~~2011 Annual Report on Form 10-K.

Key Operating and Financial Activities

~~Spin-off Downstream Business into Independent Company~~In the third quarter of 2012, notable items were:

Net liquid hydrocarbon and natural gas sales volumes of 452 thousand barrels of oil equivalent per day (“mboed”), of which 65 percent was liquid hydrocarbons

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

~~On June 30, 2011, the spin-off~~Eagle Ford shale average net sales volumes of Marathon’s downstream (Refining, Marketing and Transportation) business was completed, creating two independent energy companies: Marathon Petroleum Corporation (“MPC”) and Marathon Oil Corporation. Marathon shareholders at the close40 mboed, an increase of business on the record date of June 27, 2011 received one share of MPC common stock for every two shares of Marathon common stock held. Fractional shares of MPC common stock were not distributed and any fractional share of MPC common stock otherwise issuable to a Marathon shareholder was sold in the open market on such shareholder's behalf, and such shareholder received a cash payment with respect to that fractional share. A tax ruling received in June 201190 percent from the ~~U.S. Internal Revenue Service (“IRS”) affirmed~~second quarter of 2012

Production from Libya increased over the ~~tax-free nature~~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

Closed the acquisition of Paloma Partners II, LLC

Assumed operatorship of the spin-off. Activities related to the downstream business have been treated as discontinued operations in all periods presented in this Form 10-Q (see Note 2 to the consolidated financial statements forVilje field offshore Norway

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

Closed acquisition of an additional ~~information).~~

~~Overview~~

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

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

Assets within these three segments are at various stages in their lifecycle and we further classify them as base, growth or exploration. We have a stable group of base assets, which include our OSM and IG segments and traditional E&P assets in Norway, Equatorial Guinea, the U.K. and the U.S. These assets generate much of the cash that will be available for investment in our growth assets and exploration projects. Growth assets are where we expect to make significant investment in order to realize production and reserve increases. We are focused on North America liquid hydrocarbon growth by developing liquids-rich shale play positions, including the establishment of a dominant position4,300 net acres in the core of the Eagle Ford shale play. In addition to the North America shale plays, growth assets include the development of Angola Block 31 and our Canadian in-situ assets. Our areas of exploration are Poland, the Iraqi Kurdistan Region and the Gulf of Mexico.

~~Operating and Financial Highlights~~

~~Significant operating and financial highlights during the third quarter of 2011 include:~~

·	~~Liquid hydrocarbon and natural gas sales of 349 thousand barrels of oil equivalent per day (“mboepd”), of which 60 percent was liquid hydrocarbons~~

·	~~International liquid hydrocarbon sales, which receive higher prices than West Texas Intermediate (“WTI”) crude oil, were 67 percent of total~~

·	~~Synthetic crude oil sales of 50 thousand barrels per day (“mbpd”), a 61 percent increase over the same period last year~~

·	~~Operating seven rigs and two hydraulic fracturing crews in North Dakota’s Bakken shale play~~

·	~~Operating six rigs in the Anadarko Woodford shale play~~

·	~~Completed the Shi Randall (50 percent working interest) well in the Anadarko Woodford shale which had an initial 30-day production rate of 1,693 mboepd, of which 35 percent was liquids~~

·	~~Added a second drilling rig in the Niobrara shale play~~

·	~~Received exploration permits~~Signed agreement for the Innsbruck (Mississippi Canyon block 993, 85 percent working interest) and Key Largo (Walker Ridge block 578, 60 percent working interest) prospects and lease extensions on 26 blocks in the Gulf of Mexico

·	~~Completed the Ozona well (Garden Banks block 515, 68 percent working interest) as a single zone producer and is ready for first production~~

·	~~Cash-adjusted debt-to-capital ratio of 2 percent, however, this will increase in the fourth quarter of 2011 upon completion of the Eagle Ford shale and gathering system acquisitions~~

·	~~Repurchased approximately 12 million common shares at a cost of $300 million~~

~~Acquisitions and Dispositions~~

Early in the fourth quarter, we closed on the following transactions in Eagle Ford: the previously announced 141,000 net acres from Hilcorp Resources Holdings, LP (“Hilcorp”); additional interests of approximately 19,000 acres net acres; and a gas gathering system. Also, during the fourth quarter, we expect to close on an additional 6,800 net acres in Eagle Ford from tag-along rights. The total acquisition cost for these nearly 167,000 net acres and the gathering system is expected to be approximately $4.5 billion, including projected closing adjustments and future carrying costs. These transactions will be funded largely from existing cash. The acreage includes proved and unproved oil and gas assets, as well as some producing wells. We are in the process of evaluating the acquisitions to determine whether they will be accounted for as business combinations or as asset acquisitions.

~~In October 2011, we entered into definitive agreements to sell our E&P segment’s equity interests in several Gulf of Mexico crude oil pipeline systems including our 28~~20 percent ~~interest in Poseidon Oil Pipeline Company, L.L.C., our 29 percent interest in Odyssey Pipeline L.L.C., our 23 percent~~non-operated interest in the ~~Eugene Island Pipeline System,~~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 ~~certain other oil pipeline interests. The value~~Safen blocks in the Kurdistan Region of ~~this transaction, subject~~Iraq

Issued $2 billion of senior notes

Overview and Outlook

Exploration and Production

Production

Net liquid hydrocarbon and natural gas sales averaged 452 mboed during the third quarter and 414 mboed in the first nine months of 2012 compared to ~~further closing adjustments, is approximately $206 million, net~~349 mboed and 362 mboed in the same periods of ~~debt. In addition,~~2011. Net liquid hydrocarbon sales volumes increased in the ~~Poseidon~~U.S. for both the third quarter and ~~Odyssey interests are subject to wavier~~first nine months of ~~rights~~2012, reflecting the impact of ~~first refusal. The carrying value of these~~production from the Eagle Ford shale assets ~~was $45 million as of September 30, 2011. We expect to close the transaction~~acquired in the fourth quarter of 2011 and our ongoing development programs in the Eagle Ford, Bakken and Anadarko Woodford shale resource plays. The resumption of sales from Libya in the first quarter of 2012 after production had ceased there in February of 2011 was the most significant increase in international sales volumes. In addition, net liquid hydrocarbon sales volumes from the U.K. were lower in the 2012 periods than in the same periods of 2011 due to turnarounds in the third quarter and the timing of liftings.

In 2012, we continued to ramp up operations in the core of the Eagle Ford shale play in Texas. Average net sales volumes from the Eagle Ford shale were 40 mboed and 25 mboed in the third quarter and first nine months of 2012. As announced in August, we have reduced our rig count to 18 operated rigs while maintaining four dedicated hydraulic fracturing crews and two more on a spot basis. During the third quarter of 2012, we drilled 78 gross wells and brought 73 gross wells to sales for a total of 180 gross wells drilled 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.

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

In the Anadarko Woodford shale, net sales volumes averaged 10 mboed and 7 mboed during the third quarter and first nine months of 2012 compared to 2 mboed and 2 mboed in the same periods of 2011. During the third quarter of 2012, eight gross 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 during the third quarter and first nine months of 2012, net sales volumes averaged 53 mboed and 51 mboed. We and our partners in the Waha concessions continue to assess the condition of our assets in Libya and uncertainty around sustained production and sales levels remains.

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

~~Completed~~

In the second quarter of 2012, we completed a four-day turnaround in Norway that was originally scheduled for 14 days in the third quarter. During the third quarter of ~~2011,~~2012, we ~~sold~~became operator of the Vilje field offshore Norway in which we own a 47 percent interest.

A 28-day turnaround began at our ~~Integrated Gas segment’s equity interest~~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 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 ~~liquefied natural gas (“LNG”) processing facility~~2 million barrels of oil equivalent reduction in ~~Alaska. A gain~~proved reserves and a $261 million impairment charge in the first quarter of 2012.

Exploration

The appraisal well on the ~~transaction of $8 million was recorded~~Shenandoah prospect located on Walker Ridge Block 51 in the Gulf of Mexico, in which we have a 10 percent outside-operated working interest, is currently drilling. In the third ~~quarter.~~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 reaching total depth within the next few days at a total net cost, including asset retirement obligations and leasehold costs, of approximately $100 million.

In ~~April 2011,~~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 ~~assigned~~have a 3015 percent ~~undivided~~outside-operated working interest in ~~our Exploration~~the prospect. During the second quarter of 2012, the well costs and ~~Production (“E&P”) segment’s approximately 180,000 acres~~related unproved property costs related to the Kilchurn well were charged to exploration expenses.

We continue exploratory drilling 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 $37 million~~. ~~We remain operator of this jointly owned leasehold.~~

~~Also in April 2011,~~Poland where we farmed-out a 40 percent working interest in 10 concessions in our E&P segment’s Poland’s Paleozoic Shale play. In late July 2011, we sold an additional 9 percent working interest. A $12 million pretax gain was recorded. We currently hold a 51 percent working interest in ~~these~~ 10 operated concessions and ~~serve as operator.~~

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 ~~March 2011,~~the Kurdistan Region of Iraq, we ~~closed~~began drilling our first operated exploration well on the ~~sale of our E&P segment's outside-operated interests~~Harir block in July 2012 and plan to drill an operated exploration well on the Gudrun field development and the Brynhild and Eirin exploration areas offshore Norway for net proceeds of $85 million, excluding working capital adjustments. A $64 million pretax loss on this disposition was recordedSafen block in ~~the fourth quarter 2010.~~

~~During~~ the first quarter ~~2010,~~of 2013. After the farm out discussed below, we ~~closed~~have 45 percent working interests in both the ~~sale~~Harir and Safen blocks. On the non-operated Atrush block, we participated in an appraisal well during the third quarter of 2012. Additionally, we participated in a non-operated well that commenced drilling on the Sarsang block in September 2012. We hold a 20 percent ~~outside-operated~~working interest in ~~our E&P segment’s Production Sharing Contract~~the Atrush block and ~~Joint Operating Agreement in Block 32 offshore Angola. We received net proceeds of $1.3 billion and recorded~~ a ~~pretax gain on the sale~~25 percent working interest in the ~~amount of $811 million. We retained a 10 percent outside-operated interest in Block 32.~~

~~Exploration Projects~~

We have notified our joint venture partner and the Indonesian government that we intend to relinquish the Pasangkayu Production Sharing Contract (PSC). Discussions continue and we are awaiting a government response. We also plan to shift from an operating to a non-operating position in both the Bone Bay and Kumawa PSCs over the coming year.

Sarsang block.

During the first quarter of ~~2011,~~2012, on the Birchwood oil sands lease located in Alberta, Canada, we conducted a seismic survey and drilled ~~94 stratigraphic test~~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 sanction is expected in 2014, with first oil projected in 2017. We have a 100 percent working interest in Birchwood.

Acquisitions and Dispositions

We continually evaluate ways 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 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 ~~drilling results are currently being evaluated. Initial results are positive,~~closing of this transaction combined with the ~~wells encountering expected or greater-than-expected reservoir potential.~~

~~In April 2011, we announced a discovery on the Atrush block~~acquisition of Paloma Partners II, LLC ("Paloma acquisition"), brings our acquisitions thus far in 2012 in the ~~Iraqi Kurdistan Region.~~core of the play to almost 25,000 additional net acres at an approximate cost of $1 billion. The ~~Atrush-1 well was drilled to a total depth of~~Paloma acquisition closed in August 2012 as discussed below. We now have approximately ~~11,000 feet and encountered pay~~230,000 net acres in the ~~Jurassic zones. Test flow rates~~core of the Eagle Ford shale. The unproved property costs related to an additional 100,000 non-core net acres were ~~more than 6,000 gross barrels per day. We hold~~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 ~~Atrush block. A second~~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 ~~Iraqi~~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 ~~was~~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 ~~Swara Tika-1 well on~~KRG for an additional 11 percent in each of the ~~Sarsang block. It was drilled~~two blocks.

In June 2012, we entered an agreement to acquire a total depth of approximately 12,500 feet and encountered 1,500 feet of gross oil column in the Triassic Kura Chine zones. Test flow rates totaled more than 7,000 bpd with associated gas. Test flow rates were limited by tubing sizes and testing equipment. We hold a 2521 percent ~~non-operated~~outside-operated working interest in the ~~Sarsang block.~~Diaba License G4-223 and its related permit onshore Gabon. The ~~Kurdistan Regional Government holds a 4 percent carried interest~~transaction closed in ~~both the Atrush and Sarsang blocks.~~

~~Libya~~

~~Civil unrest, which began~~October 2012. The start of exploration drilling is expected in ~~February 2011 in parts of North Africa, escalated to armed conflict in Libya where we have exploration and production operations. During~~ the first quarter ~~2011, all~~of 2013.

During June 2012, we signed a new production ~~operations~~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 ~~Libya were suspended~~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 ~~are not currently making deliveries of hydrocarbons from~~paid the amount accrued.

In April 2012, we entered agreements to sell our ~~interest~~Alaska assets. One transaction closed in the ~~Waha concession in eastern Libya.~~second quarter of 2012 with proceeds and a net gain of $7 million. The ~~return~~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 ~~operations~~interests in ~~Libya to pre-conflict levels is unknown at this time, however, we~~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 ~~our partners~~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 ~~Waha concession are assessing the condition~~first quarter of ~~our assets and when the resumption of operations will be viable.~~2012.

As of September 30, 2011, our net property, plant and equipment investment in Libya is approximately $758 million and our net proved reserves in Libya were 242 million barrels of oil equivalent (“mmboe”) at December 31, 2010. Sales from Libya in 2010 averaged 46,000 barrels of oil equivalent per day and we are in an underlift position of 847 thousand net barrels of liquid hydrocarbons.

In addition, payments due to the Libyan government or entities affiliated with the Libyan government have been blocked by the U.S. government under a February 25, 2011 executive order. As of September 30, 2011, such amounts, primarily related to taxes and royalties due on our January and February 2011 sales, totaled approximately $200 million.

~~Forward-looking Statements~~

The above discussions include forward-looking statements with respect to the ~~pending acquisitions~~expected production in the Eagle Ford, ~~shale formation,~~Anadarko Woodford and Bakken plays, timing of first production from the ~~status~~Boyla field, anticipated drilling rig and drilling activity, the sale of ~~operations~~our Alaska assets, possible increased recoverable resources from optimized well spacing in ~~Libya,~~the Eagle Ford resource play, the expected closing of an agreement in Ethiopia, anticipated exploration activity in Ethiopia, Gabon, Poland and the Kurdistan Region of Iraq and the timing of the commencement of construction and ~~levels~~first oil on the SAGD project. The projected asset dispositions through 2013 are based on current expectations, estimates, and projections and are not guarantees of future ~~production (including initial production rates), anticipated future exploratory drilling activity and the intended shift from operating to a non-operating position in Indonesia. Some factors~~performance. Factors that could potentially affect ~~these forward-looking statements~~the expected production in the Eagle Ford, Anadarko Woodford and Bakken plays, timing of first production from the Boyla field, exploratory 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 and anticipated drilling rig and drilling activity include pricing, supply and demand for ~~petroleum products, the amount of capital available for exploration~~liquid hydrocarbons and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorists acts and the governmental or military response, and other geological, operating and economic considerations. The completion of the acquisitions in the Eagle Ford shale formation is subject to customary closing conditions. The anticipated shift from operating to a non-operating position in both the Bone Bay and Kumawa PSCs in Indonesia is subject to obtaining necessary government and third-party approvals. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

~~Outlook~~

~~Highlights of our expected future activities include:~~

·	Reaching ten operated drilling rigs in the Eagle Ford shale by year end, plus adding add a third crew dedicated to hydraulic fracturing in January and a fourth crew in June 2012. By this time next year we expect to have 17 rigs operating in the Eagle Ford shale.

·	~~Completing the 27 gross operated wells awaiting completion in the Bakken shale in North Dakota, bringing 33 total wells on production before the end of 2011.~~

·	~~Acquiring seismic data and drilling seven to nine gross wells in the Niobrara shale DJ Basin by yearend~~.

·	~~Starting to drill our first well in Poland the fourth quarter of 2011. By the end of 2012, we plan to drill six to seven wells.~~

·	~~Beginning to drill in the fourth quarter of 2011 on our two operated blocks (Harir and Safen) in the Iraqi Kurdistan Region.~~

·	~~Executing a seismic program on our Birchwood oil sand lease in Alberta, Canada during the winter of 2011-2012 to continue our evaluation of the reservoir for insitu production.~~

·	Reviewing our global asset portfolio with a goal of divesting between $1.5 and $3 billion of non-core assets over the next two to three years, including a potential farm down of a minority interest in our Gulf of Mexico prospects.

~~Progressing toward a 2012 final investment decision on the Quest Carbon Capture and Storage (“”Quest CCS”) project which~~, ~~as announced in the second quarter of 2011, the governments of Alberta and Canada have agreed to partially fund for 865 million Canadian dollars. The financing would be done over a period~~

~~of 15 years, including development, construction and 10 years of operations. However, the funding is subject to conditions of achieving certain performance objectives.~~

·	~~Shutdown of the Muskeg River mine in Alberta, Canada for 10 days in October 2011.~~

·	~~Projecting fourth quarter 2011 E&P segment production of between 360,000 and 370,000 boepd.~~

The above discussions include forward-looking statements with respect to future exploratory and development drilling activity, number of anticipated drilling rig activity, potential assets sales, the goal of divesting $1.5 to $3 billion on non-core assets and the Quest CCS project. Some factors that could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products,natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, 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. ~~Some factors that could potentially affect~~The completion of the sale of ~~$1.5 billion~~our Alaska assets is subject to ~~$3 billion~~necessary government and regulatory approvals and customary closing conditions. The agreement in ~~non-core assets include changes in prices~~Ethiopia is subject to government approvals. The timing of commencement of construction and ~~demand for crude~~first oil natural gas and synthetic crude oil, actions of competitors, future financial condition and operating results, and economic, business, competitive and /or regulatory factors affecting our businesses. The Quest CCSon the SAGD project ~~could also~~can be affected by ~~projected costs and availability of materials and labor, and~~ delays in obtaining orand conditions imposed by necessary government and third-party ~~approvals.~~approvals, board approval, transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, and the other risks associated with construction projects. 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 the 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.

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 portion 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 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. 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 have been volatile in recent years. The following table lists ~~the~~ benchmark crude oil and natural gas price averages in the third quarter and first nine months of ~~2011, when~~2012 compared to the same periods in ~~2010.~~2011.

Three Months Ended September 30, Nine Months Ended September 30,
Benchmark 2011 2010 2011 2010
West Texas Intermediate ("WTI")
crude oil (Dollars per barrel) $ 89.54 $ 76.21 $ 95.47 $ 77.69
Brent (Europe) crude oil (Dollars per barrel) $ 113.46 $ 76.86 $ 111.93 $ 77.13
Henry Hub natural gas
(Dollars per mmbtu)(a)
$ 4.19 $ 4.38 $ 4.16 $ 4.59



	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


^(a)	Settlement date average.

~~Crude~~Average WTI crude oil benchmark prices were higher in 2011 than in 2010 for all periods. Monthly average prices for Dated Brent have been over $100 per barrel since early February 2011. April 2011 WTI averaged $110.04 per barrel, but prices have been declining to an average of $85.61increased 3 percent in the ~~month~~third quarter of ~~September~~2012 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 5935 percent sour in the third quarter and 42 percent sour in the first nine months of 2012 compared to 64 percent and 62 percent in the ~~first nine months~~same periods of ~~2011.~~2011. Reduced production from the Gulf of Mexico and increased onshore production from the Bakken and Eagle Ford shale plays contributed to the lower sour crude percentage in 2012. Sour crude oil contains more sulfur than light sweet WTI. Sour crude oil also tends to be heavier than and sells at a discount to light sweet crude oil because of its higher refining costs and lower refined product values. ~~Our international crude oil production is relatively sweet and a majority is sold in relation to the Dated Brent crude oil benchmark.~~

~~Average natural gas prices have been less volatile in the periods presented.~~ A significant portion of our natural gas production in the lower 48 states of the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas. Average Henry Hub settlement prices for natural gas were lower for the third quarter and first nine months of 2012 compared to the same periods of the prior year. A decline in average settlement date Henry Hub natural gas prices began in September 2011 and continued into 2012. Although prices have stabilized recently, they have not increased appreciably.

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

Oil Sands Mining

OSM segment revenues correlate with prevailing market prices for the various qualities of synthetic crude oil and vacuum gas oil we produce. Roughly two-thirds of our normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil market, primarily Western Canadian ~~Select.~~Select (“WCS”). In 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 at the ~~mine~~mines or upgrader.

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

The table below shows benchmark prices that impacted both our revenues and variable costs for the third quarter and first nine months of ~~2011~~2012 and ~~2010:~~2011:

Three Months Ended September 30, Nine Months Ended September 30,
Benchmark 2011 2010 2011 2010
WTI crude oil (Dollars per barrel) $ 89.54 $ 76.21 $ 95.47 $ 77.69
Western Canadian Select
(Dollars per barrel)(a)
$ 72.14 $ 60.55 $ 76.10 $ 64.72
AECO natural gas sales
index
(Dollars per mmbtu)(b)
$ 3.70 $ 3.44 $ 3.86 $ 3.99



	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
Western Canadian Select (Dollars per barrel)^(a)	$70.49	$72.14	$74.21	$76.10
AECO natural gas sales index (Dollars per mmbtu)^(b)	$2.27	$3.70	$2.03	$3.86


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


^(b)	Monthly average ~~of Alberta Energy Company (“AECO”)~~AECO day ahead index.

Integrated Gas

~~Our integrated gas operations include marketing and transportation of products manufactured from natural gas, such as LNG and methanol, primarily in Europe and West Africa.~~

We have a 60 percent ownership in a production facility in Equatorial Guinea, which sells LNG under a long-term contract ~~at prices tied to~~principally based upon Henry Hub natural gas prices. In general, LNG delivered to the U.S. is tied to Henry Hub prices and will track with changes in U.S. natural gas prices, while LNG sold in Europe and Asia is indexed to crude oil prices and will track the movement of those prices.

We own a 45 percent interest in a methanol plant located in Equatorial ~~Guinea through our investment in Atlantic Methanol Production Company LLC (“AMPCO”).~~Guinea. Methanol demand has a direct impact on ~~AMPCO’s~~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. ~~AMPCO’s~~The plant capacity of 1.1 million tonnes is about 32 percent of ~~total~~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 ~~for 2011 was 26 percent higher~~ in the third quarter of 2012 was 33 percent higher than in the same period of ~~2010, largely~~2011 primarily due to ~~higher liquid hydrocarbon prices. This improvement was offset by a 69 percent continuing~~the previously discussed resumption of our operations in Libya. The effective tax rate ~~in the third quarter of 2011 compared to 55~~was 74 percent in the ~~same period last year. In the~~ third quarter of ~~2011, Marathon incurred a non-cash charge~~2012 compared to 69 percent in the third quarter of ~~$227 million for foreign~~2011, with the increase related to higher income from continuing operations in higher tax credits which we now expect to be unutilized in current or future periods. A higher production outlook for Norway due to better than expected performance contributed to our generating excess foreign tax credits. jurisdictions, primarily Libya.

~~In the first nine months of 2011, consolidated~~ Consolidated income from continuing operations before income taxes in the first nine months of 2012was ~~relatively consistent with~~40 percent higher than in the same period of ~~2010. Higher liquid hydrocarbon prices were offset by lower sales volumes~~2011 primarily due to increased income in ~~the E&P segment. For the first nine months~~Libya. As a result of ~~2011, the~~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 ~~compared to 55 percent in~~for the same period ~~last year.~~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 September 30, Nine Months Ended September 30,
(In millions) 2011 2010 2011 2010
E&P $ 3,212 $ 2,640 $ 9,788 $ 7,712
OSM 427 196 1,180 567
IG 16 38 93 98

Segment revenues 3,655 2,874 11,061 8,377
Elimination of intersegment revenues (6 ) (20 ) (47 ) (49 )
Total revenues $ 3,649 $ 2,854 $ 11,014 $ 8,328

E&P segment revenues increased ~~$572~~$307 million in the third quarter and ~~$2,076~~$539 million in the first nine months of ~~2011~~2012 from the comparable prior-year periods. Revenues in both 2010 periods include the impact of derivative instruments intended to mitigate price risk on future sales of liquid hydrocarbons and natural gas. Net pretax derivative gains of $13 million and $91 million were reported in the third quarter and first nine months of 2010.

Included in our E&P segment are supply optimization activities which include ~~sales~~the purchase of ~~crude oil and natural gas purchased~~commodities from ~~partners and nearby producers~~third parties for ~~sale~~resale. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and ~~achieving~~to achieve flexibility inwithin product ~~type~~types and delivery ~~point. Revenues from these~~points. Volumes associated with supply optimization ~~activities are higher~~have been decreasing in 2012 due to market dynamics and related commodity prices have also been lower in 2012. See the ~~third quarter~~
Cost of revenues discussion as revenues from supply optimization approximate the related costs.

~~and first nine months of 2011 than in comparable periods in part due higher crude oil prices in 2011.~~

Revenues from the sale of our U.S. production are higher in ~~both periods~~the third quarter and first nine months of 2012 primarily as a result of ~~higher~~increased liquid hydrocarbon ~~price realizations, but~~ sales volumes ~~have been more variable among~~from our U.S. shale plays. Lower liquid hydrocarbon and natural gas realizations partially offset the ~~periods.~~volume impact. The following table gives details of net sales and average realizations of our ~~United States~~U.S. operations.

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
United States Operating Statistics
     Net liquid hydrocarbons sales (mbpd) 69 80 73 65
     Liquid hydrocarbon average realization (per bbl) $ 88.89 $ 69.52 $ 91.53 $ 69.95

     Net natural gas sales (mmcfd) 296 363 326 350
     Natural gas average realization (per mcf) $ 4.85 $ 4.43 $ 5.04 $ 4.78



	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

~~The Droshky development in the Gulf of Mexico, which commenced production in July 2010, is the primary reason for the higher liquid hydrocarbon~~(a)Includes crude oil, condensate and natural gas ~~sales volumes~~liquids.

(b)Excludes gains and losses on derivative instruments

Revenues from our international operations are higher in the ~~nine-month period of 2011, however, its production rates declined rapidly and is also a reason for lower liquid hydrocarbon and natural gas sales volumes in the~~ third ~~quarter of 2011. In addition to the impact of Droshky on natural gas volumes, sales were lower in the third~~ quarter and first nine months of ~~2011~~2012 primarily as ~~compared~~a result of the previously discussed resumption of liquid hydrocarbon sales from Libya. Higher average liquid hydrocarbon realizations during the third quarter and first nine months of 2012 also contributed to the same periods of 2010 because the Powder River Basin field which was sold in the second quarter of 2010 primarily produced natural gas, and mature fields continue a natural decline, while gas demand in Alaska decreased in the third quarter of 2011.revenue increase for both periods.

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


	Three Months Ended September 30,					Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2011			2010		2011		2010		2012		2011		2012		2011
International Operating Statistics
Net liquid hydrocarbon (mbpd)
Net liquid hydrocarbon sales (mbbld)^(a)
Europe		108			80		102		92	94		108		97		102
Africa		34			89		44		84	88		34		73		44
Total International		142			169		146		176	182		142		170		146
Liquid hydrocarbon average realizations (per bbl)
Liquid hydrocarbon average realizations (per bbl)^(b)
Europe	$	117.05		$	80.49	$	115.91	$	79.69	$	112.34	$	117.05	$	115.73	$	115.91
Africa		63.51			69.24		75.38		69.85	98.65		63.51		97.00		75.38
Total International	$	104.24	��	$	74.57	$	103.75	$	75.00	$	105.71	$	104.24	$	107.69	$	103.75

Net natural gas sales (mmcfd)
Europe(a)		79			99		92		104
Europe^(c)										100		79		102		92
Africa		453			442		440		399	485		453		434		440
Total International		532			541		532		503	585		532		536		532
Natural gas average realizations (per mcf)
Natural gas average realizations (per mcf)^(b)
Europe	$	9.81		$	7.20	$	10.07	$	6.42	$	10.10	$	9.81	$	10.05	$	10.07
Africa		0.24			0.25		0.24		0.25	0.63		0.24		0.39		0.24
Total International	$	1.67		$	1.52	$	1.95	$	1.52	$	2.25	$	1.67	$	2.23	$	1.95

~~(a)~~
^(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 18 mmcfd and 16 mmcfd for the third quarters of 2012 and 2011, and 16 mmcfd and 15 mmcfd for the ~~third quarters of 2011 and 2010, and 15 mmcfd and 19 mmcfd for the~~ first nine months of ~~2011~~2012 and ~~2010.~~2011.

Compared to 2010, international liquid hydrocarbon sales volumes for the third quarter and first nine months of 2011 are lower due to the temporary cessation of production from Libya in February 2011. Partially offsetting the impact of Libya in both periods, were higher liquid hydrocarbon sales from Europe primarily due to the timing of liftings and from Equatorial Guinea where a turnaround occurred in the first four months of 2010. Natural gas sales volumes from Equatorial Guinea were likewise higher in the 2011 periods due to this turnaround, while natural gas sales volumes from Europe were down primarily related to planned turnarounds and normal production declines in the U.K.

OSM segment revenues ~~revenues~~ increased ~~$231~~$43 million in the third quarter and ~~$613~~$4 million in the first nine months of ~~2011~~2012 compared to the same periods of ~~2010.~~2011. The impact of derivative instruments intended to mitigate price risk relative to future sales of synthetic crude were losses of $8 million and gains of $34 million the third quarter and first nine months of 2010. All derivative positions closed in December 2010. See Note 14 to the consolidated financial statements for additional information about derivative instruments.

~~Excluding the derivative effects, segment revenues increased in both periods of 2011 due to higher synthetic crude oil realizations and volumes as shown on the table below.~~

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
OSM Operating Statistics
Net synthetic crude sales (mbpd) 50 31 43 25
Synthetic crude average realization (per bbl) $ 87.29 $ 67.83 $ 90.91 $ 69.07

~~The 2011 sales volumes improved as a result of the Jackpine mine, which commenced operations in late 2010, and the~~ upgrader expansion was completed and commenced operations in the ~~second~~third quarter of ~~2011. Sales~~2011, resulting in higher sales volumes in ~~2010 were impacted by a turnaround that commenced on March 22, 2010 that caused production~~both periods. However, an increase in the discount of WCS to ~~be completely shut down~~WTI resulted in ~~April, with a staged resumption~~the decreases in ~~May 2010.~~average realizations during the third quarter and first nine months of 2012, partially offsetting the positive volume variance.

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



	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


^(a)	Includes blendstocks.

IG segment revenues ~~revenues~~ decreased ~~$22~~$16 millionin the third quarter and $5$93 million in the first nine months of ~~2011~~2012 compared to the same periods of ~~2010.~~2011. Sales of LNG from our Alaska operations ~~declined throughout~~ ceased in the third quarter of 2011 as when we ~~planned to shut down the LNG~~sold our interest in this production facility.

Unrealized gain on crude oil derivative instruments is included in total revenues but not segment revenues. In the third quarter and first nine months of ~~2011, sales from~~2012, the ~~LNG facility ceased completely because we sold~~net unrealized gain on crude oil derivative instruments was $45 million and there was no comparable derivative activity in similar periods of 2011. See Note 14 to the consolidated financial statements and Item 3. Quantitative and Qualitative Disclosures About Market Risk for additional information about our ~~equity interest in the facility.~~derivative positions.

Income from equity method investments ~~increased $46~~decreased $100 million ~~in the third quarter of 2011 and $115 million~~ in the first nine months of ~~2011~~2012 from the comparable prior-year ~~periods. Higher commodity~~period, primarily due to lower natural gas prices ~~positively impacted the earnings of~~and turnarounds early in 2012 at our facilities in Equatorial Guinea. Also, in January 2012, we sold our equity ~~method investees.~~investments in several Gulf of Mexico crude oil pipelines.

Net gain (loss) on disposal of assets in the third quarter of ~~2011~~2012 primarily ~~relates to sales~~reflects an $18 million loss on the sale of ~~assets in Alaska, including~~undeveloped acreage outside the ~~LNG facility sale previously discussed. Net~~core of the Eagle Ford shale resource play. The net gain on disposal of assets in the first nine months of ~~2011 also includes a gain~~2012 consists primarily of ~~$37 million from assigning a 30 percent undivided working interest in~~ the ~~Niobrara Shale play, where we remain operator. The gain in the first nine months of 2010 primarily related to the $811~~$166 million gain on the sale of ~~a 20 percent outside-operated undivided interest~~our interests in several Gulf of Mexico crude oil pipeline systems, reduced by the $36 million loss on the assignment of our ~~E&P segment’s Production Sharing~~Bone Bay and ~~Joint Operating Agreement~~Kumawa exploration licenses in ~~Block 32 offshore Angola.~~Indonesia and the $18 million loss on the Eagle Ford acreage. See Note 7 to the consolidated financial statements for information about these dispositions.

Cost of revenues ~~increased $493~~decreased $304 million and ~~$1,287~~$666 million in the third quarter and first nine months of ~~2011~~2012 from the comparable periods of ~~2010~~2011 primarily due to our supply optimization activities. ~~WTI~~Volumes associated with supply optimization have been decreasing in 2012 due to market dynamics and related commodity prices have also been lower in 2012. Comparatively, costs related to supply optimization were lower by $438 million for the third quarter and by $677 million for the first nine months of 2012. Excluding the impact of supply optimization activities, E&P segment operating expenses have increased ~~17 percent for~~in proportion to our increased production from U.S. shale plays. Additionally, Integrated Gas segment costs are lower in 2012 due to the sale of our interest in the Alaska LNG facility in the third quarter ~~and 23 percent in the first nine months~~ of 2011.

OSM segment costs increased in total for the third quarter primarily because the Jackpine mine and upgrader expansion operated for the first full quarter. Although gross costs are up due to the increased volumes handled by the expansion, per barrel costs have been declining in comparison with 2010. OSM segment costs also increased in the first nine months of 2011 when compared to the same periods of 2010 due the expansion’s operation start-up costs. These increases were partially offset by no turnaround costs in 2011. We incurred $99 million in the first nine months of 2010 associated with the turnaround. Additionally, estimated net costs of $64 million were recorded in the second quarter of 2011 to address water flow in a previously mined and contained area of the Muskeg River mine.

~~Purchases from related parties~~ increased $52 million in first nine months of 2011 compared to the same periods of 2010. Our most significant related party purchases are from the Alba gas plant in Equatorial Guinea in which we own an equity interest. Higher liquid hydrocarbon prices in 2011 increased the value of those purchases.

Depreciation, depletion and amortization(“DD&A”) ~~decreased $13~~increased $108 million in the third quarter and ~~increased $340~~$63 million in the first nine months of ~~2011~~2012 from the comparable prior-year periods. Because both our E&P and OSM segments apply the units-of-production method to the majority of their assets, the previously discussed increases ~~or decreases~~ in sales volumes generally result in similar changes in DD&A. Decreased DD&A in the third quarter reflects the impact of lower E&P segment sales volumes, partially offset by increases in the OSM segment. For the nine-month period, DD&A increased in both the OSM and E&P segments, despite lower sales volumes in the E&P segment. The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in reserves and capitalized costs, can also cause changes in our DD&A. ~~A higher~~Lower U.S. and International E&P DD&A ~~rate per barrel related~~rates in the third quarter and first nine months of 2012 compared to ~~our domestic E&P operations~~the same periods in 2011 partially offset the impact of ~~lower~~higher sales ~~volumes.~~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. The following table provides DD&A rates for our E&P and OSM segments.

Three Months Ended September 30, Nine Months Ended September 30,
2011 2010 2011 2010
DD&A rate ($ per boe)
E&P Segment
United States $ 24 $ 21 $ 26 $ 18
International $ 10 $ 9 $ 10 $ 9
OSM Segment $ 18 $ 15 $ 17 $ 15



	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

Impairments in the first nine months of ~~2011~~2012 related primarily to ~~our~~the Ozona development in the Gulf of Mexico. Impairments in the first nine months of 2011 related primarily to the Droshky development in the Gulf of Mexico ~~for $273 million~~ and an intangible asset for aan LNG delivery contract at Elba Island. ~~In 2010, impairments were primarily related to the Powder River Basin in the amount of $423 million.~~ See Note 13 to the consolidated financial statements for information about these impairments.

General and administrative expenses increased ~~$43~~$35 million in the third quarter and $18 million in the first nine months of 2011 compared to the same period in 2010 primarily due to additional compensation expense. The first nine months of 2011 also includes higher costs of stock awards due to increased stock price of Marathon before the spin-off.

2012~~Other taxes~~ ~~increased $15 million and $25 million in the third quarter and first nine months of 2011~~ compared to the same periods in 2011. The third quarter of ~~2010. With~~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 ~~revenues, particularly related~~Marathon’s stock price in the period leading up to ~~higher prices, production and ad valorem taxes also increased.~~the spin-off.

Exploration expenses were higher in the third quarter ~~and first nine months~~ of ~~2011~~2012 than in the same ~~periods~~quarter of ~~2010,~~2011, primarily due to larger unproved property impairments. The third quarter of 2012 included $51 million related to unproved property impairments associated with approximately 100,000 net non-core acres in the Eagle Ford shale. Exploration expenses were lower in the first nine months of 2012 than in the previous year, primarily due to dry wells in the Gulf of Mexico, Norway and Indonesia in 2011 compared to one dry Gulf of Mexico well plus various U.S. onshore dry wells in 2012; however, higher ~~dry well costs. Dry well~~unproved property impairments in the Marcellus shale, Eagle Ford shale and Indonesia in 2012 partially offset this decrease. Geological and geophysical (“G&G”) costs increased in the nine months of 2012 primarily related to activity in the Kurdistan Region of Iraq and the seismic survey on our Birchwood oil sands in-situ lease.

The following table summarizes the components of exploration expenses.



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

Net interest and otherincreased $23 million and $98 million in the third quarter and first nine months of 2012 from the comparable periods of 2011. Foreign currency gains were lower in the third quarter of ~~2011 included the final costs of the Earb well in Norway which was deemed dry~~2012 than in the ~~second~~same quarter of ~~2011 and some domestic onshore wells, while dry well costs for the third quarter~~2011. In addition, capitalized interest has been lower in both periods of 2010 were minimal. Dry wells related to Norway, Indonesia and the Gulf of Mexico for the first nine months of 2011 and to the Gulf of Mexico, Equatorial Guinea and Alaska in the first nine months of 2010. Geologic and seismic costs have increased in 2011 primarily related to the U.S. shale plays and the Iraqi Kurdistan Region. The following table summaries these components of exploration expenses.2012.

Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2011 2010 2011 2010
Dry well and unproved property impairment $ 47 $ 11 $ 311 $ 122
Geological, geophysical, seismic 39 12 67 62
Other 43 36 126 98
Total exploration expense $ 129 $ 59 $ 504 $ 282

Loss on early extinguishment of debtrelates to debt retirements in February and March of ~~2011 and in April of 2010.~~2011. See Note 15 to the consolidated financial statements for additional discussion of these transactions.

Provision for income taxes increased ~~$331~~$381 million and ~~$293~~$1,180 million in the third quarter and first nine months of ~~2011~~2012 from the comparable periods of ~~2010.~~

~~The following is an analysis~~2011 primarily due to the increase in pretax income in high tax rate jurisdictions, including the impact of the ~~effective income tax rates for the first nine months~~previously discussed resumption of ~~2011 and 2010:~~

~~As discussed in Note 10 to the consolidated financial statements, we suspended production operations~~sales in Libya in the first quarter of ~~2011, where the statutory~~2012.

The effective income tax rate is in excess of 90 percent. As a result, the effects of foreign operations on our effective tax rate decreased in the first nine months of 2011 compared to the same period of 2010. This decrease was partially offset by a deferred tax charge of $122 million related to an internal restructuring of our international subsidiaries in the second quarter of 2011.

The ability to realize the benefit of foreign tax credits is based on certain estimates concerning future operating conditions (particularly as related to prevailing liquid hydrocarbon, natural gas and synthetic crude oil prices), future financial conditions, income generated from foreign sources and Marathon Oil's tax profile in the years that such credits may be claimed. During the third quarter of 2011 these estimates were revised. The valuation allowance on our deferred tax assets has increased because it is more likely than not that we will be unable to realize all foreign tax credit benefits recorded on taxes being accrued in 2011.

In the second quarter of 2011, we recorded $716 million of deferred U.S. tax on undistributed earnings of $2,046 million that we previously intended to permanently reinvest in foreign operations. Offsetting this tax expense were associated foreign tax credits of $488 million. In addition, we reduced our valuation allowance related to foreign tax credits by $228 million due to recognizing deferred U.S. tax on previously undistributed earnings.

In the second quarter of 2011, we recorded a valuation allowance of $18 million on our deferred tax assets related to state operating loss carryforwards. Due to the spin-off (see Note 2 to the consolidated financial statements), we have determined it is more likely than not that we will be unable to realize all recorded deferred tax assets.

~~The effective tax rate is also~~ influenced by a variety of factors including the ~~geographical~~geographic and functional sources of income and the relative magnitude of these sources of ~~income, foreign currency remeasurement effects, and tax legislation changes. See Note 10 to the consolidated financial statements for further discussion of items impacting our effective tax rate.~~

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~~“Corporate and other unallocated ~~items.~~items” in Note 8 to the consolidated financial statements.

Our effective tax rate in the first nine months of 2012 was 72 percent. This rate is higher than the U.S. statutory rate of 35 percent primarily due to earnings from foreign jurisdictions, primarily Norway and Libya, where the tax 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 production resumed in the fourth quarter of 2011 and liquid hydrocarbon sales resumed in the first quarter of 2012. A reliable estimate of 2012 annual ordinary income from our Libyan operations cannot be made and the range of possible scenarios when including ordinary income from our Libyan operations in the worldwide annual effective tax rate calculation demonstrates significant variability. As such, for the first nine months of 2012, an estimated annual effective tax rate was calculated excluding Libya and applied to consolidated ordinary income excluding Libya and the tax provision applicable to Libyan ordinary income was recorded as a discrete item in the period. Excluding Libya, the effective tax rate would be 64 percent for the first nine months of 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 operations reflect the June 30, 2011 spin-off of our downstream ~~businesses~~business and the historical results of those operations, net of tax, for all periods presented.

Segment Results

~~Segment Results~~

Segment income ~~(loss)~~ is summarized in the following ~~table:~~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 September 30, Nine Months Ended September 30,
(In millions) 2011 2010 2011 2010
E&P
    United States $ 81 $ 99 $ 237 $ 233
    International 249 411 1,362 1,211
            E&P segment 330 510 1,599 1,444

OSM 92 18 193 (59 )
IG 55 41 158 109

            Segment income 477 569 1,950 1,494
Items not allocated to segments, net of income taxes:
     Corporate and other unallocated items (79 ) (50 ) (215 ) (130 )
     Foreign currency remeasurement of income taxes 23 (37 ) 6 33
     Impairments - (15 ) (195 ) (286 )
     Loss on early extinguishment of debt - - (176 ) (57 )
     Tax effect of subsidiary restructuring - - (122 ) -
     Deferred income tax items (15 ) - (65 ) (45 )
     Water abatement - Oil Sands - - (48 ) -
     Gain on dispositions (1 ) - 23 449
         Income from continuing operations 405 467 1,158 1,458
         Discontinued operations - 229 1,239 404
Net income $ 405 $ 696 $ 2,397 $ 1,862

United States E&P income ~~decreased $18~~increased $29 million in the third quarter and increased $4$52 million in the first nine months of ~~2011~~2012 compared to the same periods of ~~2010.~~2011. The income ~~decrease~~increase in both ~~the third quarter of 2011~~periods was primarily the result of ~~lower~~higher liquid hydrocarbon ~~and natural gas~~ sales volumes ~~increased production costs and exploration expenses,~~as previously discussed, partially offset by ~~higher liquid hydrocarbon realizations. For the nine-month period, the increase in~~lower liquid hydrocarbon realizations and ~~sales volumes were partially offset by~~the impact of increased production operations on DD&A ~~production costs,~~and operating expenses. In addition, exploration expenses ~~and lower derivative revenue.~~were higher primarily due to higher unproved property impairments.

International E&P income ~~decreased $162~~increased $127 million in the third quarter and ~~increased $151~~decreased $271 million in the first nine months of ~~2011~~2012 compared to the same periods of ~~2010.~~2011. Segment income, before taxes, increased in both periods primarily due to ~~40 percent and 38 percent~~the previously discussed higher liquid hydrocarbon ~~price realizations for the third quarter and first nine months of 2011. Decreased~~ sales volumes ~~as previously discussed,~~and realizations, partially offset ~~the benefit of higher realizations, but higher income taxes had the most significant impact on decreasing segment income.~~by increased operating costs. As previously discussed, increased income before tax in higher tax jurisdictions resulted in a higher effective tax rate in the ~~third quarter~~first nine months of ~~2011, a valuation allowance was recorded on our deferred tax assets, as it is more likely than not we will be unable~~2012 compared to ~~realize all foreign tax credit benefits recorded on taxes accrued in 2011.~~the same period of 2011.

OSM segment income ~~increased $74~~decreased $27 million and ~~$252~~$36 million in the third quarter and first nine months of ~~2011.~~2012. As previously discussed, ~~higher sales volumes and~~lower synthetic crude oil price realizations ~~in the third quarter and the first nine months of 2011~~ were the primary ~~reasons~~reason for the ~~increase~~decrease in income. This was partially offset by ~~increased~~decreased costs on a per unit basis and higher ~~DD&A.~~sales volumes.

IG segment income ~~increased $14~~decreased $16 million and ~~$49~~$102 million in the third quarter ~~of 2011~~ and first nine months of ~~2011~~2012 compared to the same periods of ~~2010. Third quarter~~ 2011 ~~income also includes~~ 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 in the ~~gain on~~first nine months of 2012 due to the sale of our interest in the Alaska LNG production facility. In Equatorial Guinea, higher third quarter earnings from our equity method investment in Atlantic Methanol Production Company were due to higher methanol sales volumes and realizations. The LNG facility in ~~Equatorial Guinea had operational availability of 97 percent for~~ the third quarter of ~~2010, but realized prices were below 2010 levels.~~2011.

Critical Accounting Estimates

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

~~Management’s Discussion and Analysis of~~ Cash Flows and Liquidity

Cash Flows

~~Cash Flows~~

Net cash provided by continuing operations ~~totaled $4,400~~was $2,812 million in the first nine months of ~~2011,~~2012, compared to ~~$3,099~~$4,400 million in the first nine months of ~~2010~~2011 primarily reflecting ~~primarily~~ the impact of ~~higher~~lower U.S. liquid hydrocarbon and natural gas prices on operating ~~income.~~income and higher cash tax payments. See Note 17 to the consolidated financial statements for amounts of the cash tax payments.

Net cash used in investing activities totaled ~~$2,611~~$4,031 million in the first nine months of ~~2011,~~2012, compared to ~~$2,256~~$2,118 million related to continuing operations in the first nine months of ~~2010.~~2011. Significant investing activities are additions to property, plant and equipment and disposal of assets. In the first nine months of ~~2011,~~2012, most of the additions were in the E&P segment with continued spending on U.S. unconventional resource plays, particularly the Eagle Ford shale. This compares to additions in the first nine months of 2011 which also included spending on U.S. unconventional resource plays, though at a lower level, and drilling in Norway, Indonesia and the ~~Iraqi~~ Kurdistan ~~Region. This compares to spending in the first nine months~~Region of 2010 which was more focused upon the U.S., particularly the Gulf of Mexico. Spending has slowed compared to 2010 in our OSM segment as the upgrader portion of AOSP Expansion 1 was completed and commenced operations in the second quarter 2011.Iraq. In the first nine months of ~~2010, the majority of sales proceeds were from the sale of a portion of our interest in Block 32 offshore Angola.~~2012, expenditures for acquisitions totaled $806 million primarily related to acquiring additional Eagle Ford shale properties. Deposits totaling $120 million were paid in the first nine months of 2011 related to the Eagle Ford shale acreage ~~acquisitions.~~acquisitions that closed later that year.

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

Net cash ~~used in~~provided by financing activities was ~~$2,182~~$1,385 million in the first nine months of ~~2011,~~2012, compared to ~~$1,146~~net cash used in financing activities related to continuing operations of $5,098 million in the first nine months of ~~2010.~~2011. During the first nine months of 2012, 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 million of debt upon its maturity. During the first nine months of 2011, we retired $2.5 billion aggregate principal amount of our debt before it was due and distributed $1.6 billion to Marathon Petroleum Corporation in connection with the spin-off of the downstream business. Dividends paid were a significant use of cash in both periods. During the first quarter of 2011, we retired $2.5 billion aggregate principal amount of our debt. In the first nine months of 2010, we retired $500 million aggregate principal value of debt. In connection with the spin-off, we distributed $1.6 billion to MPC in the second quarter of 2011.

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 ~~$3.0 billion~~ committed revolving credit facility, and sales of ~~non-core~~non-strategic assets. Our working capital requirements are supported by these sources and we may issue commercial paper backed by our $2.5 billion revolving credit facility to meet short-term cash requirements. We issued $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 ~~including internally generated cash flow~~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

At September 30, ~~2011,~~2012, we had no borrowings against our revolving credit facility, described below, and no$1.8 billion 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 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.

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

Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 225 percent at September 30, 2012, compared to 20 percent at ~~September 30, 2011, compared to 14 percent at~~ December 31, ~~2010. This cash-adjusted debt-to-capital ratio will increase in the fourth quarter of~~ 2011 ~~upon completion of the Eagle Ford shale acreage and gathering system acquisitions. This includes $217 million of debt that is serviced by United States Steel Corporation (“United States Steel”)~~. ~~United States Steel has issued calls for the fourth quarter of 2011 on the environmental revenue bonds.~~



	September 30,			December 31,
(In millions)	2012			2011
Commercial paper	$	1,839		$	—
Long-term debt due within one year	183			141
Long-term debt	4,518			4,674
Total debt	6,540			4,815
Cash	671			493
Equity	$	18,064		$	17,159
Calculation:
Total debt	$	6,540		$	4,815
Minus cash	671			493
Total debt minus cash	5,869			4,322
Total debt	6,540			4,815
Plus equity	18,064			17,159
Minus cash	671			493
Total debt plus equity minus cash	$	23,933		$	21,481
Cash-adjusted debt-to-capital ratio	25		%	20		%

September 30, December 31,
(In millions) 2011 2010
    Long-term debt due within one year $ 338 $ 295
    Long-term debt 4,705 7,601

            Total debt $ 5,043 $ 7,896

    Cash $ 4,633 $ 3,951
    Equity $ 16,756 $ 23,771

    Calculation:

    Total debt $ 5,043 $ 7,896
    Minus cash 4,633 3,951

            Total debt minus cash $ 410 $ 3,945

    Total debt 5,043 7,896
    Plus equity 16,756 23,771
    Minus cash 4,633 3,951

            Total debt plus equity minus cash $ 17,166 $ 27,716

    Cash-adjusted debt-to-capital ratio 2 % 14 %

Capital Requirements

During the fourth quarter of 2011, we are closing the Eagle Ford shale acreage and gathering system acquisitions for approximately $4.5 billion, including projected closing adjustments and future carrying costs. The acquisitions will be funded largely from existing cash balances.

On October ~~26, 2011,~~31, 2012, our Board of Directors approved a dividend of 1517 cents per share for the third quarter of ~~2011,~~2012, payable December ~~12, 2011~~10, 2012 to stockholders of record at the close of business on November ~~16, 2011.~~21, 2012.

In October and early November 2012, we paid $264 million for closed acquisition transactions.

~~Since January 2006,~~In the first quarter of 2012, we increased our ~~Board~~2012 capital, investment and exploration budget, excluding acquisition costs, from $4.8 billion to $5.0 billion, of Directors has authorized a common share repurchase program totaling $5 billion. As of September 30, 2011, we had repurchased 78 million common shares at a cost of $3,222 million, with 12 million shares at a cost of $300 millionwhich $4.6 billion will be used for capital expenditures. The increase reflects development plans for the additional acreage acquired in the third quarter of 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 financial condition or changes in market conditionsEagle Ford shale and is subject to termination prior to completion. The program’s authorization does not include specific price targets or timetables. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and market conditions.other adjustments.

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 ~~completion of the agreements to purchase assets in the Eagle Ford shale formation is subject to customary closing conditions. The~~above discussions also contain forward-looking statements about our ~~common stock repurchase program are based on current expectations, estimates~~2012 capital, investment and ~~projections and are not guarantees of future performance.~~exploration budget. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially are changes in prices of and demand for ~~crude oil,~~liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of our production and mining 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 our consolidated contractual cash obligations to make future payments under existing contracts as of September 30, ~~2011:~~2012.

2012- 2014- Later
(In millions) Total 2011 2013 2015 Years
Long-term debt (excludes interest)(a)
$ 5,035 $ 232 $ 346 $ 137 $ 4,320
Sale-leaseback financing
Capital lease obligations(a)
50 - 23 2 25
Operating lease obligations(a)
261 15 75 57 114
Operating lease obligations under sublease(a)

Purchase obligations:
Crude oil and feedstock contracts 76 10 62 3 1
Transportation and related contracts 1,198 97 222 153 726
Contracts to acquire property, plant and equipment 2,641 347 617 568 1,109
LNG terminal operating costs(b)
123 3 26 26 68
Service and materials contracts(c)
890 62 308 122 398
Unconditional purchase obligations(d)
40 8 16 16 -
Commitments for oil and gas exploration
(non-capital)(e)
37 27 4 1 5
Other long-term liabilities reported
in the consolidated balance sheet(f)
2,800 233 863 717 987
Total contractual cash obligations(g)
$ 13,151 $ 1,034 $ 2,562 $ 1,802 $ 7,753



					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)~~	~~Includes debt~~
^(a)	Oil and ~~lease obligations assumed by United States Steel upon the USX Separation.~~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)~~

We have the right to deliver 58 bcf of natural gas per year to the Elba Island LNG re-gasification terminal. The agreement’s primary term ends in 2021. Pursuant to this agreement, we are also committed to pay for a portion of the operating costs of the terminal.

~~(c)~~

^(b)

Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.

~~(d)~~

~~We are party to a long-term transportation services agreement with Alliance Pipeline. This agreement was used by Alliance Pipeline to secure its financing.~~

~~(e)~~

Commitments for oil and gas exploration (non-capital) include estimated costs related to contractually obligated exploratory work programs that are expensed immediately, such as geological and geophysical costs.

^(c)

~~(f)~~

Primarily includes obligations for pension and other postretirement benefits including medical and life insurance, which we have estimated through ~~2019.~~2021. Also includes amounts for uncertain tax positions.

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

~~Receivable from United States Steel~~

We remain obligated (primarily or contingently) for $221 million of certain debt and other financial arrangements for which United States Steel has assumed responsibility for repayment (see the USX Separation in Item 1. of our 2010 Annual Report on Form 10-K). United States Steel has issued calls on the environmental revenue bonds the fourth quarter of 2011. United States Steel reported in its Form 10-Q for the three months ended September 30, 2011 that it believes that its liquidity will be adequate to satisfy its obligations for the foreseeable future.

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.

In August 2011, the Environmental Protection Agency (“U.S. EPA”) published proposed New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAP”) that will both amend existing NSPS and NESHAP standards for oil and gas facilities as well as create a new NSPS for oil and gas production, transmission and distribution facilities. If the proposed rules are finalized without substantial modification, compliance

with the rules will result in an increase in costs of control, equipment, and labor, and require additional notification, monitoring, reporting, and recordkeeping. The U.S. EPA is required to finalize the rule by April of 2012.

In July 2011, the U.S. EPA finalized a Federal Implementation Plan under the Clean Air Act (“CAA”) that includes New Source Review (“NSR”) regulations which apply to air emissions sources on Tribal Lands. This rule became effective on August 30, 2011, and requires the registration and/or pre-construction permitting of most of our facilities on Tribal Lands in Wyoming, Oklahoma, and North Dakota. With respect to these facilities, the U.S. EPA has determined that pre-construction permitting is required under the new rules. We do not agree with this assessment and are continuing to work with the U.S. EPA to resolve. However, to minimize pre-construction delays in the near term, we entered into an Administrative Compliance and Consent Agreement (“Agreement”) that temporarily suspended the requirement for pre-construction permits for facilities on Tribal Lands in North Dakota as long as permit applications were filed in accordance with the Agreement (discussed further in Legal Proceedings). We cannot reasonably estimate the final financial impact of these new permitting requirements until the U.S. EPA finalizes its internal permitting procedures and expected challenges to the new NSR regulations are resolved.

There have been no ~~other~~ significant changes to our environmental matters subsequent to December 31, ~~2010.~~2011.

Other Contingencies

~~During~~Litigation – In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the ~~second quarter~~District Court of ~~2011, the AOSP operator determined the need and developed preliminary plans to address water flow into a previously mined and contained section~~Harris County, Texas alleging, among other things, breach of contract, breach of the ~~Muskeg River mine. Our share~~duty of ~~the estimated costs~~good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. Noble is seeking an unspecified amount of ~~$64 million was recorded to cost of revenues. At September 30, 2011, the remaining liability is $56 million.~~

~~Critical Accounting Estimates~~

damages. We are vigorously defending this litigation. The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used.

Certain accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material.

~~There have been no changes to our critical accounting estimates related to continuing operations subsequent to December 31, 2010.~~

~~Accounting Standards Not Yet Adopted~~

In September 2011, the Financial Accounting Standards Board (“FASB”) amended accounting standards to simplify how entities test goodwill for impairment. The amendments reduce complexity by allowing an entity the option to make a qualitative evaluation of whether it is necessary to perform the two-step goodwill impairment test. The amendment is effective for our interim and annual periods beginning with the first quarter of 2012. Early adopting is permitted, but we were unable to do so because our annual goodwill impairment testing was completed prior to the issuance of the amendment. Adoptionultimate outcome of this ~~amendment will not have a significant impact~~lawsuit, including any financial effect 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 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 other comprehensive income, and the total of comprehensive income. The presentation of items that are reclassified from other comprehensive income to net on the income statement is also required. The amendments did not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. The amendments are effective for us, ~~beginning with the first quarter of 2012. We are still evaluating this reporting~~

~~standard, but we do not expect adoption of this amendment to have an 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 U.S. generally accepted accounting principles (“U.S. GAAP”) and International Financial Reporting Standards (“IFRS”). The amendments change the wording used to describe certain of the U.S. GAAP requirements either to clarify the intent of existing requirements, to change measurement or expand disclosure principles or to conform to the wording used in IFRS. The amendments are to be applied prospectively and will be effective for our interim and annual periods beginning with the first quarter of 2012. Early application is not permitted.remains uncertain. We do not ~~expect adoption~~believe an estimate of ~~these amendments to have~~ a ~~significant impact on our consolidated results~~reasonably probable loss (or range of ~~operations, financial position or cash flows.~~loss) can be made for this lawsuit at this time.

Item 3. Quantitative and Qualitative Disclosures ~~about~~About Market Risk

For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A7A. Quantitative and Qualitative Disclosures ~~about~~About Market Risk in our ~~2010~~2011 Annual Report on Form 10-K.

In August 2012, we entered crude oil derivatives related to a portion of our forecast U.S. E&P crude oil sales through December 31, 2013. Disclosures about how derivatives are reported in our consolidated financial statements and how the fair values of our derivative instruments are measured may be found in Notes 13 and 14 to the consolidated financial statements.

~~The majority of our previous derivative activity was conducted by our downstream business.~~ Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent increases and decreases in commodity ~~derivatives~~prices on our open commodity derivative instruments, by contract type as of September 30, 2012 is provided in the following table.



	Incremental Change in IFO from a Hypothetical Price Increase of						Incremental Change in IFO from a Hypothetical Price Decrease of
	10%			25%			10%		25%
Crude oil
Swaps	$	(207	)	$	(519	)	$	207	$	519
Option Collars	(105		)	(277		)	103		275
Total crude oil	(312		)	(796		)	310		794
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 ~~interest rate swaps related to continuing operations has not changed significantly.~~liabilities as of September 30, 2012 is provided in the following table.



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


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


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

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

Item 4. Controls and Procedures

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

In 2012, we began a project to update our existing ERP system. The project includes implementation of 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, ~~2011,~~2012, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
(In millions) 2011 2010 2011 2010

Segment Income (Loss)
     Exploration and Production
          United States $ 81 $ 99 $ 237 $ 233
          International 249 411 1,362 1,211
               E&P segment 330 510 1,599 1,444
     Oil Sands Mining 92 18 193 (59 )
     Integrated Gas 55 41 158 109
          Segment income 477 569 1,950 1,494
               Items not allocated to segments, net of income taxes (72 ) (102 ) (792 ) (36 )
         Income from continuing operations 405 467 1,158 1,458
         Discontinued operations - 229 1,239 404
              Net income $ 405 $ 696 $ 2,397 $ 1,862
Capital Expenditures(a)

     Exploration and Production
          United States $ 502 $ 352 $ 1,407 $ 1,222
          International 182 234 694 552
               E&P segment 684 586 2,101 1,774
     Oil Sands Mining 36 191 236 699
     Integrated Gas 1 1 2 2
     Corporate 7 13 37 27
               Total $ 728 $ 791 $ 2,376 $ 2,502
Exploration Expenses
     United States $ 75 $ 34 $ 280 $ 192
     International 54 25 224 90
               Total $ 129 $ 59 $ 504 $ 282




	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


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


^(b)	Capital expenditures include changes in accruals.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,				Three Months Ended				Nine Months Ended
	2011		2010		2011		2010		September 30,				September 30,
									2012		2011		2012		2011
E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbpd)
Net Liquid Hydrocarbon Sales (mbbld)
United States		69		80		73		65	111		69		98		73

Europe		108		80		102		92	94		108		97		102
Africa		34		89		44		84	88		34		73		44
Total International		142		169		146		176	182		142		170		146
Worldwide		211		249		219		241	293		211		268		219
Net Natural Gas Sales (mmcfd)
United States		296		363		326		350	366		296		343		326

Europe(b)		79		99		92		104
Europe^(c)									100		79		102		92
Africa		453		442		440		399	485		453		434		440
Total International		532		541		532		503	585		532		536		532
Worldwide		828		904		858		853	951		828		879		858
Total Worldwide Sales (mboepd)		349		399		362		382

Total Worldwide Sales (mboed)									452		349		414		362
Average Realizations ~~(e)~~(d)
Liquid Hydrocarbons (per bbl)
United States	$	88.89	$	69.52	$	91.53	$	69.95	$83.80		$88.89		$86.98		$91.53

Europe		117.05		80.49		115.91		79.69	$112.34		$117.05		$115.73		$115.91
Africa		63.51		69.24		75.38		69.85	$98.65		$63.51		$97.00		$75.38
Total International		104.24		74.57		103.75		75.00	$105.71		$104.24		$107.69		$103.75
Worldwide	$	99.24	$	72.95	$	99.68	$	73.64	$97.40		$99.24		$100.10		$99.68

Natural Gas (per mcf)
United States	$	4.85	$	4.43	$	5.04	$	4.78	$3.61		$4.85		$3.73		$5.04

Europe		9.81		7.20		10.07		6.42	$10.10		$9.81		$10.05		$10.07
Africa(c)		0.24		0.25		0.24		0.25
Africa^(e)									$0.63		$0.24		$0.39		$0.24
Total International		1.67		1.52		1.95		1.52	$2.25		$1.67		$2.23		$1.95
Worldwide	$	2.81	$	2.69	$	3.12	$	2.86	$2.77		$2.81		$2.81		$3.12

OSM Operating Statistics
Net Synthetic Crude Sales (mbpd) (d)		50		31		43		25
Synthetic Crude Average Realization (per bbl)(e)	$	87.29	$	67.83	$	90.91	$	69.07

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 (mtpd) (f)
Net Sales (mtd) ^(g)
LNG		6,935		7,142		7,121		6,502	7,065		6,935		6,277		7,121
Methanol		1,366		1,069		1,310		1,120	1,146		1,366		1,242		1,310

~~(b)~~
^(c)	Includes natural gas acquired for injection and subsequent resale of 1618 mmcfd and 1516 mmcfd for the third quarters of ~~2011~~2012 and ~~2010,~~2011, and 1516 mmcfd and 1915 mmcfd for the first nine months of ~~2011~~2012 and ~~2010.~~2011.

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


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

~~(d)~~
^(f)	Includes blendstocks.

~~(e)~~

~~Excludes gains and losses on derivative instruments.~~

~~(f)~~

^(g)

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

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

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

~~Environmental Proceedings~~

As discussed in Item-2: Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Matters, in August 2011, we entered into an Administrative Compliance and Consent Agreement with the U.S. EPA that temporarily suspended the requirement for pre-construction permits for our well pad facilities on Tribal Lands in North Dakota as long as permit applications were filed in accordance with the schedule set forth in this Agreement. We also agreed to pay $294,000 in settlement of this matter, which also provided coverage for alleged violations of the Clean Air Act.

WeThere have been ~~working with~~no significant changes in legal or environmental proceedings during the ~~North Dakota Department~~first nine months of Health to resolve voluntary disclosures we made in 2009 relating to potential Clean Air Act violations relating to our operations on State lands in the Bakken. The amount of the potential fine is estimated to be $100,000.2012.

~~SEC Investigation Relating to Libya~~

On May 25, 2011 we received a subpoena issued by the Securities and Exchange Commission (“SEC”) requiring the production of documents related to payments made to the government of Libya, or to officials and persons affiliated with officials of the government of Libya. We have been and intend to continue cooperating with the SEC in its investigation.

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 ~~2010~~2011 Annual Report on Form 10-K. ~~The following is an update to our risk factors.~~

The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.

Hydraulic fracturing is a commonly used process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. The U.S. Congress has considered legislation that would require additional regulation affecting the hydraulic fracturing process. Consideration of new federal regulation and increased state oversight continues to arise. The U.S. EPA announced in the first quarter of 2010 its intention to conduct a comprehensive research study on the potential effects that hydraulic fracturing may have on water quality and public health. The U.S. EPA has begun preparation for the study and expects to complete the study in 2012. In addition, various state-level initiatives in regions with substantial shale gas resources have been or may be proposed or implemented to further regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal or state laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a

~~decrease in the completion of new oil and gas wells and increased compliance costs, which could adversely affect our financial position, results of operations and cash flows.~~

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

The following table provides information about purchases by Marathon Oil during the quarter ended September 30, 2012, 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 Shares Purchased as Part of Publicly Announced Plans or Programs (c)

Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (c)

Total Number of Average Price Paid
Period
Shares Purchased (a)
per Share

07/01/11 – 07/31/11 7,487 $ 32.68 - $ 2,080,366,711
08/01/11 – 08/31/11 12,026,149 $ 25.25 11,898,200 $ 1,780,609,536
09/01/11– 09/30/11 43,767 (b) $ 24.66 - $ 1,780,609,536
Total 12,077,403 $ 25.25 11,898,200



	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	—

~~(a)~~	~~142,319~~
^(a)	162,184 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

~~(b)~~

~~36,884~~

^(b)

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

^(c)

We announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion. As of September 30, ~~2011,~~2012, 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:

~~Exhibit Number~~

Incorporated by Reference

~~Filed Herewith~~

~~Furnished Herewith~~

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 ~~and Treasurer~~ 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 ~~and Treasurer~~ pursuant to 18 U.S.C. Section 1350.

101.INS

XBRL Instance ~~Document~~Document.

101.SCH

XBRL Taxonomy Extension ~~Schema~~Schema.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.

101.CAL

XBRL Taxonomy Extension Calculation ~~Linkbase~~Linkbase.

~~101.PRE~~101.DEF

XBRL Taxonomy Extension ~~Presentation Linkbase~~Definition Linkbase.

101.LAB

XBRL Taxonomy Extension Label ~~Linkbase~~

~~101.DEF~~

~~XBRL Taxonomy Extension Definitions Linkbase~~Linkbase.

SIGNATURES

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



November ~~4, 2011~~7, 2012		MARATHON OIL CORPORATION

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

(In millions)	Preferred Stock		Common Stock		Securities Exchangeable for Common Stock		Treasury Stock			Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Non-controlling Interest		Total Stockholders' Equity
December 31, 2010 Balance	$	-	$	770	$	-	$	(2,665	)	$	6,756		$	19,907		$	(997	)	$	-	$	23,771
Shares issued - stock
based compensation		-		-		-		251			(84	)		-			-					167
Shares repurchased		-		-		-		(307	)		-			-			-					(307	)
Stock-based compensation		-		-		-		-			(2	)		-			-					(2	)
Net income		-		-		-		-			-			2,397			-					2,397
Other comprehensive income		-		-		-		-			-			-			82					82
Dividends paid		-		-		-		-			-			(462	)		-					(462	)
Purchase of subsidiary shares
from noncontrolling interest		-		-		-		-			-			-			-			8		8
Spin-off of downstream
business		-		-		-		-			5			(9,490	)		587					(8,898	)
September 30, 2011 Balance	$	-	$	770	$	-	$	(2,721	)	$	6,675		$	12,352		$	(328	)	$	8	$	16,756

(Shares in millions)	Preferred Stock		Common Stock		Securities Exchangeable for Common Stock		Treasury Stock
December 31, 2010 Balance		-		770		-		(60	)
Shares issued - stock
based compensation		-		-		-		6
Shares repurchased		-		-		-		(12	)
September 30, 2011 Balance		-		770		-		(66	)

	Three Months Ended September 30, 2010
(In millions)	E&P			OSM		IG		Total

Revenues:
Customer	$	2,605		$	196	$	38	$	2,839
Intersegment		20			-		-		20
Related parties		15			-		-		15
Segment revenues		2,640			196		38		2,874
Elimination of intersegment revenues		(20	)		-		-		(20	)
Total revenues	$	2,620		$	196	$	38	$	2,854
Segment income	$	510		$	18	$	41	$	569
Income from equity method investments		51			-		51		102
Depreciation, depletion and amortization		491			28		1		520
Income tax provision		579			2		21		602
Capital expenditures		586			191		1		778

	Nine Months Ended September 30, 2010
(In millions)	E&P			OSM			IG		Total

Revenues:
Customer	$	7,622		$	567		$	98	$	8,287
Intersegment		49			-			-		49
Related parties		41			-			-		41
Segment revenues		7,712			567			98		8,377
Elimination of intersegment revenues		(49	)		-			-		(49	)
Total revenues	$	7,663		$	567		$	98	$	8,328
Segment income (loss)	$	1,444		$	(59	)	$	109	$	1,494
Income from equity method investments		128			-			142		270
Depreciation, depletion and amortization		1,279			67			3		1,349
Income tax provision (benefit)		1,741			(15	)		56		1,782
Capital expenditures		1,774			699			2		2,475

	December 31, 2010
(In millions)	Level 1			Level 2		Level 3			Collateral		Total
Derivative instruments, assets
Commodity	$	58		$	-	$	1		$	81	$	140
Interest rate		-			32		-			-		32
Derivative instruments, assets		58			32		1			81		172
Derivative instruments, liabilities
Commodity		(102	)		-		(3	)		-		(105	)
Derivative instruments, liabilities	$	(102	)	$	-	$	(3	)	$	-	$	(105	)

	September 30, 2011				December 31, 2010
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other current assets	$	223	$	220	$	226	$	220
Other noncurrent assets		273		276		396		231
Total financial assets		496		496		622		451
Financial liabilities
Long-term debt, including current portion(a)		5,636		4,985		8,364		7,527
Deferred credits and other liabilities		33		35		66		67
Total financial liabilities	$	5,669	$	5,020	$	8,430	$	7,594

(In millions)
6.000% notes due 2012	$	400
6.125% notes due 2012		450
8.375% secured notes due 2012(a)		448
6.500% debentures due 2014		700
5.900% notes due 2018		40
7.500% debentures due 2019		460
Total debt purchases	$	2,498

						2012-		2014-	Later
(In millions)	Total		2011			2013		2015	Years
Long-term debt (excludes interest)(a)	$	5,035	$	232	$	346	$	137	$	4,320
Sale-leaseback financing
Capital lease obligations(a)		50		-		23		2		25
Operating lease obligations(a)		261		15		75		57		114
Operating lease obligations under sublease(a)
Purchase obligations:
Crude oil and feedstock contracts		76		10		62		3		1
Transportation and related contracts		1,198		97		222		153		726
Contracts to acquire property, plant and equipment		2,641		347		617		568		1,109
LNG terminal operating costs(b)		123		3		26		26		68
Service and materials contracts(c)		890		62		308		122		398
Unconditional purchase obligations(d)		40		8		16		16		-
Commitments for oil and gas exploration
(non-capital)(e)		37		27		4		1		5
Other long-term liabilities reported
in the consolidated balance sheet(f)		2,800		233		863		717		987
Total contractual cash obligations(g)	$	13,151	$	1,034	$	2,562	$	1,802	$	7,753