Edgar Filing: MARATHON OIL CORP

form10q2012q1.htm

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 June 30, 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 Street, Houston, TX 77056-2723

(Address of principal executive offices)

(713) 629-6600

(Registrant’s telephone number, including area code)

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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o

There were 705,432,356 shares of Marathon Oil Corporation common stock outstanding as of June 29, 2012.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended June 30, 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
	Notes to Consolidated Financial Statements (Unaudited)		6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		30
Item 4.	Controls and Procedures		30
	Supplemental Statistics (Unaudited)		31
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		33
Item 1A.	Risk Factors		33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		33
Item 4.	Mine Safety Disclosures		33
Item 6.	Exhibits		34
	Signatures		35

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

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions, except per share data)	2012			2011			2012			2011
Revenues and other income:
Sales and other operating revenues	$	3,718		$	3,680		$	7,495		$	7,336
Sales to related parties		13			14			27			29
Income from equity method investments		60			120			138			237
Net gain (loss) on disposal of assets		(28	)		45			138			50
Other income		21			6			26			22
Total revenues and other income		3,784			3,865			7,824			7,674
Costs and expenses:
Cost of revenues (excludes items below)		1,302			1,667			2,709			3,071
Purchases from related parties		56			71			119			127
Depreciation, depletion and amortization		580			564			1,154			1,199
Impairments		1			307			263			307
General and administrative expenses		130			130			250			267
Other taxes		67			53			145			111
Exploration expenses		173			145			315			375
Total costs and expenses		2,309			2,937			4,955			5,457
Income from operations		1,475			928			2,869			2,217
Net interest and other		(57	)		(13	)		(107	)		(32	)
Loss on early extinguishment of debt		-			-			-			(279	)
Income from continuing operations before income taxes		1,418			915			2,762			1,906
Provision for income taxes		1,025			617			1,952			1,153
Income from continuing operations		393			298			810			753
Discontinued operations		-			698			-			1,239
Net income	$	393		$	996		$	810		$	1,992
Per Share Data

Basic:
Income from continuing operations	$	0.56		$	0.42		$	1.15		$	1.06
Discontinued operations	$	-		$	0.98		$	-		$	1.74
Net income	$	0.56		$	1.40		$	1.15		$	2.80
Diluted:
Income from continuing operations	$	0.56		$	0.42		$	1.14		$	1.05
Discontinued operations	$	-		$	0.97		$	-		$	1.73
Net income	$	0.56		$	1.39		$	1.14		$	2.78
Dividends paid	$	0.17		$	0.25		$	0.34		$	0.50

Weighted average shares:
Basic		706			713			705			712
Diluted		709			717			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						Six Months Ended
	June 30,						June 30,
(In millions)	2012			2011			2012			2011
Net income	$	393		$	996		$	810		$	1,992
Other comprehensive income
Postretirement and postemployment plans
Change in actuarial loss		(3	)		64			10			97
Spin-off downstream business		-			968			-			968
Income tax benefit (provision) on postretirement and
postemployment plans		1			(403	)		(4	)		(415	)
Postretirement and postemployment plans, net of tax		(2	)		629			6			650
Derivative hedges
Net unrecognized gain		-			1			-			10
Spin-off downstream business		-			(7	)		-			(7	)
Income tax benefit (provision) on derivatives		-			3			-			(1	)
Derivative hedges, net of tax		-			(3	)		-			2
Foreign currency translation and other
Unrealized loss		(1	)		(1	)		-			(1	)
Income tax provision on foreign currency translation and other		-			-			-			-
Foreign currency translation and other, net of tax		(1	)		(1	)		-			(1	)
Other comprehensive income (loss)		(3	)		625			6			651
Comprehensive income	$	390		$	1,621		$	816		$	2,643

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	June 30,			December 31,
(In millions, except per share data)	2012			2011
Assets
Current assets:
Cash and cash equivalents	$	452		$	493
Receivables		2,047			1,917
Receivables from related parties		17			35
Inventories		335			361
Prepayments		101			96
Deferred tax assets		87			99
Other current assets		215			223
Total current assets		3,254			3,224
Equity method investments		1,319			1,383
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $17,777 and $17,248		26,001			25,324
Goodwill		525			536
Other noncurrent assets		1,151			904
Total assets	$	32,250		$	31,371
Liabilities
Current liabilities:
Commercial paper	$	550		$	-
Accounts payable		2,158			1,864
Payables to related parties		25			18
Payroll and benefits payable		120			193
Accrued taxes		1,440			2,015
Other current liabilities		211			163
Long-term debt due within one year		187			141
Total current liabilities		4,691			4,394
Long-term debt		4,513			4,674
Deferred income taxes		2,534			2,544
Defined benefit postretirement plan obligations		761			789
Asset retirement obligations		1,489			1,510
Deferred credits and other liabilities		477			301
Total liabilities		14,465			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 – 65 million and 66 million shares		(2,646	)		(2,716	)
Additional paid-in capital		6,667			6,680
Retained earnings		13,358			12,788
Accumulated other comprehensive loss		(364	)		(370	)
Total equity of Marathon Oil's stockholders		17,785			17,152
Noncontrolling interest		-			7
Total equity		17,785			17,159
Total liabilities and stockholders' equity	$	32,250		$	31,371

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended
	June 30,
(In millions)	2012			2011
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	810		$	1,992
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		75			(51	)
Depreciation, depletion and amortization		1,154			1,199
Impairments		263			307
Pension and other postretirement benefits, net		(22	)		22
Exploratory dry well costs and unproved property impairments		174			264
Net gain on disposal of assets		(138	)		(50	)
Equity method investments, net		7			(21	)
Changes in:
Current receivables		(107	)		78
Inventories		(18	)		46
Current accounts payable and accrued liabilities		(450	)		372
All other operating, net		(6	)		122
Net cash provided by continuing operations		1,742			3,320
Net cash provided by discontinued operations		-			1,090
Net cash provided by operating activities		1,742			4,410
Investing activities:
Additions to property, plant and equipment		(2,181	)		(1,702	)
Disposal of assets		218			371
Investments - return of capital		21			36
Investing activities of discontinued operations		-			(493	)
Property deposit		-			(100	)
All other investing, net		(59	)		15
Net cash used in investing activities		(2,001	)		(1,873	)
Financing activities:
Commercial paper, net		550			-
Debt issuance costs		(9	)		-
Debt repayments		(111	)		(2,843	)
Dividends paid		(240	)		(356	)
Financing activities of discontinued operations		-			2,916
Distribution in spin-off		-			(1,622	)
All other financing, net		20			126
Net cash provided by (used in) financing activities		210			(1,779	)
Effect of exchange rate changes on cash		8			2
Net increase (decrease) in cash and cash equivalents		(41	)		760
Cash and cash equivalents at beginning of period		493			3,951
Cash and cash equivalents at end of period	$	452		$	4,711

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 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 (“Marathon Oil”) 2011 Annual Report on Form 10-K. The results of operations for the second quarter and first six months 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 business was completed, creating two independent energy companies: Marathon Oil and Marathon Petroleum Corporation (“MPC”). On June 30, 2011, stockholders of record as of 5:00 p.m. Eastern Daylight Savings time on June 27, 2011 (the “Record Date”) received one common share of MPC stock for every two common shares of Marathon stock held as of the Record Date.

The following table presents selected financial information regarding the results of operations of our downstream business which are reported as discontinued operations. Transaction costs incurred to affect the spin-off of $57 million and $74 million for the second quarter and first six months of 2011 are included in discontinued operations.

	Three Months Ended,			Six Months Ended
	June 30,			June 30,
(In millions)	2011			2011
Revenues applicable to discontinued operations		$	20,760		$	38,602
Pretax income from discontinued operations			1,244			2,012

3. Accounting Standards

Recently Adopted

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

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

4. Variable Interest Entity

The owners of the Athabasca Oil Sands Project (“AOSP”), in which we hold a 20 percent undivided interest, contracted with a wholly-owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with a $3 million current liability recorded at June 30, 2012. Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline. Currently, no third-party shippers use the pipeline. Should shipments be suspended, by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all remaining periods. The contract expires in 2029; however, the shippers can extend its term perpetually. This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a Variable Interest Entity (“VIE”). We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore, the Corridor Pipeline is not consolidated by 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 $703 million as of June 30, 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 June 30,
	2012				2011
(In millions, except per share data)	Basic		Diluted		Basic		Diluted
Income from continuing operations	$	393	$	393	$	298	$	298
Discontinued operations		-		-		698		698
Net income	$	393	$	393	$	996	$	996

Weighted average common shares outstanding		706		706		713		713
Effect of dilutive securities		-		3		-		4
Weighted average common shares, including dilutive effect		706		709		713		717
Per share:
Income from continuing operations	$	0.56	$	0.56	$	0.42	$	0.42
Discontinued operations	$	-	$	-	$	0.98	$	0.97
Net income	$	0.56	$	0.56	$	1.40	$	1.39

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Six Months Ended June 30,
	2012				2011
(In millions, except per share data)	Basic		Diluted		Basic		Diluted
Income from continuing operations	$	810	$	810	$	753	$	753
Discontinued operations		-		-		1,239		1,239
Net income	$	810	$	810	$	1,992	$	1,992

Weighted average common shares outstanding		705		705		712		712
Effect of dilutive securities		-		4		-		4
Weighted average common shares, including dilutive effect		705		709		712		716
Per share:
Income from continuing operations	$	1.15	$	1.14	$	1.06	$	1.05
Discontinued operations	$	-	$	-	$	1.74	$	1.73
Net income	$	1.15	$	1.14	$	2.80	$	2.78

The per share calculations above exclude 10 million and 9 million stock options and stock appreciation rights for the second quarter and first six months of 2012, as they were antidilutive. Excluded for the second quarter and first six months of 2011 were 5 million and 6 million stock options and stock appreciation rights.

6. Acquisitions

In April 2012, we entered into agreements to acquire approximately 20,000 net acres in the core of the Eagle Ford shale. The smaller transactions closed during the second quarter of 2012. The largest transaction, with a value of $750 million before closing adjustments, closed on August 1, 2012.

7. Dispositions

2012

In May 2012, we reached an agreement to relinquish our Exploration and Production (“E&P”) segment’s operatorship of and interests in the Bone Bay and Kumawa exploration licenses in Indonesia. A $36 million payment will be made upon government ratification of the agreement, to settle all of our obligations related to these licenses, including well commitments. This amount was accrued and reported as a loss on disposal of assets in the second quarter of 2012.

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 gain of $7 million. The remaining transaction, with a value of $375 million before closing adjustments, is expected to close in the second half of 2012, pending regulatory approval and closing conditions. Assets held for sale are included in the June 30, 2012 balance sheet as follows:

(In millions)
Other current assets	$	60
Other noncurrent assets		187
Total assets		247
Deferred credits and other liabilities		87
Total liabilities	$	87

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

2011

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

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

8. 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

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

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

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

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

	Three Months Ended June 30, 2012
(In millions)	E&P		OSM		IG		Total
Revenues:
Customer	$	3,383	$	335	$	-	$	3,718
Related parties		13		-		-		13
Total revenues	$	3,396	$	335	$	-	$	3,731
Segment income	$	417	$	51	$	13	$	481
Income from equity method investments		38		-		22		60
Depreciation, depletion and amortization		521		50		-		571
Income tax provision		1,110		17		5		1,132
Capital expenditures		1,184		43		1		1,228

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Three Months Ended June 30, 2011
(In millions)	E&P			OSM		IG		Total
Revenues:
Customer	$	3,220		$	447	$	13	$	3,680
Intersegment		15			-		-		15
Related parties		14			-		-		14
Segment revenues		3,249			447		13		3,709
Elimination of intersegment revenues		(15	)		-		-		(15	)
Total revenues	$	3,234		$	447	$	13	$	3,694
Segment income	$	601		$	69	$	43	$	713
Income from equity method investments		66			-		54		120
Depreciation, depletion and amortization		501			49		1		551
Income tax provision		598			23		17		638
Capital expenditures		749			80		-		829

	Six Months Ended June 30, 2012
(In millions)	E&P		OSM		IG		Total
Revenues:
Customer	$	6,781	$	714	$	-	$	7,495
Related parties		27		-		-		27
Total revenues	$	6,808	$	714	$	-	$	7,522
Segment income	$	894	$	92	$	17	$	1,003
Income from equity method investments		102		-		36		138
Depreciation, depletion and amortization		1,037		99		-		1,136
Income tax provision		2,146		31		6		2,183
Capital expenditures		2,185		95		1		2,281

	Six Months Ended June 30, 2011
(In millions)	E&P			OSM		IG		Total
Revenues:
Customer	$	6,506		$	753	$	77	$	7,336
Intersegment		41			-		-		41
Related parties		29			-		-		29
Segment revenues		6,576			753		77		7,406
Elimination of intersegment revenues		(41	)		-		-		(41	)
Total revenues	$	6,535		$	753	$	77	$	7,365
Segment income	$	1,269		$	101	$	103	$	1,473
Income from equity method investments		124			-		113		237
Depreciation, depletion and amortization		1,087			86		3		1,176
Income tax provision		1,211			33		43		1,287
Capital expenditures		1,417			200		1		1,618

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						Six Months Ended
	June 30,						June 30,
(In millions)	2012			2011			2012			2011
Segment income	$	481		$	713		$	1,003		$	1,473
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(65	)		(24	)		(109	)		(153	)
Gain (loss) on dispositions (a)		(23	)		24			83			24
Impairments(b)		-			(195	)		(167	)		(195	)
Tax effect of subsidiary restructuring		-			(122	)		-			(122	)
Loss on early extinguishment of debt(c)		-			-			-			(176	)
Deferred income tax items		-			(50	)		-			(50	)
Water abatement - Oil Sands		-			(48	)		-			(48	)
Income from continuing operations		393			298			810			753
Discontinued operations		-			698			-			1,239
Net income	$	393		$	996		$	810		$	1,992

(a)	Additional information on these gains and losses can be found in Note 7.

(b)	Impairments are discussed in Note 13.

(c)	Additional information on debt retired early can be found in Note 15.

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2012			2011		2012			2011
Total revenues		$	3,731	$	3,694		$	7,522		$	7,365
Less: Sales to related parties			13		14			27			29
Sales and other operating revenues		$	3,718	$	3,680		$	7,495		$	7,336

9. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Three Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Service cost	$	13		$	10		$	1		$	1
Interest cost		16			16			3			4
Expected return on plan assets		(16	)		(16	)		-			-
Amortization:
– prior service cost (credit)		2			2			(1	)		(1	)
– actuarial loss		13			12			-			-
Net periodic benefit cost	$	28		$	24		$	3		$	4

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

	Six Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2012			2011			2012			2011
Service cost	$	25		$	23		$	2		$	2
Interest cost		32			33			7			8
Expected return on plan assets		(32	)		(33	)		-			-
Amortization:
– prior service cost (credit)		4			3			(3	)		(3	)
– actuarial loss		25			25			-			-
Net periodic benefit cost	$	54		$	51		$	6		$	7

During the first six months of 2012, we made contributions of $68 million to our funded pension plans. We expect to make additional contributions up to an estimated $50 million over the remainder of 2012. Current benefit payments related to unfunded pension and other postretirement benefit plans were $6 million and $8 million during the first six months of 2012.

10. Income Taxes

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

Our effective tax rate in the first six months of 2012 was 71 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 six 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 six months of 2012.

Our effective tax rate in the first six months of 2011 was 60 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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

The following table summarizes the activity in unrecognized tax benefits:

	Six Months Ended June 30,
(In millions)	2012			2011
Beginning balance	$	157		$	103
Additions based on tax positions related to the current year		2			2
Reductions based on tax positions related to the current year		-			(2	)
Additions for tax positions of prior years		69			53
Reductions for tax positions of prior years		(55	)		(8	)
Settlements		(7	)		(9	)
Ending balance	$	166		$	139

If the unrecognized tax benefits as of June 30, 2012 were recognized, $117 million would affect our effective income tax rate. There were $16 million of uncertain tax positions as of June 30, 2012 for which it is reasonably possible that the amount of unrecognized tax benefits would decrease during the next twelve months.

11. Inventories

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

	June 30,			December 31,
(In millions)	2012			2011
Liquid hydrocarbons, natural gas and bitumen		$	99		$	147
Supplies and sundry items			236			214
Total inventories, at cost		$	335		$	361

12. Property, Plant and Equipment

	June 30,			December 31,
(In millions)	2012			2011
E&P
United States	$	20,353		$	19,679
International		12,954			12,579
Total E&P		33,307			32,258
OSM		10,031			9,936
IG		38			37
Corporate		402			341
Total property, plant and equipment		43,778			42,572
Less accumulated depreciation, depletion and amortization		(17,777	)		(17,248	)
Net property, plant and equipment	$	26,001		$	25,324

In the first quarter of 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed. Since that time, average net sales volumes have increased to 44 thousand barrels per day (“mbbld”) in the second quarter of 2012 and 30 mbbld in the first six months of 2012. 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.

Exploratory well costs capitalized greater than one year after completion of drilling (“suspended”) were $254 million as of June 30, 2012. The net increase in such costs related to changes in two areas. Norway exploration costs of $55 million incurred between 2009 and 2011 have now been suspended for greater than one year, pending commencement of Boyla development which was submitted to the Norwegian government for approval June 2012. Drilling on the Shenandoah prospect in the Gulf of Mexico resumed in June 2012. Costs of $28 million related to Shenandoah are no longer suspended.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

13. Fair Value Measurements

Fair Values - Recurring

As of June 30, 2012 and December 31, 2011, balances related to interest rate swaps accounted for at fair value on a recurring basis were noncurrent assets of $16 million and $5 million. Foreign currency forwards accounted for at fair value on a recurring basis were current liabilities of $15 million at June 30, 2012. See Note 14 for the income statement impacts of our derivative instruments.

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

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

	Three Months Ended							Six Months Ended
	June 30,							June 30,
(In millions)	2012			2011				2012			2011
Beginning balance		$	-		$	(1	)		$	-		$	(2	)
Included in net income			-			1				-			-
Settlements			-			(2	)			-			-
Spin-off downstream business			-			2				-			2
Ending balance		$	-		$	-			$	-		$	-

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 June 30,
		2012				2011
(In millions)		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	-	$	1	$	226	$	282
Intangible assets	$	-	$	-	$	-	$	25

		Six Months Ended June 30,
		2012				2011
(In millions)		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	75	$	263	$	226	$	282
Intangible assets	$	-	$	-	$	-	$	25

Our E&P segment’s Ozona development in the Gulf of Mexico began production in December 2011. During the first quarter of 2012, production rates declined significantly and have remained below initial expectations. Accordingly, our reserve engineers performed an evaluation of our future production as well as our reserves which concluded in early April 2012. This resulted in a 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. Consequently, 3.4 million barrels of oil equivalent of proved reserves were written off and a $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.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

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

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

Natural gas prices began declining in September 2011 and have continued to decline in 2012. Should natural gas prices remain depressed, additional impairment charges related to our natural gas assets may be necessary.

Fair Values – Reported

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

The following table summarizes financial instruments, excluding trade accounts receivables and payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at June 30, 2012 and December 31, 2011:

	June 30, 2012				December 31, 2011
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other current assets	$	131	$	136	$	146	$	148
Other noncurrent assets		198		198		68		68
Total financial assets		329		334		214		216
Financial liabilities
Long-term debt, including current portion(a)		5,447		4,643		5,479		4,753
Deferred credits and other liabilities		122		121		36		38
Total financial liabilities	$	5,569	$	4,764	$	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 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 of our long-term debt instruments are publicly-traded. A market approach based upon quotes from major financial institutions is used to measure the fair value of such debt. Because these quotes cannot be independently verified to an active market they are considered Level 3 inputs. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

14. Derivatives

As of June 30, 2012, our outstanding derivative positions were fair value hedges. Interest rate swaps with an asset value of $16 million are reported in Other noncurrent assets and foreign currency forwards with a liability value of $15 million are located in Other current liabilities on the consolidated balance sheet.

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

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

Derivatives Designated as Fair Value Hedges

As of June 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 4.72 percent.

As of June 30, 2012, our foreign currency forwards had an aggregate notional amount of 3,310 million Norwegian Kroner at a weighted average forward rate of 5.825. These forwards hedge our current Norwegian tax liability and have settlement dates through December 2012.

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.

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

		Gain (Loss)
		Three Months Ended						Six Months Ended
		June 30,						June 30,
(In millions)	Income Statement Location	2012			2011			2012			2011
Derivative
Interest rate	Net interest and other	$	12		$	3		$	12		$	(1	)
Interest rate	Loss on early extinguishment of debt		-			-			-			29
Foreign currency	Provision for income taxes	$	(32	)	$	-		$	(40	)	$	-
Hedged Item
Long-term debt	Net interest and other	$	(12	)	$	(3	)	$	(12	)	$	1
Long-term debt	Loss on early extinguishment of debt		-			-			-			(29	)
Accrued taxes	Provision for income taxes	$	32		$	-		$	40		$	-

15. Debt

At June 30, 2012, we had no borrowings against our revolving credit facility, described below, and $550 million in commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

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

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

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

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

16. Incentive Based Compensation Plans

Stock Option and Restricted Stock Awards

The following table presents a summary of stock option award and restricted stock award activity for the first six months of 2012:

	Stock Options					Restricted Stock
				Weighted					Weighted
	Number of			Average					Average Grant
	Shares			Exercise Price		Awards			Date Fair Value
Outstanding at December 31, 2011		21,370,715		$	24.41		3,703,978		$	25.88
Granted		1,462,779	(a)		35.06		1,219,174			34.59
Options Exercised/Stock Vested		(906,193	)		18.73		(310,575	)		20.94
Cancelled		(293,478	)		27.77		(161,439	)		27.41
Outstanding at June 30, 2012		21,633,823		$	25.33		4,451,138		$	28.55

(a) The weighted average grant date fair value of stock option awards granted was $11.62 per share.

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

	Six Months Ended June 30,
(In millions)	2012			2011
Net cash provided from operating activities:
Interest paid (net of amounts capitalized)	$	113		$	83
Income taxes paid to taxing authorities		2,317			1,351
Commercial paper and revolving credit arrangements, net:
Commercial paper - issuances	$	4,252		$	-
- repayments		(3,702	)		-
Total	$	550		$	-
Noncash investing activities:
Debt payments made by United States Steel	$	14		$	14
Change in capital expenditure accrual		159			(54	)

18. 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 for 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.

Contractual commitments – At June 30, 2012 and December 31, 2011, Marathon’s contract commitments to acquire property, plant and equipment were $1,021 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:

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

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 our 2011 Annual Report on Form 10-K.

Key Operating and Financial Activities

In the second quarter of 2012, notable items were:

·	Net liquid hydrocarbon and natural gas sales volumes of 407 thousand barrels of oil equivalent per day (“mboed”), of which 66 percent was liquid hydrocarbons

·	Net international liquid hydrocarbon sales volumes, for which average realizations have exceeded West Texas Intermediate (“WTI”) crude oil, were 66 percent of total liquid hydrocarbon sales

·	Production from Libya increased over the first quarter of 2012, with average net sales of 44 mboed and production available for sale of 44 mboed in the second quarter

·	Bakken shale average net sales volumes of 27 mboed, a 69 percent increase over the same quarter of last year

·	Eagle Ford shale average net sales volumes of 21 mboed, an increase nearly 50 percent from the first quarter of 2012

·	Turnarounds at our operated assets in Equatorial Guinea and Norway were completed in less time and at lower cost than originally anticipated

·	Signed a new production sharing contract for an exploration block adjacent to the Alba field offshore Equatorial Guinea

·	Cash-adjusted debt-to-capital ratio of 21 percent

·	Replaced existing revolving credit facility with a new $2.5 billion facility expiring April 2017

Some significant third quarter activities through August 3, 2012 include:

·	Re-entered Gabon with a non-operated 21 percent working interest in an exploration license

·	Agreed to pursue exploration activities in Kenya and Ethiopia

·	Closed farm out agreements on 35 percent working interests in the Harir and Safen blocks in the Kurdistan Region of Iraq

·	Closed the largest previously announced acquisition in the Eagle Ford shale

Overview and Outlook

Exploration and Production

Production

Net liquid hydrocarbon and natural gas sales averaged 407 mboed during the second quarter and 395 mboed in the first six months of 2012 compared to 337 mboed and 368 mboed in the same periods of 2011. 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 cause of our increased sales volumes. Net liquid hydrocarbon sales volumes increased in the U.S. for both the quarter and first six months of 2012, reflecting the impact of the Eagle Ford shale assets acquired in the fourth quarter of 2011 and our ongoing development programs in the Eagle Ford, Bakken and Anadarko Woodford unconventional resource plays. In addition, net liquid hydrocarbon sales volumes from the U.K. were higher in the second quarter of 2012 than in the same period of 2011 due to the timing of liftings.

We continue to ramp up operations in the core of the Eagle Ford play in Texas where we had 20 operated rigs drilling and four hydraulic fracturing crews working as of June 30, 2012. During the second quarter and first six months of 2012, we drilled 61 gross and 107 gross wells, with a total of 72 gross (50 net) wells brought to sales in the first six months of 2012. We have realized significant efficiencies in drilling over the past few months, reducing the average drilling time per well to 23 days. With these gains in efficiencies, we believe we can reduce our operated rig count to 18 for the balance of 2012 and drill the 230 to 240 wells originally planned for 2012, along with 11 incremental wells associated with the acreage acquired on August 1, 2012.

To complement drilling and completion activity in the Eagle Ford shale, we continue to build infrastructure to support production growth across the operating area. Approximately 210 miles of gathering lines were installed in the first six months of 2012, while four new central gathering and treating facilities were commissioned. Five additional facilities are under construction. We are now able to transport approximately 70 percent of our Eagle Ford production by pipeline.

Average net sales volumes from the Bakken shale were 27 mboed and 26 mboed in the second quarter and first six months of 2012 compared to 16 mboed and 15 mboed in the same periods of 2011. Our Bakken shale liquid hydrocarbon volumes average approximately 95 percent liquid hydrocarbons. During the second quarter and first six months of 2012, we drilled 26 gross and 47 gross wells, with a total of 44 gross (37 net) wells brought to sales in the first six months of 2012. We are reducing our operated rig count in the Bakken shale from eight to five in response to continued commodity price volatility and lower domestic liquid hydrocarbon prices. With this five-rig program, we expect to maintain our previously projected production levels over the next 12 to 18 months and to retain our core Bakken acreage.

In the Anadarko Woodford shale, net sales volumes averaged 6 mboed and 5 mboed during the second quarter and first six months of 2012 compared to 2 mboed and 1 mboed in the same periods of 2011. Recent performance improvements are being driven by results in the Knox area. During the second quarter of 2012, eight gross (five net) wells were brought to sales, with 17 gross (13 net) brought to sales in the first six months of 2012. In response to the continued decline in natural gas liquids prices and low natural gas prices, we are reducing our rig count in the Anadarko Woodford play from six to two. We expect to maintain our projected 2012 production level and retain our core acreage in the play with this two-rig program over the next 12 to 18 months.

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 2 mmboe reduction in proved reserves and a $261 million impairment charge in the first quarter of 2012.

In the first quarter 2011, production operations in Libya were suspended. In the fourth quarter of 2011, limited production resumed so that during the second quarter and first six months of 2012, net sales volumes averaged 44 mboed and 31 mboed. Some uncertainty concerning the sustainability of production and sales levels in Libya remains. We and our partners in the Waha concessions continue to assess the condition of our assets.

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. The Boyla field is located approximately 17 miles south of our operated Alvheim field. We hold a 65 percent working interest in the field. Pending approval, first production from Boyla is expected in the fourth quarter of 2014. Also during the second quarter of 2012, we completed a four-day turnaround in Norway that was originally scheduled for 14 days in the third quarter. We expect an additional one to two day planned shutdown of our Norway assets in the third quarter of 2012.

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

Exploration

At June 30, 2012, we were participating in two non-operated wells in the Gulf of Mexico: an appraisal well on the Gunflint discovery located on Mississippi Canyon Block 948 and an appraisal well on the Shenandoah prospect located on Walker Ridge Block 51. We have a 15 percent and a 10 percent working interest in these prospects. The Gunflint well has confirmed expected reservoir properties and continuity, establishing the commercial viability of the field. Drilling of the Shenandoah appraisal well commenced on June 29, 2012. During the second quarter of 2012, the well costs and related unproved property costs related to the Kilchurn well were charged to exploration expenses.

In the second half of 2012, we expect to return to drilling the exploration well on the Gulf of Mexico Innsbruck prospect on Mississippi Canyon Block 993 in which we hold a 45 percent working interest. Drilling of this well was halted in 2010 due to the U.S. government imposed drilling moratorium that followed the large Gulf of Mexico spill.

We continue exploratory drilling in Poland. Our third exploratory well has completed and a fourth well, is currently drilling. We have collected extensive data, including well logs and core samples, which are being evaluated. We plan to drill six wells by the end of 2012 in Poland. We hold a 51 percent working interest in 10 operated concessions and a 100 percent working interest in one concession.

In the Kurdistan Region of Iraq, we began drilling our first operated exploration well on the Harir block on July 30, 2012 and plan to drill an exploration well on the Safen block in 2013. We have a 45 percent working (56 percent paying) interest in both the Harir and Safen blocks. Additionally, we are participating in non operated appraisal well on the Sarsang block, where we hold a 20 percent working (25 percent paying) interest.

During the first quarter of 2012, on the Birchwood oil sands lease located in Alberta, Canada, we conducted a seismic survey and drilled six water wells. We also submitted a regulatory application for a proposed 12 thousand barrel per day (“mbbld”) steam assisted gravity drainage (“SAGD”) project at Birchwood. Pending regulatory approval, project sanction is expected in 2014, with first oil projected in 2017. We have a 100 percent working interest in Birchwood.

Acquisitions and Divestitures

On January 3, 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million. This includes our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system. A pretax gain of $166 million was recorded in the first quarter of 2012.

In April 2012, we entered multiple agreements to acquire approximately 20,000 net acres in the core of the Eagle Ford shale formation in transactions valued at $767 million, before closing adjustments. The smaller transactions closed during the second quarter of 2012. The largest transaction with a value of $750 million before closing adjustments closed on August 1, 2012. In addition to undeveloped acreage, 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.

In April 2012, we entered agreements to sell our Alaska assets. One transaction closed in the second quarter of 2012 with proceeds and a net gain of $7 million. The remaining transaction, with a value of $375 million before closing adjustments, is expected to close in the second half of 2012, pending regulatory approval and closing conditions.

In May 2012, we reached an agreement to relinquish operatorship of and our interests in the Bone Bay and Kumawa exploration licenses in Indonesia. A $36 million payment will be made upon government ratification of the agreement, to settle all of our obligations related to these licenses, including well commitments. This amount was accrued and reported as a loss on disposal of assets in the second quarter of 2012.

In June 2012, we entered an agreement to acquire a 21 percent working (25 percent paying) interest in the Diaba License G4-223 and its related permit in Gabon. The transaction is expected to close, subject to completion of the necessary Gabonese government and partner approvals, in the third quarter of 2012. The start of exploration drilling is expected in the first quarter of 2013.

During June 2012, we signed a new production sharing contract with the government of Equatorial Guinea for the exploration of Block A-12 offshore Bioko Island, located immediately west of our operated Alba Field. We have an 80 percent operated working interest in this block. Ratification of the contract by the government is expected in the third quarter of 2012.

In late July, we entered into an agreement to acquire positions in two onshore exploration blocks in northwest Kenya amounting to more than 11 million gross acres. The transaction includes a 50 percent working interest in Block 9 and a 15 percent working interest in Block 12A. An exploration well is planned on Block 9 in mid-2013. The transaction, subject to government approval, is expected to close in the third quarter of 2012. Additionally, we are pursuing exploration activities in Ethiopia, subject to host country government approval.

Also in late July, we closed on agreements to farm out 35 percent working (44 percent paying) interests in the Harir and Safen blocks in the Kurdistan Region of Iraq. After this transaction, we have a 45 percent working (56 percent paying) interest in each of the two blocks.

The above discussions include forward-looking statements with respect to the expected production in the Eagle Ford, Anadarko Woodford and Bakken plays, timing of first production from the Boyla field, anticipated drilling rig and drilling activity, the sale of the our Alaska assets, the expected closing of agreements in Gabon and Kenya, possible exploration activity in Ethiopia, a new production sharing contract with the Government of Equatorial Guinea, a scheduled shutdown of the Norway assets and the timing of the commencement of construction and first oil on the SAGD project. Factors that could potentially affect the expected production in the Eagle Ford, Anadarko Woodford and Bakken plays, timing of first production from the Boyla field, and anticipated drilling rig and drilling activity include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other geological, operating and economic considerations. The completion of the sale of our Alaska assets is subject to necessary government and regulatory approvals and customary closing conditions. The agreement in Gabon is subject to government and partner approvals. The agreement in Kenya and the exploration activity in Ethiopia are subject to government approvals. The new production sharing contract with the Government of Equatorial Guinea is subject to ratification by the Equatorial Guinea government. The scheduled shutdown of the Norway assets is based on current expectations, estimates and projections and is not a guarantee of future performance. The timing of commencement of construction and first oil on the SAGD project can be affected by delays in obtaining and conditions imposed by necessary government and third-party approvals, board approval, transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, 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”). Our net synthetic crude oil sales were 44 mbbld in the second quarter and first six months of 2012 compared to 41 mbbld and 39 mbbld in the same periods of 2011. The upgrader expansion was completed and commenced operations in the second 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.

In July 2012, Alberta’s primary energy regulator, the Energy and Resources Conservation Board (“ERCB”), conditionally approved the AOSP’s Quest Carbon Capture and Storage (“Quest”) project. The ERCB’s approval positions the AOSP partners to make an investment decision on Quest in 2012.

The above discussion contains forward looking statements with regard to the Quest project. The project is subject to regulatory approvals, stakeholder engagement, detailed engineering studies and a final joint venture partner agreement.

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 5,467 metric tonnes per day (“mtd”) for the second quarter and 5,879 mtd for the first six months of 2012 compared to 6,614 mtd and 7,215 mtd in the same periods of 2011. LNG sales volumes are below the prior year primarily because the second quarter and first six 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. Also, the planned turnaround which began at the LNG facility in Equatorial Guinea in the first quarter of 2012 was completed in the second quarter four days ahead of schedule and 15 percent under budget.

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 benchmark crude oil and natural gas price averages in the second quarter and first six months of 2012 compared to the same periods in 2011.

		Three Months Ended June 30,				Six Months Ended June 30,
Benchmark		2012		2011		2012		2011
WTI crude oil (Dollars per barrel)		$	93.35	$	102.34	$	98.15	$	98.50
Brent (Europe) crude oil	(Dollars per barrel)	$	108.42	$	117.36	$	113.45	$	111.16
Henry Hub natural gas (Dollars per million British thermal units ("mmbtu"))(a)		$	2.22	$	4.31	$	2.48	$	4.21

(a)	Settlement date average.

Average WTI crude oil benchmark prices decreased in the second quarter of 2012 compared to the same quarter of 2011, but were relatively flat for the first six months of each year. The average differential between the Brent and WTI benchmarks was a premium of approximately $15 per barrel in both periods of 2012. Our international crude oil production is relatively sweet and a majority is sold in relation to the Brent crude oil benchmark.

Our domestic crude oil production was about 42 percent sour in the second quarter and 45 percent sour in the first six months of 2012 compared to 68 percent and 69 percent in the same periods of 2011. Reduced production from the Gulf of Mexico and increased onshore production from the Bakken and Eagle Ford shales 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.

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 second quarter and first six 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 the second quarter of 2012. Should U.S. natural gas prices remain depressed, impairment charges related to our natural gas assets may be necessary.

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

Oil Sands Mining

OSM 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 (“WCS”). Recently, 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 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, making per unit costs 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 second quarter and first six months of 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
Benchmark	2012		2011		2012		2011
WTI crude oil (Dollars per barrel)	$	93.35	$	102.34	$	98.15	$	98.50
Western Canadian Select (Dollars per barrel)(a)	$	70.63	$	84.92	$	76.07	$	78.08
AECO natural gas sales index (Dollars per mmbtu)(b)	$	1.84	$	4.04	$	2.04	$	3.94

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

(b)	Monthly average AECO day ahead index.

Integrated Gas

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

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

Results of Operations

Consolidated Results of Operation

Due to the spin-off of our downstream business on June 30, 2011, which is reported as discontinued operations, income from continuing operations is more representative of Marathon Oil as an independent energy company. Consolidated income from continuing operations before income taxes in the second quarter of 2012 was 55 percent higher than in the same period of 2011 primarily due to the previously discussed resumption of our operations in Libya and no impairments in the second quarter of 2012. The effective tax rate was 72 percent in the second quarter of 2012 compared to 67 percent in the second quarter of 2011, with the increase related to higher income from continuing operations in higher tax jurisdictions, primarily Norway and Libya.

Consolidated income from continuing operations before income taxes in the first six months of 2012 was 45 percent higher than in the same period of 2011 primarily due to increased income in Libya and lower exploration expenses, depreciation, depletion and amortization (“DD&A”) and impairments. As a result of increased income from continuing operations before tax in higher tax jurisdictions, primarily Norway and Libya, the effective tax rate was 71 percent for the first six months of 2012 compared to 60 percent for the same period of 2011.

Revenues are summarized by segment in the following table:

	Three Months Ended June 30,					Six Months Ended June 30,
(In millions)	2012		2011			2012		2011
E&P	$	3,396	$	3,249		$	6,808	$	6,576
OSM		335		447			714		753
IG		-		13			-		77
Segment revenues		3,731		3,709			7,522		7,406
Elimination of intersegment revenues		-		(15	)		-		(41	)
Total revenues	$	3,731	$	3,694		$	7,522	$	7,365

E&P segment revenues increased $147 million in the second quarter and $232 million in the first six months of 2012 from the comparable prior-year periods. Included in our E&P segment are supply optimization activities which include the purchase of commodities from third parties for resale. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points. See the Cost of revenues discussion as revenues from supply optimization approximate the related costs. Lower average commodity prices in the second quarter and first six months of 2012 decreased revenues related to supply optimization.

Revenues from the sale of our U.S. production are higher in the second quarter and first six months of 2012 primarily as a result of increased liquid hydrocarbon sales volumes from our U.S. shale plays. Lower liquid hydrocarbon and natural gas price realizations partially offset the volume impact. The following table gives details of net sales and average realizations of our U.S. operations.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
United States Operating Statistics
Net liquid hydrocarbon sales (mbbld) (a)		93		72		91		75
Liquid hydrocarbon average realizations (per bbl) (b)	$	84.40	$	99.51	$	88.94	$	92.76

Net natural gas sales (mmcfd)		319		315		331		341
Natural gas average realizations (per mcf)(b)	$	3.42	$	5.08	$	3.79	$	5.12

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

(b)	Excludes gains and losses on derivative instruments.

Revenues from our international operations are higher in the second quarter and first six months of 2012 primarily as a result of the, previously discussed, resumption of liquid hydrocarbon sales from Libya. Higher average liquid hydrocarbon realizations during the first six months of 2012 also contributed to the revenue increase for that period. The following table gives details of net sales and average realizations of our international operations.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
International Operating Statistics
Net liquid hydrocarbon sales (mbbld)(a)
Europe		99		87		98		99
Africa		78		39		65		49
Total International		177		126		163		148
Liquid hydrocarbon average realizations (per bbl)(b)
Europe	$	111.12	$	122.13	$	117.37	$	115.27
Africa		96.84		76.86		95.87		79.60
Total International	$	104.82	$	108.05	$	108.80	$	103.51

Net natural gas sales (mmcfd)
Europe(c)		102		96		103		99
Africa		399		420		409		433
Total International		501		516		512		532
Natural gas average realizations (per mcf)(b)
Europe	$	10.05	$	10.05	$	10.02	$	10.18
Africa		0.25		0.25		0.25		0.25
Total International	$	2.25	$	2.06	$	2.22	$	2.09

(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 17 mmcfd and 13 mmcfd for the second quarters of 2012 and 2011, and 15 mmcfd and 14 mmcfd for the first six months of 2012 and 2011.

OSM segment revenues decreased $112 million in the second quarter and $39 million in the first six months of 2012 compared to the same periods of 2011. Net sales volumes improved in both periods of 2012 compared to the prior year because the upgrader expansion was completed and commenced operations in the second quarter of 2011. However, lower WTI prices and an increase in the discount of WCS to WTI resulted in the 21 percent and 9 percent decreases in average realizations during the second quarter and first six months of 2012. The following table gives details of net sales and average realizations of our OSM operations.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
OSM Operating Statistics
Net synthetic crude oil sales (mbbld) (a)		44		41		44		39
Synthetic crude oil average realizations (per bbl)	$	79.31	$	100.68	$	85.07	$	93.26

(a)	Includes blendstocks.

IG segment revenues decreased $13 million in the second quarter and $77 million in the first six months of 2012 compared to the same periods of 2011. Sales of LNG from our Alaska operations ceased in the third quarter of 2011 when we sold our interest in this production facility.

Income from equity method investments decreased $60 million in the second quarter of 2012 and $99 million in the first six months of 2012 from the comparable prior-year periods. Lower commodity prices negatively impacted the earnings of our equity method investees.

Net gain (loss) on disposal of assets in the second quarter of 2012 primarily reflects $36 million to settle all of our obligations, including well commitments, as a result of the assignment of our Bone Bay and Kumawa exploration licenses in Indonesia. The net gain on disposal of assets in the first six months of 2012 was primarily the $166 million gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems, reduced by the second quarter Indonesia loss. See Note 7 to the consolidated financial statements for information about these dispositions.

Cost of revenues decreased $365 million and $362 million in the second quarter and first six months of 2012 from the comparable periods of 2011 primarily due to the impact of lower commodity prices on our supply optimization activities. Comparatively, costs related to supply optimization were lower by $276 million for the second quarter and by $239 million for the first six months of 2012. OSM segment costs decreased in both periods of 2012 because the second quarter of 2011 included a $64 million accrual for estimated net costs to address water flow in a previously mined and contained area of the Muskeg River mine 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 of 2011.

Depreciation, depletion and amortization increased $16 million in the second quarter and decreased $45 million in the first six months of 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. The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in reserves and capitalized costs, can also cause changes in our DD&A. Lower U.S. DD&A rates in the second quarter and first six months of 2012 compared to the same periods in 2011 offset the impact of higher sales volumes in those periods. Also, there was no depletion of our Alaska assets in the second quarter 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 June 30,				Six Months Ended June 30,
($ per boe)	2012		2011		2012		2011
DD&A rate
E&P Segment
United States	$	22	$	26	$	23	$	27
International	$	10	$	10	$	9	$	10
OSM Segment	$	6	$	6	$	6	$	6

Impairments in the first six months of 2012 related primarily to the Ozona development in the Gulf of Mexico. Impairments in the first six months of 2011 related primarily to the Droshky development in the Gulf of Mexico and an intangible asset for an LNG delivery contract at Elba Island. See Note 13 to the consolidated financial statements for information about these impairments.

General and administrative expenses were flat in the second quarter and decreased $17 million in the first six months of 2012 compared to the same periods in 2011. The first six months of 2011 included higher incentive compensation expense due to the increase in Marathon’s stock price in the period leading up to the spin-off.

Exploration expenses were higher in the second quarter of 2012 than in the same quarter of 2011, primarily due to higher dry well costs and unproved property impairments. Dry well costs in the second quarter of 2012 included one dry well in the Gulf of Mexico and a few domestic onshore dry wells, while the second quarter of 2011 included dry well costs in Norway and Indonesia. Exploration expenses were lower in the first six months of 2012 than in the previous year, primarily due to dry well costs in the Gulf of Mexico and Indonesia in the first quarter of 2011; however, higher unproved property impairments in the Marcellus shale and Indonesia in 2012 partially offset this decrease. Geological and geophysical (“G&G”) costs increased in both periods of 2012 primarily related to the Eagle Ford shale play, 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 June 30,				Six Months Ended June 30,
(In millions)	2012		2011		2012		2011
Dry well costs and unproved property impairments	$	116	$	91	$	174	$	264
G&G		27		13		70		29
Other		30		41		71		82
Total exploration expenses	$	173	$	145	$	315	$	375

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

Net interest and other increased $44 million and $75 million in the second quarter and first six months of 2012 from the comparable periods of 2011 primarily due to lower capitalized interest in both periods.

Provision for income taxes increased $408 million and $799 million in the second quarter and first six months of 2012 from the comparable periods of 2011 primarily due to the increase in pretax income in high tax rate jurisdictions, including the impact of the previously discussed resumption of sales in Libya in the first quarter of 2012.

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

Segment Results

Segment income is summarized in the following table.

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2012			2011			2012			2011
E&P
United States	$	70		$	126		$	179		$	157
International		347			475			715			1,112
E&P segment		417			601			894			1,269
OSM		51			69			92			101
IG		13			43			17			103
Segment income		481			713			1,003			1,473
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(65	)		(24	)		(109	)		(153	)
Gain (loss) on dispositions		(23	)		24			83			24
Impairments		-			(195	)		(167	)		(195	)
Tax effect of subsidiary restructuring		-			(122	)		-			(122	)
Loss on early extinguishment of debt		-			-			-			(176	)
Deferred income tax items		-			(50	)		-			(50	)
Water abatement - Oil Sands		-			(48	)		-			(48	)
Income from continuing operations		393			298			810			753
Discontinued operations		-			698			-			1,239
Net income	$	393		$	996		$	810		$	1,992

United States E&P income decreased $56 million in the second quarter and increased $22 million in the first six months of 2012 compared to the same periods of 2011. The income decrease in the second quarter of 2012 was primarily the result of lower liquid hydrocarbon price realizations and increased exploration expenses, partially offset by higher liquid hydrocarbon sales volumes. For the six-month period, the increase in liquid hydrocarbon sales volumes and decreased DD&A were partially offset by lower liquid hydrocarbon realizations and increased exploration expenses.

International E&P income decreased $128 million in the second quarter and $397 million in the first six months of 2012 compared to the same periods of 2011. As previously discussed, increased income before tax in higher tax jurisdictions resulted in a higher effective tax rate in the second quarter and first six months of 2012 compared to the same periods of 2011. Segment income, before taxes, increased in both periods primarily due to the previously discussed higher liquid hydrocarbon sales volumes and lower exploration expenses in both periods. Higher liquid hydrocarbon realizations also had a favorable impact on income for the first six months of 2012.

OSM segment income decreased $18 million and $9 million in the second quarter and first six months of 2012. As previously discussed, lower synthetic crude oil price realizations were the primary reason for the decrease in income. This was partially offset by decreased costs and higher sales volumes.

IG segment income decreased $30 million and $86 million in the second quarter of 2012 and first six months of 2012 compared to the same periods of 2011 primarily as a result of weaker natural gas prices in 2012 and lower LNG sales volumes due to the sale of our interest in the Alaska LNG facility in the third quarter of 2011.

Cash Flows and Liquidity

Cash Flows

Net cash provided by continuing operations was $1,742 million in the first six months of 2012, compared to $3,320 million in the first six months of 2011 primarily reflecting the impact of lower liquid hydrocarbon and natural gas prices on operating 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 $2,001 million in the first six months of 2012, compared to $1,380 million related to continuing operations in the first six months of 2011. Significant investing activities are additions to property, plant and equipment and disposal of assets. In the first six months of 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 six 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. Deposits totaling $100 million were paid in the first six months of 2011 related to the Eagle Ford shale acreage acquisitions that closed later that year.

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

Net cash provided by financing activities was $210 million in the first six months of 2012, compared to net cash used in financing activities related to continuing operations of $4,695 million in the first six months of 2011. During the first six months of 2012, we drew a net $550 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 six months of 2011, we retired $2.5 billion aggregate principal amount of our debt before it was due and distributed $1.6 billion to Marathon Petroleum Corporation in connection with the spin-off of the downstream business. Dividends paid were a significant use of cash in both periods.

Liquidity and Capital Resources

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, the issuance of notes, our committed revolving credit facility, and sales of non-strategic assets. Our working capital requirements are supported by these sources and we may issue commercial paper backed by our $2.5 billion revolving credit facility to meet short-term cash requirements. We issued $4.3 billion and repaid $3.7 billion of commercial paper in the first six months of 2012 leaving a balance of $550 million outstanding at June 30, 2012. After June 30, 2012, we continued to utilize our sources of liquidity, including additional issuances of commercial paper, to fund the Eagle Ford acquisition that closed on August 1, 2012 and working capital requirements. Because of the alternatives available to us as discussed above and access to capital markets, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, defined benefit plan contributions, repayment of debt maturities, and other amounts that may ultimately be paid in connection with contingencies.

Capital Resources

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 21 percent at June 30, 2012, compared to 20 percent at December 31, 2011.

	June 30,			December 31,
(In millions)	2012			2011
Commercial paper	$	550		$	-
Long-term debt due within one year		187			141
Long-term debt		4,513			4,674
Total debt		5,250			4,815
Cash		452			493
Equity	$	17,785		$	17,159
Calculation:
Total debt	$	5,250		$	4,815
Minus cash		452			493
Total debt minus cash		4,798			4,322
Total debt		5,250			4,815
Plus equity		17,785			17,159
Minus cash		452			493
Total debt plus equity minus cash	$	22,583		$	21,481
Cash-adjusted debt-to-capital ratio		21	%		20	%

Capital Requirements

On July 25, 2012, our Board of Directors approved a dividend of 17 cents per share for the second quarter of 2012, payable September 10, 2012 to stockholders of record at the close of business on August 16, 2012.

As discussed in Note 6 to the consolidated financial statements, the transaction valued at $750 million to acquire additional Eagle Ford shale assets was closed on August 1, 2012.

In the first quarter of 2012, we increased our 2012 capital, investment and exploration budget, excluding acquisition costs, from $4.8 billion to $5.0 billion, of which $4.6 billion will be used for capital expenditures. The increase reflects development plans for the additional acreage being acquired in the Eagle Ford shale and other adjustments.

As of June 30, 2012 we expected to make additional contributions to our funded pension plans up to an estimated $50 million over the remainder of 2012. We made a contribution of $14 million in July 2012.

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 above discussions also contain forward-looking statements about our 2012 capital, investment and exploration budget and expected contributions to our funded pension plans. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially are changes in prices of and demand for 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 June 30, 2012.

						2013-		2015-	Later
(In millions)	Total		2012			2014		2016	Years
Short and long-term debt (excludes interest)	$	5,202	$	584	$	249	$	68	$	4,301
Lease obligations		272		45		74		54		99
Purchase obligations:
Oil and gas activities(a)		1,053		550		381		43		79
Service and materials contracts(b)		992		84		229		152		527
Transportation and related contracts		1,258		162		255		158		683
Drilling rigs and fracturing crews		1,272		397		851		24		-
Other		215		41		90		27		57
Total purchase obligations		4,790		1,234		1,806		404		1,346
Other long-term liabilities reported
in the consolidated balance sheet(c)		1,163		95		272		253		543
Total contractual cash obligations(d)	$	11,427	$	1,958	$	2,401	$	779	$	6,289

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

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

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

(d)	This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1,489 million.

Critical Accounting Estimates

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

Environmental Matters

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

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

Other Contingencies

Litigation – In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling 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.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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.

Sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of June 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		$	16	(b)		$	5
Long-term debt, including amounts due within one year		$	(5,447	)(b)		$	(220	)

(a)

Fair values of cash and cash equivalents, receivables, notes payable, 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 June 30, 2012 would be $55 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. During the quarter ended June 30, 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						Six Months Ended
	June 30,						June 30,
(In millions)	2012			2011			2012			2011
Segment Income
Exploration and Production
United States	$	70		$	126		$	179		$	157
International		347			475			715			1,112
E&P segment		417			601			894			1,269
Oil Sands Mining		51			69			92			101
Integrated Gas		13			43			17			103
Segment income		481			713			1,003			1,473
Items not allocated to segments, net of income taxes		(88	)		(415	)		(193	)		(720	)
Income from continuing operations		393			298			810			753
Discontinued operations(a)		-			698			-			1,239
Net income	$	393		$	996		$	810		$	1,992
Capital Expenditures(b)
Exploration and Production
United States	$	983		$	556		$	1,845		$	905
International		201			193			340			512
E&P segment		1,184			749			2,185			1,417
Oil Sands Mining		43			80			95			200
Integrated Gas		1			-			1			1
Corporate		17			24			59			30
Total	$	1,245		$	853		$	2,340		$	1,648
Exploration Expenses
United States	$	144		$	54		$	237		$	204
International		29			91			78			171
Total	$	173		$	145		$	315		$	375

(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				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbbld)
United States		93		72		91		75

Europe		99		87		98		99
Africa		78		39		65		49
Total International		177		126		163		148
Worldwide		270		198		254		223
Net Natural Gas Sales (mmcfd)
United States		319		315		331		341

Europe(c)		102		96		103		99
Africa		399		420		409		433
Total International		501		516		512		532
Worldwide		820		831		843		873
Total Worldwide Sales (mboed)		407		337		395		368
Average Realizations (d)
Liquid Hydrocarbons (per bbl)
United States	$	84.40	$	99.51	$	88.94	$	92.76

Europe		111.12		122.13		117.37		115.27
Africa		96.84		76.86		95.87		79.60
Total International		104.82		108.05		108.80		103.51
Worldwide	$	97.81	$	104.93	$	101.68	$	99.89

Natural Gas (per mcf)
United States	$	3.42	$	5.08	$	3.79	$	5.12

Europe		10.05		10.05		10.02		10.18
Africa(e)		0.25		0.25		0.25		0.25
Total International		2.25		2.06		2.22		2.09
Worldwide	$	2.70	$	3.21	$	2.84	$	3.28
OSM Operating Statistics
Net Synthetic Crude Oil Sales (mbbld) (f)		44		41		44		39
Synthetic Crude Oil Average Realizations (per bbl)(d)	$	79.31	$	100.68	$	85.07	$	93.26
IG Operating Statistics
Net Sales (mtd) (g)
LNG		5,467		6,614		5,879		7,215
Methanol		1,268		1,243		1,290		1,281

c)	Includes natural gas acquired for injection and subsequent resale of 17 mmcfd and 13 mmcfd for the second quarters of 2012 and 2011, and 15 mmcfd and 14 mmcfd for the first six months of 2012 and 2011.

(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.

(f)	Includes blendstocks.

(g)

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

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. The discussion of such risks and uncertainties may be found under Item 1A. Risk Factors in our 2011 Annual Report on Form 10-K.

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

The following table provides information about purchases by Marathon Oil during the quarter ended June 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		Approximate Dollar
					Shares Purchased		Value of Shares that
					as Part of		May Yet Be
	Total Number of		Average Price Paid		Publicly Announced		Purchased Under the
Period	Shares Purchased (a)(b)		per Share		Plans or Programs(c)		Plans or Programs(c)
04/01/12 – 04/30/12		10,341	$	31.90		-	$	1,780,609,536
05/01/12 – 05/31/12		4,522	$	29.95		-	$	1,780,609,536
06/01/12– 06/30/12		46,608	$	24.68		-	$	1,780,609,536
Total		61,471	$	26.29		-

(a)	23,502 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

(b)

In June 2012, 37,969 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 June 30, 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:

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed Herewith

Furnished Herewith

12.1

Computation of Ratio of Earnings to Fixed Charges.

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase.

101.DEF

XBRL Taxonomy Extension Definition Linkbase.

101.LAB

XBRL Taxonomy Extension Label Linkbase.

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.

August 3, 2012	MARATHON OIL CORPORATION

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