MRO 10-Q Quarterly Report Sept. 30, 2010

MARATHON OIL CORP

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10-Q 1 form10q2010sep30.htm MARATHON OIL CORPORATION FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2010 form10q2010sep30.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 September 30, 2010

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

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)

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

5555 San Felipe Road, 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 x 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 x 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 x	Accelerated filer
Non-accelerated filer (Do not check if a smaller reporting company)	Smaller reporting company

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

There were 709,911,592 shares of Marathon Oil Corporation common stock outstanding as of October 29, 2010.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended September 30, 2010

	INDEX
		Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Consolidated Statements of Income (Unaudited)		2
	Consolidated Balance Sheets (Unaudited)		3
	Consolidated Statements of Cash Flows (Unaudited)		4
	Consolidated Statements of Comprehensive Income (Unaudited)		5
	Notes to Consolidated Financial Statements (Unaudited)		6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		36
Item 4.	Controls and Procedures		36
	Supplemental Statistics (Unaudited)		37
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		40
Item 1A.	Risk Factors		40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		42
Item 6.	Exhibits		43
	Signatures		44

Unless the context otherwise indicates, references in this Form 10-Q to “Marathon,” “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 exerts significant influence by virtue of its ownership interest).

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions, except per share data)	2010			2009			2010			2009
Revenues and other income:

Sales and other operating revenues (including	$	18,407		$	14,335		$	52,673		$	37,509
consumer excise taxes)
Sales to related parties		36			27			88			68
Income from equity method investments		95			75			301			184
Net gain on disposal of assets		5			5			830			200
Other income		32			35			77			112

Total revenues and other income		18,575			14,477			53,969			38,073
Costs and expenses:
Cost of revenues (excludes items below)		14,291			10,963			41,464			28,080
Purchases from related parties		180			133			454			338
Consumer excise taxes		1,351			1,258			3,871			3,658
Depreciation, depletion and amortization		765			627			2,072			1,970
Long-lived asset impairments		-			3			467			18
Selling, general and administrative expenses		324			323			958			935
Other taxes		99			98			324			296
Exploration expenses		59			55			282			181

Total costs and expenses		17,069			13,460			49,892			35,476

Income from operations		1,506			1,017			4,077			2,597

Net interest and other financing costs		(27	)		(35	)		(75	)		(63	)
Loss on early extinguishment of debt		-			-			(92	)		-


Income from continuing operations before income taxes		1,479			982			3,910			2,534

Provision for income taxes		783			590			2,048			1,549

Income from continuing operations		696			392			1,862			985

Discontinued operations		-			21			-			123

Net income	$	696		$	413		$	1,862		$	1,108

Per Share Data

Basic:

Income from continuing operations	$	0.98		$	0.55		$	2.63		$	1.39
Discontinued operations	$	-		$	0.03		$	-		$	0.17
Net income per share	$	0.98		$	0.58		$	2.63		$	1.56

Diluted:

Income from continuing operations	$	0.98		$	0.55		$	2.62		$	1.39
Discontinued operations	$	-		$	0.03		$	-		$	0.17
Net income per share	$	0.98		$	0.58		$	2.62		$	1.56

Dividends paid	$	0.25		$	0.24		$	0.74		$	0.72

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	September 30,			December 31,
(In millions, except per share data)	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	1,643		$	2,057
Receivables, less allowance for doubtful accounts of $18 and $14		5,363			4,677
Receivables from related parties		53			60
Inventories		3,969			3,622
Other current assets		572			221

Total current assets		11,600			10,637

Equity method investments		1,844			1,970
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $19,027 and $17,185		31,987			32,121
Goodwill		1,383			1,422
Other noncurrent assets		1,309			902

Total assets	$	48,123		$	47,052
Liabilities
Current liabilities:
Accounts payable	$	6,775		$	6,982
Payables to related parties		59			64
Payroll and benefits payable		362			399
Accrued taxes		1,407			547
Deferred income taxes		414			403
Other current liabilities		489			566
Long-term debt due within one year		98			96

Total current liabilities		9,604			9,057

Long-term debt		7,844			8,436
Deferred income taxes		3,940			4,104
Defined benefit postretirement plan obligations		1,846			2,056
Asset retirement obligations		1,166			1,099
Deferred credits and other liabilities		367			390

Total liabilities		24,767			25,142

Commitments and contingencies

Stockholders’ Equity
Preferred stock – zero and 5 million shares issued, zero and 1 million shares
outstanding (no par value, 26 million shares authorized)		-			-
Common stock:
Issued – 770 million and 769 million shares (par value
$1 per share, 1.1 billion shares authorized)		770			769
Securities exchangeable into common stock – zero and 5 million shares issued,
zero and 1 million shares outstanding (no par value, 29 million authorized)		-			-
Held in treasury, at cost – 60 million and 61 million shares		(2,681	)		(2,706	)
Additional paid-in capital		6,756			6,738
Retained earnings		19,379			18,043
Accumulated other comprehensive loss		(868	)		(934	)

Total stockholders' equity		23,356			21,910

Total liabilities and stockholders' equity	$	48,123		$	47,052

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


	Nine Months Ended
	September 30,
(In millions)	2010			2009
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	1,862		$	1,108
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on early extinguishment of debt		92			-
Discontinued operations		-			(123	)
Deferred income taxes		(228	)		726
Depreciation, depletion and amortization		2,072			1,970
Long-lived asset impairments		467			18
Pension and other postretirement benefits, net		(65	)		(159	)
Exploratory dry well costs and unproved property impairments		122			48
Net gain on disposal of assets		(830	)		(200	)
Equity method investments, net		4			42
Changes in:
Current receivables		(668	)		(1,241	)
Inventories		(665	)		(184	)
Current accounts payable and accrued liabilities		757			1,141
All other operating, net		68			78
Net cash provided by continuing operations		2,988			3,224
Net cash provided by discontinued operations		-			84
Net cash provided by operating activities		2,988			3,308
Investing activities:
Additions to property, plant and equipment		(3,634	)		(4,749	)
Disposal of assets		1,370			573
Trusteed funds - withdrawals		-			16
Investing activities of discontinued operations		-			(69	)
All other investing, net		8			63
Net cash used in investing activities		(2,256	)		(4,166	)
Financing activities:
Borrowings		-			1,491
Debt issuance costs		-			(11	)
Debt repayments		(628	)		(43	)
Dividends paid		(526	)		(510	)
All other financing, net		8			(1	)
Net cash provided by (used in) financing activities		(1,146	)		926
Effect of exchange rate changes on cash:
Continuing operations		-			19
Discontinued operations		-			(2	)
Total effect of exchange rate changes on cash		-			17
Net increase (decrease) in cash and cash equivalents		(414	)		85
Cash and cash equivalents at beginning of period		2,057			1,285
Cash and cash equivalents at end of period	$	1,643		$	1,370

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

MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2010			2009			2010			2009
Net income	$	696		$	413		$	1,862		$	1,108
Other comprehensive income (loss)

Post-retirement and post-employment plans
Change in actuarial gain (loss)		(24	)		9			134			58
Income tax provision on post-retirement and
post-employment plans		10			-			(73	)		(31	)
Post-retirement and post-employment plans, net of tax		(14	)		9			61			27

Derivative hedges
Net unrecognized gain		1			19			5			22
Income tax benefit (provision) on derivatives		-			(4	)		-			(11	)
Derivative hedges, net of tax		1			15			5			11

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

Other comprehensive income (loss)		(13	)		24			66			39

Comprehensive income	$	683		$	437		$	1,928		$	1,147

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. Certain reclassifications have been made to conform to current year presentation.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation (“Marathon”) 2009 Annual Report on Form 10-K. The results of operations for the quarter and nine months ended September 30, 2010 are not necessarily indicative of the results to be expected for the full year.

2. Accounting Standards

Recently Adopted

Variable interest accounting standards were amended by the Financial Accounting Standards Board (“FASB”) in June 2009. The new accounting standards replace the quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity. In addition, the concept of qualifying special-purpose entities has been eliminated. Ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity are also required. The amended variable interest accounting standards require reconsideration for determining whether an entity is a variable interest entity when changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lack the power from voting rights or similar rights to direct the activities of the entity. Enhanced disclosures are required for any enterprise that holds a variable interest in a variable interest entity. Prospective application of these standards in the first quarter of 2010 did not have a significant impact on our consolidated results of operations, financial position or cash flows. The required disclosures are presented in Note 3.

A standard to improve disclosures about fair value measurements was issued by the FASB in January 2010. The additional disclosures required include: (1) the different classes of assets and liabilities measured at fair value, (2) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the gross presentation of purchases, sales, issuances and settlements for the rollforward of Level 3 activity, and (4) the transfers in and out of Levels 1 and 2. We adopted all aspects of this standard in the first quarter of 2010. This adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows. The required disclosures are presented in Note 11.

Oil and Gas Reserve Estimation and Disclosure standards were issued by the FASB in January 2010, which align the FASB’s reporting requirements with the Securities and Exchange Commission (“SEC”) requirements. Similar to the SEC requirements, the FASB requirements were effective for us as of December 31, 2009. The SEC introduced a new definition of oil and gas producing activities which allows companies to include volumes in their reserve base from unconventional resources. The FASB also addresses the impact of changes in the SEC’s rules and definitions on accounting for oil and gas producing activities. Initial adoption did not have an impact on our consolidated results of operations, financial position or cash flows. The effect on depreciation, depletion and amortization expense subsequent to adoption, as compared to prior periods, was not significant.

3. Variable Interest Entities

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 mine, 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 $ 1 million current liability recorded at September 30, 2010. 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 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. Our maximum exposure to loss as a

Notes to Consolidated Financial Statements (Unaudited)

result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $832 million as of September 30, 2010. 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.

4. Income per Common Share

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

	Three Months Ended September 30,
	2010				2009
(In millions, except per share data)	Basic		Diluted		Basic		Diluted

Income from continuing operations	$	696	$	696	$	392	$	392
Discontinued operations		-		-		21		21
Net income	$	696	$	696	$	413	$	413

Weighted average common shares outstanding		710		710		709		709
Effect of dilutive securities		-		2		-		2
Weighted average common shares, including
dilutive effect		710		712		709		711

Per share:
Income from continuing operations	$	0.98	$	0.98	$	0.55	$	0.55
Discontinued operations	$	-	$	-	$	0.03	$	0.03
Net income	$	0.98	$	0.98	$	0.58	$	0.58

	Nine Months Ended September 30,
	2010				2009
(In millions, except per share data)	Basic		Diluted		Basic		Diluted

Income from continuing operations	$	1,862	$	1,862	$	985	$	985
Discontinued operations		-		-		123		123
Net income	$	1,862	$	1,862	$	1,108	$	1,108

Weighted average common shares outstanding		709		709		709		709
Effect of dilutive securities		-		2		-		2
Weighted average common shares, including
dilutive effect		709		711		709		711

Per share:
Income from continuing operations	$	2.63	$	2.62	$	1.39	$	1.39
Discontinued operations	$	-	$	-	$	0.17	$	0.17
Net income	$	2.63	$	2.62	$	1.56	$	1.56

The per share calculations above exclude 11 million and 12 million stock options and stock appreciation rights for the third quarter and the first nine months of 2010, as they were antidilutive. Excluded in the third quarter and the first nine months of 2009 were 11 million and 10 million stock options and stock appreciation rights.

5. Dispositions

Assets Held For Sale

In October 2010, we entered into definitive agreements to sell our Refining, Marketing and Transportation (“RM&T”) segment’s St. Paul Park, Minnesota, refinery (including associated terminal, tankage and pipeline investments) and 166 Speedway SuperAmerica retail outlets, plus related inventories. The fair value of the consideration is estimated to be approximately $900 million, which includes the estimated value of inventory and the fair values of (1) a retained preferred stock interest in the buyer with a stated value of $80 million, (2) a maximum $125 million earnout provision payable to us over eight years, and (3) a maximum $60 million of margin support payable to

Notes to Consolidated Financial Statements (Unaudited)

the buyer over two years. Cash proceeds at closing are estimated to be $700 million. The earnout and margin support provisions in the agreements are subject to certain conditions and any margin support paid may be recovered by an increase in the total earnout amount. We expect the sale transaction to close by yearend 2010, contingent upon the buyer meeting the conditions of their financing arrangements and other customary closing conditions.

As of September 30, 2010, the Minnesota assets and liabilities held for sale are reported in the consolidated balance sheet as follows:

(In millions)
Other current assets	$	308
Other noncurrent assets		512
Total assets		820

Deferred credits and other liabilities		3
Total liabilities	$	3

2010 Disposition

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

2009 Dispositions

In April 2009, we closed the sale of our operated properties in Ireland for net proceeds of $ 84 million, after adjusting for cash held by the sold subsidiary. A $158 million pretax gain on the sale was recorded. As a result of this sale, we terminated our pension plan in Ireland, incurring a charge of $ 18 million.

In June 2009, we entered into an agreement to sell the subsidiary holding our 19 percent outside-operated interest in the Corrib natural gas development offshore Ireland. An initial $100 million payment was made at closing. Additional fixed proceeds of $ 135 million will be received on the earlier of first commercial gas or December 31, 2012. Including contingent consideration, the fair value of $311 million at June 30, 2009, was less than book value. An impairment of $ 154 million was recognized in the second quarter of 2009 and reported as part of the loss on disposal of discontinued operations.

Existing guarantees of our subsidiaries’ performance issued to Irish government entities remain in place after the sales until the purchasers issue similar guarantees to replace them. The guarantees, related to asset retirement obligations and natural gas production levels, have been indemnified by the purchasers. The fair value of these guarantees is not significant.

In December 2009, we closed the sale of our operated fields offshore Gabon, receiving net proceeds of $ 269 million, after closing adjustments. A $232 million pretax gain on this disposition was reported in discontinued operations in the fourth quarter of 2009.

Our Irish businesses and our Gabonese businesses, which had been reported in our E&P segment, have been reported as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for the three and nine months ended September 30, 2009. Revenues, pretax income and the net pretax loss on these dispositions are shown on the table below.

		Three Months Ended		Nine Months Ended
		September 30,		September 30,
(In millions)	2009			2009
Revenues applicable to discontinued operations		$	65		$	186
Pretax income from discontinued operations			48			98
Pretax loss on disposal of discontinued operations		$	-		$	14

In June 2009, we closed sales of a portion of our operated and all of our outside-operated Permian Basin producing assets in New Mexico and west Texas for net proceeds after closing adjustments of $ 293 million. A $196 million pretax gain on the sale was recorded. Activities related to these properties had been reported in our E&P segment.

Notes to Consolidated Financial Statements (Unaudited)

6. Segment Information

We have four 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;

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

Refining, Marketing and Transportation (“RM&T”) – refines, markets and transports crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States.

As discussed in Note 5, our Irish and Gabonese businesses were sold in 2009 and have been reported as discontinued operations. Segment information for all presented periods of 2009 excludes amounts for these operations.

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

Revenues:
Customer	$	2,343		$	156		$	38	$	15,870		$	18,407
Intersegment (a)		174			34			-		6			214
Related parties		15			-			-		21			36
Segment revenues		2,532			190			38		15,897			18,657
Elimination of intersegment revenues		(174	)		(34	)		-		(6	)		(214	)
Total revenues	$	2,358		$	156		$	38	$	15,891		$	18,443
Segment income	$	510		$	18		$	41	$	285		$	854
Income from equity method investments (b)		51			-			51		18			120
Depreciation, depletion and amortization (c)		491			28			1		234			754
Income tax provision (b)		579			2			21		170			772
Capital expenditures (c)(d)		586			191			1		273			1,051

	Three Months Ended September 30, 2009
(In millions)	E&P			OSM			IG		RM&T			Total

Revenues:
Customer	$	1,816		$	130		$	15	$	12,387		$	14,348
Intersegment (a)		148			37			-		8			193
Related parties		15			-			-		12			27
Segment revenues		1,979			167			15		12,407			14,568
Elimination of intersegment revenues		(148	)		(37	)		-		(8	)		(193	)
Loss on U.K. natural gas contracts (e)		(13	)		-			-		-			(13	)
Total revenues	$	1,818		$	130		$	15	$	12,399		$	14,362
Segment income	$	491		$	25		$	13	$	158		$	687
Income from equity method investments		40			-			21		14			75
Depreciation, depletion and amortization (c)		424			26			1		167			618
Income tax provision (b)		297			7			12		119			435
Capital expenditures (c)(d)		516			267			-		634			1,417

Notes to Consolidated Financial Statements (Unaudited)

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

Revenues:
Customer	$	7,144		$	461		$	98	$	44,970		$	52,673
Intersegment (a)		498			73			-		37			608
Related parties		41			-			-		47			88
Segment revenues		7,683			534			98		45,054			53,369
Elimination of intersegment revenues		(498	)		(73	)		-		(37	)		(608	)
Total revenues	$	7,185		$	461		$	98	$	45,017		$	52,761
Segment income (loss)	$	1,444		$	(59	)	$	109	$	469		$	1,963
Income from equity method investments (b)		128			-			142		56			326
Depreciation, depletion and amortization (c)		1,279			67			3		695			2,044
Income tax provision (benefit) (b)		1,741			(15	)		56		274			2,056
Capital expenditures (c)(d)		1,774			699			2		839			3,314

	Nine Months Ended September 30, 2009
(In millions)	E&P			OSM			IG		RM&T			Total

Revenues:
Customer	$	4,952		$	353		$	33	$	32,099		$	37,437
Intersegment (a)		390			91			-		25			506
Related parties		44			-			-		24			68
Segment revenues		5,386			444			33		32,148			38,011
Elimination of intersegment revenues		(390	)		(91	)		-		(25	)		(506	)
Gain on U.K. natural gas contracts (e)		72			-			-		-			72
Total revenues	$	5,068		$	353		$	33	$	32,123		$	37,577
Segment income	$	782		$	3		$	53	$	482		$	1,320
Income from equity method investments		77			-			91		16			184
Depreciation, depletion and amortization (c)		1,373			97			3		476			1,949
Income tax provision (benefit) (b)		910			(1	)		27		329			1,265
Capital expenditures (c)(d)		1,490			834			1		2,007			4,332

(a)	Management believes intersegment transactions were conducted under terms comparable to those with unrelated parties.

(b)	Differences between segment totals and our financial statement totals represent amounts related to corporate administrative activities and other unallocated items and are included in “Items not allocated to segments, net of income taxes” in the reconciliation below.

(c)	Differences between segment totals and our financial statement totals represent amounts related to corporate administrative activities.

(d)	Includes accruals.

(e)	The U.K. natural gas contracts expired in September 2009.

Notes to Consolidated Financial Statements (Unaudited)

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2010			2009			2010			2009
Segment income	$	854		$	687		$	1,963		$	1,320
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(106	)		(159	)		(178	)		(299	)
Foreign currency remeasurement of income taxes		(37	)		(114	)		33			(180	)
Gain (loss) on dispositions (a)		-			(15	)		449			107
Impairments (b)		(15	)		-			(303	)		-
Loss on early extinguishment of debt (c)		-			-			(57	)		-
Deferred income taxes - tax legislation changes (d)		-			-			(45	)		-
Gain on U.K. natural gas contracts		-			(7	)		-			37
Discontinued operations		-			21			-			123
Net income	$	696		$	413		$	1,862		$	1,108

(a)	Additional information on these gains can be found in Note 5.

(b)

Impairments include those based upon fair value measurements discussed in Note 11 and a $15 million pretax writeoff of the remaining portion of the contingent proceeds from the 2009 sale of the Corrib natural gas development, which was recorded in the second quarter of 2010, based upon new public information regarding the pipeline that would transport natural gas from the Corrib development.

(c)	Additional information on debt retired early can be found in Note 13.

(d)	A discussion of the tax legislation changes can be found in Note 8.

The following reconciles total revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(In millions)	2010			2009		2010			2009
Total revenues		$	18,443	$	14,362		$	52,761		$	37,577
Less: Sales to related parties			36		27			88			68
Sales and other operating revenues (including
consumer excise taxes)		$	18,407	$	14,335		$	52,673		$	37,509

7. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Three Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2010			2009			2010			2009
Service cost	$	27		$	36		$	4		$	4
Interest cost		44			42			10			11
Expected return on plan assets		(40	)		(41	)		-			-
Amortization:
– prior service cost (credit)		4			4			(1	)		(1	)
– actuarial loss (gain)		24			8			(1	)		(2	)
– net settlement		12			-			-			-
Net periodic benefit cost	$	71		$	49		$	12		$	12

Notes to Consolidated Financial Statements (Unaudited)

	Nine Months Ended September 30,
	Pension Benefits						Other Benefits
(In millions)	2010			2009			2010			2009
Service cost	$	81		$	108		$	13		$	13
Interest cost		131			126			29			31
Expected return on plan assets		(120	)		(121	)		-			-
Amortization:
– prior service cost (credit)		10			11			(4	)		(4	)
– actuarial loss (gain)		74			24			(2	)		(4	)
– net settlement/curtailment loss		12			18			-			-
Net periodic benefit cost	$	188		$	166		$	36		$	36

During the first nine months of 2010, we made contributions of $240 million to our funded pension plans. We expect to make additional contributions up to an estimated $2 million to our funded pension plans over the remainder of 2010. Current benefit payments related to unfunded pension and other postretirement benefit plans were $29 million and $26 million during the first nine months of 2010.

8. Income Taxes

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

	Nine Months Ended September 30,
	2010			2009
Statutory U.S. income tax rate		35	%		35	%
Effects of foreign operations, including foreign tax credits		17			25
State and local income taxes, net of federal income tax effects		-			1
Legislation change		1			-
Other		(1	)		-
Effective income tax rate for continuing operations		52	%		61	%

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

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income, the relative magnitude of these sources of income, and foreign currency remeasurement effects. 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 the Corporate and other unallocated items line of the reconciliation shown in Note 6.

Notes to Consolidated Financial Statements (Unaudited)

9. Inventories

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

	September 30,		December 31,
(In millions)	2010		2009
Liquid hydrocarbons, natural gas and bitumen	$	1,555	$	1,393
Refined products and merchandise		2,046		1,790
Supplies and sundry items		368		439
Inventories	$	3,969	$	3,622

10. Property, Plant and Equipment

	September 30,		December 31,
(In millions)	2010		2009
E&P
United States	$	6,118	$	6,005
International		4,964		5,522
Total E&P		11,082		11,527
OSM		9,100		8,531
IG		35		34
RM&T		11,628		11,887
Corporate		142		142
Property, plant and equipment	$	31,987	$	32,121

Exploratory well costs capitalized greater than one year after completion of drilling were $158 million as of September 30, 2010, an increase of $8 million from December 31, 2009.

The offshore Gulf of Mexico Shenandoah appraisal well, located at Walker Ridge Block 52, was added to this category in the first quarter of 2010 at a cost of $28 million. The Shenandoah costs were incurred primarily during 2009. Appraisal drilling for the Shenandoah prospect is in our near-term plans. The results of the appraisal well program will be used to evaluate the commercial viability of the project.

In the first quarter of 2010, a detailed study of the commerciality of the Gardenia well in Equatorial Guinea concluded that development of the area was uncertain; therefore, we wrote off $20 million in costs associated with the well. The remaining $ 10 million of exploration well costs in Equatorial Guinea are associated with the Corona well which were incurred in 2004. Efforts to develop these reserves continue and we are evaluating both a unitization with existing production facilities and stand-alone development.

Notes to Consolidated Financial Statements (Unaudited)

11. Fair Value Measurements

Fair Values - Recurring

The following table presents assets and liabilities accounted for at fair value on a recurring basis as of September 30, 2010 and December 31, 2009 by fair value hierarchy level.

	September 30, 2010
(In millions)	Level 1			Level 2			Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	149		$	23		$	1	$	90		263
Interest rate		-			45			-		-		45
Foreign currency		-			-			1		-		1
Derivative instruments, assets		149			68			2		90		309
Derivative instruments, liabilities
Commodity	$	(207	)	$	(1	)	$	-	$	-		(208	)
Derivative instruments, liabilities		(207	)		(1	)		-		-		(208	)

	December 31, 2009
(In millions)	Level 1			Level 2			Level 3			Collateral		Total
Derivative instruments, assets
Commodity	$	133		$	11		$	12		$	63	$	219
Interest rate		-			-			7			-		7
Foreign currency		-			1			2			-		3
Derivative instruments, assets		133			12			21			63		229
Derivative instruments, liabilities
Commodity	$	(125	)	$	(12	)	$	(10	)	$	-	$	(147	)
Interest rate		-			-			(2	)		-		(2	)
Derivative instruments, liabilities		(125	)		(12	)		(12	)		-		(149	)

Commodity derivatives in Level 1 are exchange-traded contracts for crude oil, natural gas, refined products and ethanol measured at fair value with a market approach using the close-of-day settlement price for the market. Commodity derivatives, interest rate derivatives and foreign currency forwards in Level 2 are measured at fair value with a market approach using broker price quotes or prices obtained from third-party services such as Bloomberg L.P. or Platt’s, a Division of McGraw-Hill Corporation (“Platt’s”), which have been corroborated with data from active markets for similar assets and liabilities. Collateral deposits related to both Level 1 and Level 2 commodity derivatives are in broker accounts covered by master netting agreements.

Commodity derivatives in Level 3 are measured at fair value with a market approach using prices obtained from third-party services such as Platt’s and price assessments from other independent brokers. The fair value of foreign currency options is measured using an option pricing model for which the inputs are obtained from a reporting service. Since we are unable to independently verify information from the third-party service providers to active markets, all these measures are considered Level 3.

Interest rate derivatives, formerly in Level 3, are reported in Level 2 beginning second quarter because we now corroborate the interest rates used in the fair value measurement.

Notes to Consolidated Financial Statements (Unaudited)

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						Nine Months Ended
	September 30,						September 30,
(In millions)	2010			2009			2010			2009
Beginning balance	$	(3	)	$	(29	)	$	9		$	(26	)
Total realized and unrealized gains (losses):
Included in net income		4			19			23			63
Included in other comprehensive income		-			-			4			-
Transfers to Level 2		-			-			(30	)		-
Purchases		-			1			2			1
Sales		-			-			-			(23	)
Issuances		-			-			-			(44	)
Settlements		1			8			(6	)		28
Ending balance	$	2		$	(1	)	$	2		$	(1	)

Related to the derivatives in Level 3, net income for the third quarter and first nine months of 2010 included unrealized gains of $3 million related to instruments held at September 30, 2010. Net income for third quarter and first nine months of 2009 included unrealized gains of $4 million and unrealized losses of $20 million related to instruments held on those dates. See Note 12 for the income statement impacts of our derivative instruments.

Fair Values - Nonrecurring

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

		Three Months Ended September 30,
		2010					2009
(In millions)		Fair Value			Impairment		Fair Value		Impairment
Equity method investment	$	-	$		25	$	-	$	-

		Nine Months Ended September 30,
		2010					2009
(In millions)		Fair Value			Impairment		Fair Value		Impairment
Long-lived assets held for use	$	146		$	467	$	5	$	15
Long-lived assets held for sale		-			-		311		154
Equity method investment		-			25		-		-

In the third quarter of 2010, we fully impaired our Integrated Gas segment’s equity method investment in an entity engaged in gas-to-fuels related technology. This investment was determined to have sustained an other than temporary loss in value. Based upon recent financial information, the fair value was measured with an income approach using internally developed estimates of future cash flows. These cash flows are Level 3 inputs.

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

As a result of changing market conditions, a supply agreement with a major customer was revised in June 2010. An impairment of $28 million was recorded for a plant that manufactures maleic anhydride. The plant was operated by our RM&T segment. The fair value was measured using a market approach based upon comparable area land values which are Level 3 inputs.

Notes to Consolidated Financial Statements (Unaudited)

Several other long-lived assets held for use in our E&P segment were evaluated for impairment in the nine months ended September 30, 2010 and the comparable period of 2009 due to reduced drilling expectations, reduction of estimated reserves or declining natural gas prices. The fair values of the assets were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, which are Level 3 inputs.

The impairment charge recorded on assets held for sale in the second quarter of 2009 related to the sale of the Corrib natural gas development offshore Ireland and was based on a fair value of anticipated sale proceeds (see Note 5). Fair value of anticipated sale proceeds includes (1) $100 million received at closing, (2) $ 135 million minimum amount due at the earlier of first gas or December 31, 2012, and (3) a range of contingent proceeds subject to the timing of first gas. The fair value of the total proceeds was measured using an income method that incorporated a probability-weighted approach with respect to timing of first commercial gas and an associated sliding scale on the amount of corresponding consideration specified in the sales agreement: the longer it takes to achieve first gas, the lower the amount of the consideration. Because a portion of the proceeds is variable in timing and amount depending upon timing of first commercial gas, the inputs to the fair value calculation were classified as Level 3 inputs.

Fair Values – Reported

The following table summarizes financial instruments, excluding the derivative financial instruments, and their reported fair value by individual balance sheet line item at September 30, 2010 and December 31, 2009:


	September 30, 2010				December 31, 2009
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Other current assets	$	23	$	22	$	23	$	22
Other noncurrent assets		596		407		671		499

Total financial assets		619		429		694		521

Financial liabilities
Long-term debt, including current portion (a)		8,628		7,563		8,754		8,190
Deferred credits and other liabilities		70		71		71		73

Total financial liabilities	$	8,698	$	7,634	$	8,825	$	8,263

(a)	Excludes capital leases.

Our current assets and liabilities accounts include financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our current assets and liabilities approximate fair value, with the exception of the current portion of receivables from United States Steel Corporation (“United States Steel”), which is reported in other current assets above, and the current portion of our long-term debt, which is reported with long-term debt above. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

The current portion of receivables from United States Steel is reported in other current assets, and the long-term portion is included in other noncurrent assets. The fair value of the receivables from United States Steel is measured using an income approach that discounts the future expected payments over the remaining term of the obligations. Because this receivable is not publicly-traded and not easily transferable, a hypothetical market based upon United States Steel’s borrowing rate curve is assumed, and the majority of inputs to the calculation are Level 3. The industrial revenue bonds are to be redeemed on or before January 1, 2012, the tenth anniversary of the USX Separation.

Restricted cash is included in other noncurrent assets. The majority of our restricted cash represent cash accounts that earn interest; therefore, the balance approximates fair value. Fair values of our remaining financial assets included in 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 the market they are considered Level 3 inputs. The fair value of our debt that is not publicly-

Notes to Consolidated Financial Statements (Unaudited)

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.

12. Derivatives

For information regarding the fair value measurement of derivative instruments, see Note 11. The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of September 30, 2010, and December 31, 2009.

	September 30, 2010
(In millions)	Asset		Liability		Net Asset			Balance Sheet Location
Cash Flow Hedges
Foreign currency	$	1	$	-	$	1		Other current assets
Fair Value Hedges
Interest rate		45		-		45		Other noncurrent assets
Total Designated Hedges		46		-		46

Not Designated as Hedges
Commodity		173		208		(35	)	Other current assets
Total Not Designated as Hedges		173		208		(35	)

Total	$	219	$	208	$	11

	December 31, 2009
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Cash Flow Hedges
Foreign currency	$	2	$	-	$	2	Other current assets
Fair Value Hedges
Interest rate		8		3		5	Other noncurrent assets
Total Designated Hedges		10		3		7

Not Designated as Hedges
Foreign currency		1		-		1	Other current assets
Commodity		116		104		12	Other current assets
Total Not Designated as Hedges		117		104		13

Total	$	127	$	107	$	20

	December 31, 2009
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Cash Flow Hedges
Foreign currency	$	-	$	-	$	-	Other current liabilities
Fair Value Hedges
Commodity		-		1		1	Other current liabilities
Total Designated Hedges		-		1		1

Not Designated as Hedges

Commodity		13		15		2	Other current liabilities

Total Not Designated as Hedges		13		15		2
Total	$	13	$	16	$	3

Notes to Consolidated Financial Statements (Unaudited)

Derivatives Designated as Cash Flow Hedges

As of September 30, 2010, the following foreign currency forwards and options were designated as cash flow hedges.

(In millions)	Period		Notional Amount	Weighted Average Forward Rate
Foreign Currency Forwards:
Dollar (Canada)	October 2010 - December 2010	$	8	1.080 (a)

(a)	Foreign currency to U.S. dollar.

(In millions)	Period		Notional Amount	Weighted Average Exercise Price
Foreign Currency Options:
Dollar (Canada)	October 2010 - December 2010	$	48	1.040 (a)

(a) U.S. dollar to foreign currency.

The following table summarizes the pretax effect of derivative instruments designated as hedges of cash flows in other comprehensive income.

	Gain (Loss) in OCI
	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2010			2009			2010			2009
Foreign currency		$	1		$	19		$	4		$	37
Interest rate			-			-			-			(15	)

Derivatives Designated as Fair Value Hedges

As of September 30, 2010, we had multiple interest rate swap agreements with a total notional amount of $ 1,450 million at a weighted-average, LIBOR-based, floating rate of 4.4 percent.

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

		Gain (Loss)
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(In millions)	Income Statement Location	2010				2009				2010				2009
Derivative
Interest rate	Net interest and other financing costs		$	15			$	26			$	39			$	(3	)
Hedged Item
Long-term debt	Net interest and other financing costs		$	(15	)		$	(26	)		$	(39	)		$	3

Derivatives not Designated as Hedges

The largest portion of our September 30, 2010, open commodity derivative contracts not designated as hedges in our E&P and OSM segments are related to 2010 forecasted sales, as shown in the table below.

	Term	Bbls per Day		Weighted Average Swap Price		Benchmark
Crude Oil
Canada	October 2010 - December 2010		25,000	$	82.56	West Texas Intermediate

Notes to Consolidated Financial Statements (Unaudited)

	Term	Mmbtu per Day (a)		Weighted Average Swap Price		Benchmark
Natural Gas
U.S. Lower 48	October 2010 - December 2010		80,000	$	5.39	CIG Rocky Mountains (b)
U.S. Lower 48	October 2010 - December 2010		30,000	$	5.59	NGPL Mid Continent (c)

(a) Million British thermal units.

(b) Colorado Interstate Gas Co. (“CIG”).

The table below summarizes open commodity derivative contracts of our RM&T segment at September 30, 2010 that are not designated as hedges. These contracts enable us to effectively correlate our commodity price exposure to the relevant market indicators, thereby mitigating fixed price risk.

	Position	Bbls per Day			Weighted Average (Dollars per Bbl)		Benchmark
Crude Oil
Exchange-traded	Long (a)		88,641		$	77.27	CME and IPE Crude (b) (c)
Exchange-traded	Short (a)		(128,885	)	$	77.17	CME and IPE Crude (b) (c)

	Position	Bbls per Day			Weighted Average (Dollars per Gallon)		Benchmark
Refined Products
Exchange-traded	Long (d)		10,121		$	2.04	CME Heating Oil and RBOB (b) (e)
Exchange-traded	Short (d)		(12,764	)	$	2.06	CME Heating Oil and RBOB (b) (e)

(a) 97 percent of these contracts expire in the fourth quarter of 2010.

(b) Chicago Mercantile Exchange (“CME”).

(d) 100 percent of these contracts expire in the fourth quarter of 2010.

(e) Reformulated Gasoline Blendstock for Oxygen Blending (“RBOB”).

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

		Gain (Loss)
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
(In millions)	Income Statement Location	2010				2009				2010			2009
Commodity	Sales and other operating revenues		$	4			$	(11	)		$	133		$	80
Commodity	Cost of revenues			(17	)			(17	)			27			(59	)
Commodity	Other income			1				4				3			7
			$	(12	)		$	(24	)		$	163		$	28

Notes to Consolidated Financial Statements (Unaudited)

13. Debt

At September 30, 2010, we had no borrowings against our revolving credit facility and no commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

In April 2010, we repurchased $ 500 million in aggregate principal of our debt under two tender offers for the notes below, at a weighted average price equal to 117 percent of face value.

(In millions)
9.375% debentures due 2012	$	34
9.125% debentures due 2013		60
6.000% Senior notes due 2017		68
5.900% Senior notes due 2018		106
7.500% debentures due 2019		112
9.375% debentures due 2022		33
8.500% debentures due 2023		46
8.125% debentures due 2023		41
Total	$	500

As a result of the tender offers, we recorded a loss on extinguishment of debt of $92 million in the second quarter of 2010, including the transaction premium costs as well as deferred financing costs related to the repurchased debt.

In May 2010, United States Steel redeemed $89 million of certain industrial development and environmental improvements bonds for which we were liable.

14. Stock-Based Compensation Plans

The following table presents a summary of stock option award and restricted stock award activity for the nine months ended September 30, 2010:

	Stock Options					Restricted Stock
	Number of Shares			Weighted Average Exercise Price		Awards			Weighted Average Grant Date Fair Value


Outstanding at December 31, 2009		18,230,074		$	35.01		1,441,499		$	44.89
Granted (a)		4,757,080			30.00		453,674			30.54
Options Exercised/Stock Vested		(376,995	)		21.89		(522,197	)		49.50
Canceled		(802,503	)		39.12		(124,611	)		40.71
Outstanding at September 30, 2010		21,807,656		$	34.00		1,248,365		$	38.16

(a) The weighted average grant date fair value of stock option awards granted was $8.70 per share.

Notes to Consolidated Financial Statements (Unaudited)

15. Stockholders’ Equity

In conjunction with our acquisition of Western Oil Sands Inc. on October 18, 2007, Canadian residents were able to receive, at their election, cash, Marathon common stock or securities exchangeable into Marathon common stock (the “Exchangeable Shares”). The Exchangeable Shares are shares of an indirect Canadian subsidiary of Marathon and were exchanged into Marathon stock based upon an exchange ratio that began at one-for-one and adjusted quarterly to reflect cash dividends. The Exchangeable Shares were exchangeable at the option of the holder at any time and were automatically redeemable on October 18, 2011. They could also be redeemed prior to their automatic redemption if certain conditions were met. Those conditions were met and we filed notice of the proposed redemption in Canada on March 3, 2010. On April 7, 2010, the remaining exchangeable shares were redeemed and the related preferred shares were eliminated in June 2010.

16. Supplemental Cash Flow Information

	Nine Months Ended September 30,
(In millions)	2010		2009
Net cash provided from operating activities:
Interest paid (net of amounts capitalized)	$	93	$	26
Income taxes paid to taxing authorities		1,426		1,398
Commercial paper and revolving credit arrangements, net:
Commercial paper - issuances	$	-	$	897
- repayments		-		(897	)
Total	$	-	$	-
Noncash investing and financing activities:
Capital lease obligations increase	$	26	$	73
Debt payments made by United States Steel		106		15

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

	Nine Months Ended September 30,
(in millions)	2010			2009
Additions to property, plant and equipment	$	3,634		$	4,749
Change in capital accruals		(293	)		(402	)
Discontinued operations		-			69
Capital expenditures	$	3,341		$	4,416

17. Commitments and Contingencies

We are the subject of, or party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to our consolidated financial statements. However, management believes that we will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably. Certain of our commitments are discussed below.

Contractual commitments – At September 30, 2010, Marathon’s contract commitments to acquire property, plant and equipment were $2,843 million.

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

We are a global integrated energy company with operations in the U.S., Canada, Africa and Europe. Our operations are organized into four reportable segments:

	w		Exploration and Production (“E&P”) which explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.
	w		Oil Sands Mining (“OSM”) which mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
	w		Integrated Gas (“IG”) which markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis.
	w		Refining, Marketing & Transportation (“RM&T”) which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States.

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 forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2009 Annual Report on Form 10-K and the update to Item 1A. Risk Factors later in this Form 10-Q.

Activities related to discontinued operations in Gabon and Ireland have been excluded from segment results and operating statistics in comparative periods.

Overview and Outlook

Gulf of Mexico Drilling Moratorium

On April 22, 2010, the Deepwater Horizon, a rig that was engaged in drilling operations in the deepwater Gulf of Mexico, sank after an explosion and fire. The incident resulted in a significant oil spill in the Gulf of Mexico. We have no ownership interest in those operations.

As a result of the Deepwater Horizon incident, the U.S. Department of the Interior issued a drilling moratorium, which was lifted on October 12, 2010, to suspend the drilling of wells using subsea blowout preventers or operations using a floating facility. As a result of the drilling moratorium, we suspended drilling an exploratory well on the Innsbruck prospect, located on Mississippi Canyon Block 993. Although the drilling moratorium has been lifted, it is not known when plans and permits will be approved for future deepwater drilling activity. The effects of new or additional laws or regulations that may be adopted in response to this incident are not fully known at this time and may impact future project execution.

Exploration and Production (“E&P”)

Exploration

Our 2010 exploration program is expected to exceed $1 billion and is focused on North America resource plays, the deepwater Gulf of Mexico, Indonesia, Norway and Libya. As stated above, in the Gulf of Mexico we suspended drilling on the Innsbruck prospect during the second quarter due to the drilling moratorium. The Noble Jim Day drilling rig has been contracted and is scheduled to become available in the fourth quarter of 2010, subject to regulatory uncertainties described above. Commissioning and testing of the rig has begun. It is our intent to reestablish our Gulf of Mexico exploration and development programs unless new laws, regulations or court orders prohibit these activities or make them not viable financially. The revised cost of the Innsbruck well is now estimated at $145 million. We are the operator and hold an 85 percent working interest in the prospect.

In December 2009, we began drilling an exploratory well on the Flying Dutchman prospect, located on Green Canyon Block 511 in the Gulf of Mexico. The Flying Dutchman reached its targeted total depth in early May 2010. The well encountered hydrocarbon-bearing sands that require further technical evaluation. During the second quarter of 2010, we expensed approximately $51 million for drilling costs incurred below the depth of the hydrocarbon-bearing

sands and have approximately $95 million of exploratory well costs suspended as of September 30, 2010 . The results of the Flying Dutchman will continue to be evaluated along with additional potential drilling on Green Canyon Block 511 to determine overall commerciality. We are the operator and have a 63 percent working interest in this prospect.

During the second quarter 2010, we were awarded all five blocks bid in the Central Gulf of Mexico Lease Sale No. 213 conducted by the U.S. Department of the Interior, for a total of $24 million. Four blocks are 100 percent Marathon, and the remaining block was bid with partners.

We acquired approximately 120,000 net acres within the Niobrara play in the DJ Basin of southeast Wyoming and northern Colorado. We expect to commence drilling in 2011.

In the Oklahoma Woodford shale, we continue to expand our acreage position and now hold approximately 75,000 net acres within the play. We have existing production operations in this geographical area which will facilitate early drilling, with initial wells currently in progress.

In Indonesia, we began our deepwater exploration drilling program in the Pasangkayu block in August 2010 and are targeting the Bravo and Romeo prospects. The Bravo exploration well is expected to reach total depth in the fourth quarter while the Romeo exploration well is expected to reach total depth during the first half of 2011. We are the operator and hold a 70 percent working interest in the Pasangkayu block.

In October 2010, we announced the acquisition of a position in four exploration blocks in the Kurdistan Region of Iraq. We have signed production sharing agreements for operatorship and an 80 percent ownership in two open blocks northeast of Erbil, Harir and Safen. The Kurdistan Regional Government will hold a 20 percent interest but bear no costs. We were assigned working interests in two additional blocks located north-northwest of Erbil, Atrush in which we have a 20 percent working interest and Sarsang in which we have a 25 percent working interest. The total entry cost, subject to final adjustments, is $156 million plus a pro rata share of historic exploration costs estimated to be $20 million. This transaction provides us with access to approximately 295,000 net acres. We have committed to a seismic program and to drilling one well on each of the two open blocks during the initial three-year exploration period. The Atrush and Sarsang blocks each have a well currently drilling.

In September 2010, we added an eleventh license with shale gas potential in Poland, increasing our total acreage position to approximately 2.3 million net acres. We have a 100 percent interest and operate all 11 blocks. We continue to pursue additional licenses and plan to begin geologic studies in Poland in 2010 followed by the acquisition of seismic in 2011 and plans to initiate drilling by the fourth quarter of 2011.

Production

Net liquid hydrocarbon and natural gas sales averaged 399 thousand barrels of oil equivalent per day (“mboepd”) during the third quarter and 382 mboepd during the first nine months of 2010 compared to 366 and 396 mboepd during the third quarter and first nine months of 2009. The increase in sales volumes in the third quarter of 2010 over the same period of the previous year is primarily related to Droshky development production beginning in this quarter and reliability at both our Alvheim development offshore Norway and the Alba field and related facilities in Equatorial Guinea. The 3 percent decrease for the nine-month period was primarily related to the sale of a portion of our Permian Basin assets in the second quarter of 2009, the planned turnaround in Equatorial Guinea in the first four months of 2010, maintenance downtime offshore U.K., and normal production declines.

Our Droshky development in the Gulf of Mexico on Green Canyon Block 244 began production in mid-July of 2010 and reached peak net production of 45,000 boepd in the third quarter of 2010, down from the original estimate of 50,000 boepd. Production declines have been steeper than anticipated due to reservoir compartmentalization and lack of aquifer support. This subsea project consists of four development wells tied back to a third-party platform. Three of the four wells are currently producing, while production from the fourth well has been delayed due to an equipment issue. We plan to re-enter the fourth well in the first quarter of 2011 to make the necessary repairs. We hold a 100 percent operated working interest and an 81 percent net revenue interest in Droshky.

Our net liquid hydrocarbon sales in North Dakota from the Bakken Shale resource play have increased to 13 thousand barrels per day (“bpd”) in third quarter of 2010 compared to 11 mbpd in the same quarter of last year. We added a sixth operated rig during the third quarter of 2010.

In the second quarter of 2010, we commenced production at the Volund field offshore Norway which allows us to maintain full capacity on the Alvheim floating production, storage and offloading (“FPSO”) vessel. We hold a 65 percent operated interest in the Volund field.

In Libya, Phase II of the Faregh project began commissioning during the third quarter of 2010 and first production is expected in November 2010. We have continued our exploration program in Libya with six discoveries in 2010.

Divestitures

During the first quarter 2010, we closed the sale of a 20 percent outside-operated interest in the Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola. We received net proceeds of $1.3 billion and

recorded a pretax gain on the sale in the amount of $811 million. We retained a 10 percent outside-operated interest in Block 32.

The above discussions include forward-looking statements with respect to the timing and levels of future production, exploration budget, anticipated future exploratory and development drilling activity, the Droshky development, the possibility of a significant new resource base in the Iraqi Kurdistan region, Phase II of the Faregh project in Libya, and the drilling moratorium. While the drilling moratorium was lifted on October 12, 2010, we cannot predict when plans and permits will be approved for future deepwater drilling activities. Some factors that could potentially affect these forward-looking statements include pricing, supply and demand for crude oil, natural gas and petroleum products, 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, and other geological, operating and economic considerations. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements. The exploration budget is based on current expectations, estimates and projections and is not a guarantee of future performance. The foregoing forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals and permits.

Oil Sands Mining (“OSM”)

Our net synthetic crude oil sales were 31 thousand barrels per day (“mbpd”) in the third quarter and 25 mbpd in the first nine months of 2010 compared to 33 mbpd and 31 mbpd in same periods of 2009. Current year sales continue to reflect the impact of the planned turnaround at the Muskeg River mine and upgrader that began March 22, 2010 and halted production in April before a staged resumption of operations in May. Incurred in the first six months of 2010, our net share of total turnaround costs was $99 million.

In the third quarter of 2010, the AOSP Expansion 1 project began a phased start-up of the Jackpine Mine operations, which will add capacity of 100,000 gross bpd to the existing Muskeg River Mine capacity of 155,000 bpd. The expanded upgrader operations are on schedule for a phased start-up beginning in late 2010 and extending into early 2011. Expansion 1 includes construction of mining and extraction facilities at the Jackpine mine, expansion of treatment facilities at the existing Muskeg River mine, expansion of the Scotford upgrader and development of related infrastructure. We hold a 20 percent working interest in the AOSP.

The above discussion includes forward-looking statements with respect to the start of operations of AOSP Expansion 1. Factors that could affect the project are transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects.

Integrated Gas (“IG”)

Our share of LNG sales worldwide totaled 7,142 metric tonnes per day (“mtpd”) for the third quarter of 2010 compared to 6,372 mtpd in the third quarter of 2009 and 6,502 mtpd in the first nine months of 2010 compared to 6,583 mtpd in the first nine months of 2009. These LNG sales volumes include both consolidated sales volumes and our share of the sales volumes of equity method investees. LNG sales from Alaska are conducted through a consolidated subsidiary. LNG and methanol sales from Equatorial Guinea are conducted through equity method investees.

Refining, Marketing and Transportation (“RM&T”)

Our total refinery throughputs were 21 percent higher in the third quarter and 15 percent higher in the first nine months of 2010 compared to the same periods of 2009. Crude oil refined increased 24 percent in both periods primarily related to the startup of the Garyville, Louisiana, expansion, while other charge and blendstocks increased 6 percent and decreased 25 percent compared to the third quarter and first nine months of 2009. Due to the significant turnaround activity in the first quarter of 2010, along with the expected reduction in external charge and blendstocks requirements due to the Garyville refinery expansion, we have reduced our purchased charge and blendstocks volume in the first nine months of 2010.

We completed turnarounds at our Garyville, Texas City, Texas, Catlettsburg, Kentucky, Robinson, Illinois and St. Paul Park, Minnesota, refineries in the first nine months of 2010. Such activity compares to turnarounds at our Canton, Ohio; Robinson, Catlettsburg and Garyville refineries in the first nine months of 2009.

The refinery units completed as part of the expansion at Garyville have now been fully integrated into the Garyville refinery and are operating as expected. The 180,000 bpd expansion establishes the Garyville facility as the fourth-largest U.S. refinery with a rated crude oil capacity of 436,000 bpd.

Ethanol volumes sold in blended gasoline increased to an average of 72 mbpd for the third quarter and 67 mbpd in the first nine months of 2010 compared to 62 mbpd and 59 mbpd in the same periods of 2009. The future expansion or contraction of our ethanol blending program will be driven by the economics of ethanol supply and government regulations.

Third quarter 2010 Speedway SuperAmerica LLC (“SSA”) same store gasoline sales volume increased 6 percent when compared to the third quarter of 2009, while same store merchandise sales increased by 3 percent for the same period. During the first quarter of 2010, Speedway was ranked the nation’s top retail gasoline brand for the second consecutive year, according to the 2010 EquiTrend® Brand Study conducted by Harris Interactive®.

As of September 30, 2010, the heavy oil upgrading and expansion project at our Detroit, Michigan, refinery was approximately 47 percent complete and on schedule for an expected completion in the second half of 2012.

In October 2010, we entered into definitive agreements to sell our St. Paul Park, Minnesota, refinery (including associated terminal, tankage and pipeline investments) and 166 Speedway SuperAmerica retail outlets, plus related inventories. The fair value of the consideration is estimated to be approximately $900 million, which includes the estimated value of inventory and the fair values of (1) a retained preferred stock interest in the buyer with a stated value of $80 million, (2) a maximum $125 million earnout provision payable to us over eight years, and (3) a maximum $60 million of margin support payable to the buyer over two years. Cash proceeds at closing are estimated to be $700 million. The earnout and margin support provisions in the agreements are subject to certain conditions and any margin support paid may be recovered by an increase in the total earnout amount. We expect the sale transaction to close by yearend 2010, contingent upon the buyer meeting the conditions of their financing arrangements and other customary closing conditions.

The above discussion includes forward-looking statements with respect to the Detroit refinery project and the sale of the Minnesota assets. Factors that could affect the Detroit refinery project include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals, and other risks customarily associated with construction projects. Some factors that could potentially affect the sale of Minnesota assets include buyer financing and customary closing conditions, including government and regulatory approvals. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

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, but both West Texas Intermediate crude oil and Dated Brent crude oil monthly average prices have been in the $75 to $85 per barrel range during 2010. The following table lists benchmark crude oil and natural gas price averages in the third quarter and first nine months of 2010, when compared to the same periods in 2009.

	Three Months Ended September 30,				Nine Months Ended September 30,
Benchmark	2010		2009		2010		2009
West Texas Intermediate ("WTI")
crude oil (Dollars per barrel)	$	76.21	$	68.24	$	77.69	$	57.32
Dated Brent crude oil (Dollars per barrel)	$	76.86	$	68.08	$	77.14	$	57.32
Henry Hub natural gas (Dollars per mmbtu) (a)	$	4.38	$	3.39	$	4.59	$	3.93

(a)	First-of-month price index per million British thermal units.

Our domestic crude oil production is 60 to 70 percent sour, which means that it contains more sulfur than light sweet WTI does. Sour crude oil also tends to be heavier than and sells at a discount to light sweet crude oil because of its higher refining costs and lower refined product values. Our international crude oil production is relatively sweet and is generally sold in relation to the Dated Brent crude oil benchmark.

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. Our other major natural gas-producing region is Equatorial Guinea, where large portions of our natural gas sales is subject to term contracts, making realized prices in this area less volatile. As we sell larger quantities of natural gas from these regions, since these fixed prices are generally lower than prevailing prices, our reported average natural gas prices realizations may not 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. Output mix can be impacted by operational problems or planned unit outages at the mine or upgrader. See Note 12 for the commodity derivatives contracts related to 2010 forecasted sales.

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

The table below shows benchmark prices that impacted both our revenues and variable costs for the third quarter and first nine months of 2010 and 2009:

	Three Months Ended September 30,				Nine Months Ended September 30,
Benchmark	2010		2009		2010		2009
WTI crude oil (Dollars per barrel)	$	76.21	$	68.24	$	77.69	$	57.32
Western Canadian Select (Dollars per barrel) (a)	$	60.55	$	58.12	$	64.72	$	48.15
AECO natural gas sales
index (Canadian dollars per gigajoule) (b)		3.36		2.78		3.93		3.59

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

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

Integrated Gas

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

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

We own a 45 percent interest in a methanol plant located in Equatorial Guinea through our investment in Atlantic Methanol Production Company LLC (“AMPCO”). Methanol demand has a direct impact on AMPCO’s earnings. Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices. AMPCO’s plant capacity is 1.1 million tonnes, or 3 percent of estimated 2009 world demand.

Refining, Marketing and Transportation

RM&T segment income depends largely on our refining and wholesale marketing gross margin, refinery throughputs and retail marketing gross margins for gasoline, distillates and merchandise.

Our refining and wholesale marketing gross margin is the difference between the prices of refined products sold and the costs of crude oil and other charge and blendstocks refined, including the costs to transport these inputs to our refineries, the costs of purchased products and manufacturing expenses, including depreciation. The crack spread is a measure of the difference between market prices for refined products and crude oil, commonly used by the industry as a proxy for the refining margin. Crack spreads can fluctuate significantly, particularly when prices of refined products do not move in the same relationship as the cost of crude oil. As a performance benchmark and a comparison with other industry participants, we calculate Midwest (Chicago) and U.S. Gulf Coast crack spreads that we feel most closely track our operations and slate of products. Light Louisiana Sweet (“LLS”) prices and a 6-3-2-1 ratio of products (6 barrels of crude oil refined into 3 barrels of gasoline, 2 barrels of distillate and 1 barrel of residual fuel) are used for the crack spread calculation.

Our refineries can process significant amounts of sour crude oil which typically can be purchased at a discount to sweet crude oil. The amount of this discount, the sweet/sour differential, can vary significantly causing our refining and wholesale marketing gross margin to differ from the crack spreads which are based upon sweet crude. In general, a larger sweet/sour differential will enhance our refining and wholesale marketing gross margin.

In addition to the market changes indicated by the crack spreads and sweet/sour differential, our refining and wholesale marketing gross margin is impacted by factors such as:

·	the types of crude oil and other charge and blendstocks processed,

·	the selling prices realized for refined products,

·	the impact of commodity derivative instruments used to manage price risk,

·	the cost of products purchased for resale, and

·	changes in manufacturing costs, which include depreciation, energy used by our refineries and the level of maintenance costs.

The following table lists calculated average crack spreads for the Midwest and Gulf Coast markets and the sweet/sour differential for the third quarter and first nine months of 2010 and 2009:

	Three Months Ended September 30,				Nine Months Ended September 30,
(Dollars per barrel)	2010		2009		2010		2009
Chicago LLS 6-3-2-1 crack spread	$	3.68	$	3.93	$	3.40	$	4.20
U.S. Gulf Coast LLS 6-3-2-1 crack spread	$	1.70	$	2.50	$	2.49	$	2.99
Sweet/Sour differential (a)	$	8.08	$	5.64	$	7.39	$	5.62

(a)	Calculated using the following mix of crude types: 15% Arab Light, 20% Kuwait, 10% Maya, 15% Western Canadian Select and 40% Mars compared to LLS.

Even though the LLS 6-3-2-1 crack spread was lower in the third quarter of 2010 compared to the same period of 2009, our realized margin for the period improved from processing sour crude, due to the widening of the sweet/sour differential. The benchmark sweet/sour differential widened 43 percent in the third quarter and 31 percent in the first nine months of 2010 relative to the same periods of last year. Due to the Garyville refinery expansion we were able to process a higher volume of sour crude oil during the third quarter and the first nine months of 2010. Within our refining system, sour crude accounted for 51 percent of the 1,263 mbpd of crude oil processed in the third quarter of 2010 and 53 percent of the 1,166 mbpd of crude oil processed in the first nine months of 2010 compared to 49 percent of the 1,019 mbpd of crude processed in the third quarter and 52 percent of the 943 mbpd of crude processed in the first nine months in 2009.

Our retail marketing gross margin for gasoline and distillates, which is the difference between the ultimate price paid by consumers and the cost of refined products, including secondary transportation and consumer excise taxes, also impacts RM&T segment profitability. There are numerous factors including local competition, seasonal demand fluctuations, the available wholesale supply, the level of economic activity in our marketing areas and weather conditions that impact gasoline and distillate demand throughout the year. The gross margin on merchandise sold at retail outlets has been historically less volatile.

Results of Operations

Consolidated Results of Operation

Consolidated net income for 2010 was 69 percent higher in third quarter and 68 percent higher in the first nine months than in the same periods of 2009. Higher liquid hydrocarbon realizations and sales volumes in the third quarter of 2010 compared to the same period of 2009 increased E&P segment income, while RM&T segment income was increased as a result of improved refining and marketing gross margins combined with higher increased throughput. The income increase in the first nine months of 2010 was primarily related to higher liquid hydrocarbon realizations.

Revenues are summarized by segment in the following table:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2010			2009			2010			2009
E&P	$	2,532		$	1,979		$	7,683		$	5,386
OSM		190			167			534			444
IG		38			15			98			33
RM&T		15,897			12,407			45,054			32,148

Segment revenues		18,657			14,568			53,369			38,011
Elimination of intersegment revenues		(214	)		(193	)		(608	)		(506	)
Gain (Loss) on U.K. natural gas contracts		-			(13	)		-			72
Total revenues	$	18,443		$	14,362		$	52,761		$	37,577

Items included in both revenues and costs:
Consumer excise taxes on petroleum products
and merchandise	$	1,351		$	1,258		$	3,871		$	3,658

E&P segment revenues increased $553 million in the third quarter and $2,297 million in the first nine months of 2010 from the comparable prior-year periods. The increases were primarily a result of higher liquid hydrocarbon and natural gas price realizations. Liquid hydrocarbon realizations averaged $72.95 per barrel in the third quarter and

$73.64 in the first nine months of 2010 compared to $64.12 and $53.62 in the same periods of 2009, while natural gas realizations averaged $2.69 per mcf in the third quarter and $2.86 in the first nine months of 2010 compared to $2.20 and $2.42 in the same periods of 2009.

Revenues in both 2010 periods include the impact of derivative instruments intended to mitigate price risk on future sales of liquid hydrocarbons and natural gas. A net pretax gain of $13 million was reported by the E&P segment in the third quarter of 2010, while there was a net pretax gain of $91 million in the first nine months of 2010.

For the third quarter and the first nine months of 2009, losses of $13 million and gains of $72 million related to natural gas sales contracts in the U.K. that were accounted for as derivative instruments were excluded for E&P segment revenues. Those contracts expired in the third quarter of 2009.

Net sales volumes from continuing operations during the quarter were 399 mboepd in 2010 and 366 mboepd in 2009. Net sales volumes for the first nine months of 2010 were 3 percent lower than the comparable prior-year period, primarily impacted by the sale of a portion of our Permian Basin assets in the second quarter of 2009, the planned turnaround in Equatorial Guinea during the first four months of 2010, maintenance downtime offshore U.K., and normal production declines. This decrease in sales volumes partially offsets the impact of the liquid hydrocarbon and natural gas realization increases previously discussed.

The following tables report E&P segment realizations and sales volumes in greater detail for all periods.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009

E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbpd)
United States		80		63		65		64

Europe		80		76		92		87
Africa		89		83		84		87
Total International		169		159		176		174
Worldwide Continuing Operations		249		222		241		238
Discontinued Operations (a)		-		10		-		6
Worldwide		249		232		241		244

Natural Gas Sales (mmcfd)
United States		363		339		350		376

Europe (b)		99		119		104		143
Africa		442		409		399		427
Total International		541		528		503		570
Worldwide Continuing Operations		904		867		853		946
Discontinued Operations (a)		-		-		-		22
Worldwide		904		867		853		968

Total Worldwide Sales (mboepd)
Continuing Operations		399		366		382		396
Discontinued Operations (a)		-		10		-		9
Worldwide		399		376		382		405

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009

E&P Operating Statistics
Average Realizations (c)
Liquid Hydrocarbons (per bbl)
United States	$	69.52	$	61.07	$	69.95	$	50.19

Europe		80.49		70.58		79.69		60.10
Africa		69.24		60.50		69.85		49.67
Total International		74.57		65.32		75.00		54.88
Worldwide Continuing Operations		72.95		64.12		73.64		53.62
Discontinued Operations		-		67.77		-		56.27
Worldwide	$	72.95	$	64.27	$	73.64	$	53.68

Natural Gas (per mcf)
United States	$	4.43	$	3.63	$	4.78	$	3.94

Europe		7.20		4.87		6.42		4.89
Africa		0.25		0.25		0.25		0.25
Total International		1.52		1.29		1.52		1.41
Worldwide Continuing Operations		2.69		2.20		2.86		2.42
Discontinued Operations		-		-		-		8.54
Worldwide	$	2.69	$	2.20	$	2.86	$	2.56

(a)	Our businesses in Ireland and Gabon were sold in 2009. The 2009 values have been recast to reflect these businesses as discontinued operations.

(b)	Includes natural gas acquired for injection and subsequent resale of 15 mmcfd and 18 mmcfd for the third quarters of 2010 and 2009, and 19 mmcfd and 20 mmcfd for the first nine months of 2010 and 2009.

(c)	Excludes gains and losses on derivative instruments and the unrealized effects of U.K. natural gas contracts that were accounted for as derivatives in 2009.

OSM segment revenues increased $23 million in the third quarter and $90 million in the first nine months of 2010 compared to the same periods of 2009. Revenues in both periods include the impact of derivative instruments intended to mitigate price risk relative to future sales of synthetic crude. Derivative losses of $8 million and gains of $34 million were included in segment revenues for the third quarter and first nine months of 2010, while gains of $3 million and $10 million were included in segment revenues for the same periods of 2009.

Excluding the derivative effects, segment revenues increased in both periods of 2010, primarily due to higher synthetic crude realizations. Net synthetic crude sales for the third quarter of 2010 were 31 mbpd at an average realized price of $67.83 per barrel compared to 33 mbpd at $62.08 in the same period last year. For the nine-month period net synthetic crude sales were 25 mbpd at $69.07 in 2010 compared to 31 mbpd at $52.02 in 2009.

See Note 12 to the consolidated financial statements for additional information about derivative instruments.

RM&T segment revenues increased $3,490 million in the third quarter of 2010 and $12,906 million in the first nine months of 2010 from the comparable periods of 2009. Our refined product and liquid hydrocarbon selling prices were higher and accounted for 39 percent of the third quarter and 66 percent of the first nine months of 2010 revenue increase. Benchmark refined product price changes are illustrated in the following table. Refined product sales volumes increased 20 percent in the third quarter and 15 percent in the first nine months of 2010, primarily related to higher production from our expanded Garyville refinery.

	Three Months Ended September 30,				Nine Months Ended September 30,
(Dollars per gallon)	2010		2009		2010		2009
Chicago Spot Unleaded regular gasoline	$	2.02	$	1.84	$	2.05	$	1.61
Chicago Spot Ultra-low sulfur diesel		2.12		1.80		2.11		1.56
USGC Spot Unleaded regular gasoline		1.95		1.77		2.02		1.55
USGC Spot Ultra-low sulfur diesel	$	2.09	$	1.79	$	2.10	$	1.57

Income from equity method investments increased $20 million in the third quarter of 2010 and $117 million in the first nine months of 2010 from the comparable prior-year periods. Higher commodity prices in 2010 compared to 2009 positively impacted the earnings of many of our equity method investees. In the third quarter of 2010, we fully impaired our Integrated Gas segment’s equity method investment in an entity engaged in gas-to-fuels related technology, see Note 11.

Net gain on disposal of assets in the first nine months of 2010 primarily represents the sale of a 20 percent outside-operated undivided interest in our Production Sharing and Joint Operating Agreement in Block 32 offshore Angola. During the first quarter of 2010, we recorded a gain of $811 million on the sale. The net gain on disposal of assets in the first nine months of 2009 primarily represents the sale of a portion of our operated and all of our outside-operated Permian Basin producing assets in New Mexico and west Texas.

Cost of revenues increased $3,328 million and $13,384 million in the third quarter and first nine months of 2010 from the comparable periods of 2009. In both periods, the increase was primarily the result of higher acquisition prices for crude oil, charge and blendstocks and purchased refined products in the RM&T segment. Increased volumes of purchased crude oil also contributed to the increased costs.

Depreciation, depletion and amortization (“DD&A”) increased in the third quarter and first nine months of 2010 from the comparable prior-year periods. The DD&A increase for the quarter was related to the higher sales volumes at a higher rate of DD&A per barrel on our domestic E&P assets and the Garyville expansion being put into service at the end of 2009. Current quarter DD&A for our domestic E&P assets increased $72 million from the same quarter of last year, primarily as a result of new production from Droshky, which began mid-July and ratably increased to peak production in September of 45,000 boepd. For the nine-month period, the increase primarily related to Garyville.

Long-lived asset impairments in the first nine months of 2010 include a $28 million impairment of our maleic anhydride plant and a $423 million impairment of our Powder River Basin field. See Note 11 for information about these impairments.

Exploration expenses were $59 million in the third quarter of 2010, with no expenses related to dry wells and $282 million and first nine months of 2010, including expenses related to dry wells of $89 million. The majority of dry well costs in 2010 relate to the partial writeoff of the previously discussed offshore Gulf of Mexico well on the Flying Dutchman prospect. Exploration expenses were $55 million and $181 million in the third quarter and first nine months of 2009, including expenses related to dry wells of $10 million and $22 million.

Provision for income taxes increased $193 million and $499 million in the third quarter and first nine months of 2010 from the comparable periods of 2009 primarily due to the increase in pretax income. The effective tax rate is influenced by a variety of factors including the geographical and functional sources of income, the relative magnitude of

these sources of income, and foreign currency remeasurement effects. The effective income tax rate decreased primarily due to these factors, partially offset by an increase from legislation changes, see Note 8.

The following is an analysis of the effective income tax rates for the first nine months of 2010 and 2009:

	Nine Months Ended September 30,
	2010			2009
Statutory U.S. income tax rate		35	%		35	%
Effects of foreign operations, including foreign tax credits		17			25
State and local income taxes, net of federal income tax effects		-			1
Legislation change		1			-
Other		(1	)		-
Effective income tax rate		52	%		61	%

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.

Discontinued operations reflect the 2009 disposal of our E&P businesses in Ireland and Gabon (see Note 5) and the historical results of those operations, net of tax, for all periods presented.

Segment Results

Segment income (loss) is summarized in the following table:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2010			2009			2010			2009
E&P
United States	$	99		$	32		$	233		$	(61	)
International		411			459			1,211			843
E&P segment		510			491			1,444			782

OSM		18			25			(59	)		3
IG		41			13			109			53
RM&T		285			158			469			482

Segment income		854			687			1,963			1,320
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(106	)		(159	)		(178	)		(299	)
Foreign currency remeasurement of income taxes		(37	)		(114	)		33			(180	)
Gain (loss) on dispositions		-			(15	)		449			107
Impairments		(15	)		-			(303	)		-
Loss on early extinguishment of debt		-			-			(57	)		-
Deferred income taxes - tax legislation changes		-			-			(45	)		-
Gain on U.K. natural gas contracts		-			(7	)		-			37
Discontinued operations		-			21			-			123
Net income	$	696		$	413		$	1,862		$	1,108

United States E&P income increased $67 million and $294 million in the third quarter and first nine months of 2010 compared to the same periods of 2009. The income increase in the third quarter of 2010 was primarily the result of higher liquid hydrocarbon and natural gas realization, and sales volume increases, as previously discussed, offset by increased DD&A. For the nine-month period, the income increase was primarily the result of higher liquid hydrocarbon realizations and derivative gains, partially offset by increased exploration expenses.

International E&P income decreased $48 million in the third quarter of 2010 and increased $368 million in the first nine months of 2010 compared to the same periods of 2009. The income decrease in the third quarter was primarily due to income taxes. During the third quarter of 2009, we began to credit certain foreign taxes that were previously

deducted resulting in a lower effective tax rate in the prior year. The income increase in the first nine months was primarily due to revenue increases as previously discussed. Liquid hydrocarbon realizations increased 14 percent and 37 percent for the third quarter and first nine months of 2010 compared to the same periods of 2009.

OSM segment income decreased $7 million and $62 million in the third quarter and first nine months of 2010. The decline in third quarter income was primarily due to an after-tax derivative loss of $6 million. The decreased income in the first nine months was primarily due to lower sales volumes and higher incremental cost both primarily resulting from the previously discussed turnaround. An after-tax derivative gain of $26 million and synthetic crude realization improvements of 33 percent partially offset the impact of the turnaround on segment income.

IG segment incom e increased $28 million and $56 million in the third quarter of 2010 and first nine months of 2010 compared to the same periods of 2009. The increase was primarily the result of higher price realizations in both periods of 2010 compared to 2009.

RM&T segment income increased by $127 million in the third quarter but decreased $13 million in first nine months of 2010 compared to the same periods of 2009. The increase for the quarter was primarily due to a higher refining and wholesale marketing gross margin, which averaged 9.21 cents per gallon in the third quarter of 2010 compared to 7.62 cents per gallon in the same quarter of 2009. A wider sweet/sour crude differential coupled with an increase in sour crude throughput contributed to the increase in segment income. These favorable impacts were partially offset by increased manufacturing expenses in the third quarter 2010 compared to the third quarter 2009 due to a combination of increased depreciation and energy expense associated with the additional Garyville refinery units.

The decrease in segment income in the nine month period was primarily due to a lower refining and wholesale marketing gross margin, which averaged 6.36 cents per gallon in the first nine months of 2010 compared to 8.08 cents per gallon in the comparable period of 2009. Higher sales volumes resulting from the Garyville expansion helped to mitigate the effects of the lower gross margin per gallon. Also impacting the gross margin were higher manufacturing costs relating to a pretax increase of approximately $170 million in refining system turnaround and maintenance costs plus higher depreciation and energy expenses related to the Garyville expansion units.

Our refining and wholesale marketing gross margin also included pretax derivative losses of $20 million and gains of $30 million in the third quarter and first nine months of 2010 compared to losses of $17 million and $64 million in the third quarter and first nine months of 2009.

Management’s Discussion and Analysis of Cash Flows and Liquidity

Cash Flows

Net cash provided by operating activities totaled $2,988 million in the first nine months of 2010, compared to $3,309 million in the first nine months of 2009.

Net cash used in investing activities totaled $2,256 million in the first nine months of 2010, compared to $4,166 million in the first nine months of 2009. In the first quarter of 2010, we closed the sale of our 20 percent outside-operated undivided interest in the Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola. The related cash inflow was $1.3 billion.

In our E&P segment, exploration and development projects in 2010 are offshore in the Gulf of Mexico, on our Angola development, Norway developments, and U.S. unconventional resource plays. With the completion of our Garyville refinery expansion at the end of 2009, we have reduced spending in our RM&T segment while keeping the expansion and upgrading of our Detroit, Michigan, refinery on track. The AOSP Expansion 1 in our OSM segment continues into 2010, with the spending rate relatively unchanged from 2009 levels.

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

Net cash used in financing activities was $1,146 million in the first nine months of 2010, compared to net cash provided of $926 million in the first nine months of 2009. Significant uses of cash in the first nine months of 2010 included the repayment of $500 million aggregate principal value of debt at a weighted average price of 117 percent of face value under two tender offers in the second quarter of 2010 and dividends. Sources of cash in the first nine months of 2009 included the issuance of $1.5 billion in senior notes, with the only significant use of cash being dividends.

Liquidity and Capital Resources

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations and our $3 billion committed revolving credit facility. Because of the alternatives available to us, including internally generated cash flow 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, share repurchase program, dividend payments, defined benefit plan contributions, repayment of debt maturities and other amounts that may ultimately be paid in connection with contingencies.

Capital Resources

During the third quarter of 2010, we filed a universal shelf registration statement with the Securities and Exchange Commission, under which we, as a well-known seasoned issuer, have the ability to issue and sell 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 September 30, 2010, compared to 23 percent at December 31, 2009. This includes $235 million of debt that is serviced by United States Steel Corporation (“United States Steel”).

	September 30,			December 31,
(In millions)	2010			2009
Long-term debt due within one year	$	98		$	96
Long-term debt		7,844			8,436

Total debt	$	7,942		$	8,532

Cash	$	1,643		$	2,057
Equity	$	23,356		$	21,910

Calculation:

Total debt	$	7,942		$	8,532
Minus cash		1,643			2,057

Total debt minus cash	$	6,299		$	6,475

Total debt		7,942			8,532
Plus equity		23,356			21,910
Minus cash		1,643			2,057

Total debt plus equity minus cash	$	29,655		$	28,385

Cash-adjusted debt-to-capital ratio		21	%		23	%

Capital Requirements

On October 27, 2010, our Board of Directors approved a 25 cents per share dividend, payable December 10, 2010 to stockholders of record at the close of business on November 17, 2010. In April 2010, the dividend was increased from 24 cents per share to 25 cents per share, a 4 percent increase in our quarterly dividend.

Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion. As of September 30, 2010, we had repurchased 66 million common shares at a cost of $2,922 million. We have not made any purchases under the program since August 2008. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program’s authorization does not include specific price targets or timetables. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and market conditions.

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 forward-looking statements about our common stock repurchase program are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially are changes in prices of and demand for crude oil, natural gas

and refined products, actions of competitors, disruptions or interruptions of our production, refining 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 obligations to make future payments under existing contracts as of September 30, 2010:

						2011-		2013-	Later
(In millions)	Total		2010			2012		2014	Years
Long-term debt (excludes interest) (a)	$	7,573	$	34	$	1,553	$	984	$	5,002
Sale-leaseback financing (a)		23		1		22		-		-
Capital lease obligations (a)		641		6		81		88		466
Operating lease obligations (a)		1,022		39		306		276		401
Operating lease obligations under sublease (a)		12		-		12		-		-
Purchase obligations:
Crude oil, feedstock, refined product		10,937		8,959		1,363		445		170
and ethanol contracts
Transportation and related contracts		2,002		120		503		265		1,114
Contracts to acquire property, plant and		2,843		782		1,440		575		46
equipment
LNG terminal operating costs (b)		133		3		25		25		79
Service and materials contracts (c)		1,944		131		507		352		953
Unconditional purchase obligations (d)		47		8		16		16		8
Commitments for oil and gas exploration		23		12		5		1		6
(non-capital) (e)
Total purchase obligations		17,929		10,015		3,859		1,679		2,376
Other long-term liabilities reported
in the consolidated balance sheet (f)		2,300		82		643		560		1,015
Total contractual cash obligations (g)	$	29,500	$	10,177	$	6,476	$	3,587	$	9,260

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

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

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

(d)	We are a part to a long-term transportation services agreement with Alliance Pipeline. This agreement was used by Alliance Pipeline to secure its financing.

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

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

(g)	This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties.

Receivable from United States Steel

We remain obligated (primarily or contingently) for $249 million of certain debt and other financial arrangements for which United States Steel has assumed responsibility for repayment (see the USX Separation in Item 1. of our 2009 Annual Report on 10-K). United States Steel reported in its Form 10-Q for the three months ended September 30, 2010 that it believes that its liquidity will be adequate to satisfy its obligations for the foreseeable future.

Environmental Matters

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

We have finalized our strategic approach to comply with Mobile Source Air Toxics II (“MSAT II”) regulations relating to benzene content in refined products and updated the project cost estimates to comply with these requirements. We now estimate that we may spend approximately $650 million over a four-year period that began in 2008, reduced from our previous projection of approximately $1 billion over a six-year period. The overall cost reduction for MSAT II compliance is a result of lower costs for several projects along with our finalization of the most appropriate MSAT II compliance approach for our refineries. Our actual MSAT II expenditures since inception have totaled $462 million through September 30, 2010, with $61 million in the third quarter of 2010. We expect total year 2010 spending will be approximately $275 million. The cost estimates are forward-looking statements and are subject to change as further work is completed in 2010.

In October 2010, the Environmental Protection Agency (“EPA”) issued a partial waiver decision under the Clean Air Act to allow for an increase in the amount of ethanol permitted to be blended into gasoline from 10 percent (E10) to 15 percent (E15) for 2007 and newer light-duty motor vehicles. There are numerous state and federal regulatory issues that would need to be addressed before E15 can be marketed for use in any traditional gasoline engines.

There have been no other significant changes to our environmental matters subsequent to December 31, 2009.

Other Contingencies

We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to us. However, we believe that we will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably to us. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.

Critical Accounting Estimates

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

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

There have been no changes to our critical accounting estimates subsequent to December 31, 2009.

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 2009 Annual Report on Form 10-K.

In October 2010, we initiated a crack spread derivative strategy related to a portion of our St. Paul Park refinery's projected production. This strategy is designed to mitigate potential commodity price fluctuation risks, and is associated with the expected sale by yearend of the St. Paul Park refinery and its related assets. Upon closing of the sale, derivative instruments executed pursuant to this strategy, along with all corresponding rights and obligations, will transfer to the buyer. As of October 31, 2010, we held derivative instruments covering 22 million barrels under this strategy. See Note 5 to the consolidated financial statements for further discussion of the pending sale.

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 Note 11 and 12 to the consolidated financial statements.

Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent increases and decreases in commodity prices on our open commodity derivative instruments as of September 30, 2010 is provided in the following table.


	Incremental Change in IFO from a Hypothetical Price Increase of						Incremental Change in IFO from a Hypothetical Price Decrease of
(In millions)		10	%		25	%		10	%		25	%
E&P Segment
Natural gas	$	(5	)	$	(12	)	$	5		$	12
OSM Segment
Crude oil	$	(19	)	$	(47	)	$	19		$	47
RM&T Segment
Crude oil	$	(108	)	$	(236	)	$	117		$	302
Natural gas		1			3			(1	)		(3	)
Refined products		(8	)		(20	)		8			20

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 September 30, 2010, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(In millions)	2010			2009			2010			2009

Segment Income (Loss)
Exploration and Production
United States	$	99		$	32		$	233		$	(61	)
International		411			459			1,211			843
E&P segment		510			491			1,444			782
Oil Sands Mining		18			25			(59	)		3
Integrated Gas		41			13			109			53
Refining, Marketing and Transportation		285			158			469			482
Segment income		854			687			1,963			1,320

Items not allocated to segments, net of income taxes		(158	)		(274	)		(101	)		(212	)
Net income	$	696		$	413		$	1,862		$	1,108
Capital Expenditures (a)
Exploration and Production
United States	$	352		$	403		$	1,222		$	1,018
International		234			113			552			472
E&P segment		586			516			1,774			1,490
Oil Sands Mining		191			267			699			834
Integrated Gas		1			-			2			1
Refining, Marketing and Transportation		273			634			839			2,007
Discontinued Operations (b)		-			3			-			66
Corporate		13			10			27			18
Total	$	1,064		$	1,430		$	3,341		$	4,416
Exploration Expenses
United States	$	34		$	23		$	192		$	88
International		25			32			90			93
Total	$	59		$	55		$	282		$	181

(a)	Capital expenditures include changes in accruals.

(b)	Our oil and gas businesses in Ireland (natural gas) and Gabon (liquid hydrocarbons) are treated as discontinued operations in 2009.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009

E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbpd)
United States		80		63		65		64

Europe		80		76		92		87
Africa		89		83		84		87
Total International		169		159		176		174
Worldwide Continuing Operations		249		222		241		238
Discontinued Operations		-		10		-		6
Worldwide		249		232		241		244
Net Natural Gas Sales (mmcfd)
United States		363		339		350		376

Europe (c)		99		119		104		143
Africa		442		409		399		427
Total International		541		528		503		570
Worldwide Continuing Operations		904		867		853		946
Discontinued Operations		-		-		-		22
Worldwide		904		867		853		968
Total Worldwide Sales (mboepd)
Continuing operations		399		366		382		396
Discontinued operations		-		10		-		9
Worldwide		399		376		382		405

Average Realizations (d)
Liquid Hydrocarbons (per bbl)
United States	$	69.52	$	61.07	$	69.95	$	50.19

Europe		80.49		70.58		79.69		60.10
Africa		69.24		60.50		69.85		49.67
Total International		74.57		65.32		75.00		54.88
Worldwide Continuing Operations		72.95		64.12		73.64		53.62
Discontinued Operations		-		67.77		-		56.27
Worldwide	$	72.95	$	64.27	$	73.64	$	53.68

Natural Gas (per mcf)
United States	$	4.43	$	3.63	$	4.78	$	3.94

Europe		7.20		4.87		6.42		4.89
Africa (e)		0.25		0.25		0.25		0.25
Total International		1.52		1.29		1.52		1.41
Worldwide Continuing Operations		2.69		2.20		2.86		2.42
Discontinued Operations		-		-		-		8.54
Worldwide	$	2.69	$	2.20	$	2.86	$	2.56

(c)	Includes natural gas acquired for injection and subsequent resale of 15 mmcfd and 18 mmcfd for the third quarters of 2010 and 2009, and 19 mmcfd and 20 mmcfd for the first nine months of 2010 and 2009.

(d)	Excludes gains and losses on derivative instruments, including the unrealized effects of U.K. natural gas contracts that were accounted for as derivatives and expired in September 2009.

(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.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions, except as noted)	2010		2009		2010		2009

OSM Operating Statistics
Net Synthetic Crude Sales (mbpd) (f)		31		33		25		31
Synthetic Crude Average Realization (per bbl) (g)	$	67.83	$	62.08	$	69.07	$	52.02

IG Operating Statistics
Net Sales (mtpd) (h)
LNG		7,142		6,372		6,502		6,583
Methanol		1,069		1,145		1,120		1,220
RM&T Operating Statistics
Refinery Runs (mbpd)
Crude oil refined		1,263		1,019		1,166		943
Other charge and blend stocks		182		171		148		197
Total		1,445		1,190		1,314		1,140
Refined Product Yields (mbpd)
Gasoline		785		687		706		655
Distillates		439		330		392		319
Propane		27		23		24		23
Feedstocks and special products		113		75		108		66
Heavy fuel oil		28		22		24		23
Asphalt		80		70		79		70
Total		1,472		1,207		1,333		1,156

Refined Products Sales Volumes (mbpd) (i)		1,681		1,400		1,550		1,353
Refining and Wholesale Marketing Gross
Margin (per gallon) (j)	$	0.0921	$	0.0762	$	0.0636	$	0.0808
Speedway SuperAmerica
Retail outlets		1,594		1,610		-		-
Gasoline and distillate sales (millions of gallons)		869		818		2,500		2,408
Gasoline and distillate gross margin (per gallon)	$	0.1549	$	0.1399	$	0.1363	$	0.1175
Merchandise sales	$	867	$	842	$	2,430	$	2,341
Merchandise gross margin	$	215	$	207	$	600	$	577

(f)	Includes blendstocks.

(g)	Excludes gains and losses on derivative instruments.

(h)	Includes both consolidated sales volumes and our share of the sales volumes of equity method investees. LNG sales from Alaska are conducted through a consolidated subsidiary. LNG and methanol sales from Equatorial Guinea are conducted through equity method investees.

(i)	Total average daily volumes of all refined product sales to wholesale, branded and retail (SSA) customers.

(j)	Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation.

Part II – OTHER INFORMATION

Item 1. Legal Proceedings

We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Certain of these matters are included below. The ultimate resolution of these contingencies could, individually or in the aggregate, be material. However, we believe that we will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably.

MTBE Litigation

We are a defendant, along with other refining companies, in six cases arising in five states alleging damages for MTBE contamination. We do not expect these cases to significantly impact our consolidated results of operations, financial positions, or cash flows. We expect additional lawsuits alleging such damages against us in the future, but likewise do not expect them to significantly impact our consolidated results of operations, financial positions, or cash flows.

Natural Gas Royalty Litigation

We have settled a qui tam case which alleged that Marathon and other defendants violated the False Claims Act with respect to the reporting and payment of royalties on natural gas and natural gas liquids for federal and Indian leases. A qui tam action is an action in which the Relator files suit on behalf of himself as well as the federal government. The case was U.S. ex rel Harrold E. Wright v. Agip Petroleum Co. et al. It was primarily a gas valuation case. We finalized and funded the settlement with all parties who include the Relator, the Department of Justice and the Indian Tribes. Such settlement did not significantly impact our consolidated results of operations, financial position or cash flows.

Environmental Proceedings

During 2001, we entered into a New Source Review consent decree and settlement of alleged Clean Air Act (“CAA”) and other violations with the U.S. EPA covering all of our refineries. The settlement committed us to specific control technologies and implementation schedules for environmental expenditures and improvements to our refineries over approximately an eight-year period, which are now substantially complete. As part of this consent decree, we were required to conduct evaluations of refinery benzene waste air pollution programs (benzene waste “NESHAPS”). Pursuant to a modification to our New Source Review consent decree, we have agreed with the U.S. Department of Justice and U.S. EPA to pay a civil penalty of $408,000 and conduct supplemental environmental projects of approximately $1 million, as part of a settlement of an enforcement action for alleged CAA violations relating to benzene waste NESHAPS. A modification to our New Source Review consent decree was finalized June 30, 2010 and the civil penalty amount has been paid.

The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order to Marathon Pipe Line LLC (“MPL”) related to the March 10, 2009 incident at St. James, Louisiana. PHMSA has proposed a civil penalty in the amount of approximately $1 million. On September 22, 2010, PHMSA granted MPL a 60-day extension in which to respond to the Notice of Probable Violation. Our response is due by November 26, 2010.

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 2009 Annual Report on Form 10-K. The following are updates to our risk factors.

Our offshore operations involve special risks that could negatively impact us.

Offshore exploration and development operations present technological challenges and operating risks because of the marine environment. Activities in deepwater areas may pose incrementally greater risks because of water depths that limit intervention capability and the physical distance to oilfield service infrastructure and service providers. Environmental remediation and other costs resulting from spills or releases may result in substantial liabilities and could materially and adversely affect our business, financial condition, results of operations, cash flow and market value of our securities.

Restrictions on U.S. Gulf of Mexico deepwater operations and similar action by countries where we do business could have a significant impact on our operations.

As a result of the Deepwater Horizon incident, the U.S. Department of the Interior issued a drilling moratorium to suspend outer continental shelf subsea and floating facility operations. Due to this drilling moratorium, we suspended drilling activity on one well in the Gulf of Mexico. While this moratorium was lifted on October 12, 2010, we cannot predict when necessary plans and permits will be approved for renewed offshore drilling activity. An extended regulatory delay on deepwater drilling activities in the Gulf of Mexico or changes in laws or regulations affecting our operations in these areas could have a material adverse effect on our business, financial condition, results of operations, cash flow and market value of our securities. In addition, other countries where we do business may make changes to their laws or regulations governing offshore operations, including deepwater areas that could have a similar material adverse effect.

We will continue to incur substantial capital expenditures and operating costs as a result of compliance with, and changes in environmental health, safety and security laws and regulations, and, as a result, our profitability could be materially reduced.

We believe it is likely that the scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations that could affect our operations. As an update to legislation and regulatory activity that impacts or could impact our operations:

The U.S. EPA issued a finding in 2009 that greenhouse gases contribute to air pollution that endangers public health and welfare. Related to this endangerment finding, in April of 2010, the EPA finalized a greenhouse gas emission standard for mobile sources (cars and light duty vehicles). The endangerment finding along with the mobile source standard and EPA’s determination that greenhouse gases are subject to regulation under the Clean Air Act, will lead to widespread regulation of stationary sources of greenhouse gas emissions. As a result, the EPA has issued a so-called tailoring rule to limit the applicability of the EPA’s major permitting programs to larger sources of greenhouse gas emissions, such as our refineries and a few large production facilities. Although legal challenges have been filed or are expected to be filed against these EPA actions, no court decisions are expected for about two years.

·	Congress may continue to consider legislation in 2010 on greenhouse gas emissions, which may include a cap and trade system for stationary sources and a carbon fee on transportation fuels.

Although there may be adverse financial impact (including compliance costs, potential permitting delays and potential reduced demand for crude oil or certain refined products) associated with any legislation, regulation or other action, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the fact that requirements have only recently been adopted and the present uncertainty regarding the additional measures and how they will be implemented.

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



	column (a)			column (b)		column (c)		column (d)
						Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (d)		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (d)


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

07/01/10 – 07/31/10		8,189		$	30.93		-	$	2,080,366,711
08/01/10 – 08/31/10		78,092		$	34.12		-	$	2,080,366,711
09/01/10– 09/30/10		50,710	(c)	$	32.30		-	$	2,080,366,711
Total		136,991		$	33.26		-

(a)	90,661 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.

(b)

46,330 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.

(c)

We announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion. As of September 30, 2010, 66 million split-adjusted common shares had been acquired at a cost of $2,922 million, which includes transaction fees and commissions that are not reported in the table above. No shares have been repurchased under this program since August 2008.

Item 6. Exhibits

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

Exhibit Number

Incorporated by Reference

Filed Herewith

Furnished Herewith

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

3.1

Amended and Restated By-Laws of Marathon Oil Corporation effective October 27, 2010

8-K

3.1

10/29/10

12.1

Computation of Ratio of Earnings to Fixed Charges

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

101.LAB

XBRL Taxonomy Extension Label Linkbase

101.DEF

XBRL Taxonomy Extension Definitions Linkbase

SIGNATURES

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

November 5, 2010	MARATHON OIL CORPORATION

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

TABLE OF CONTENTS

Part I - Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 6. Exhibits

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MRO 10-Q Quarter ended Sept. 30, 2010