Edgar Filing: MARATHON OIL CORP

form10q2009june30.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended June 30, 2009

[ ]	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

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 No

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

Large accelerated filer 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 No X

There were 707,726,372 shares of Marathon Oil Corporation common stock outstanding as of July 31, 2009.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended June 30, 2009

		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
	Notes to Consolidated Financial Statements (Unaudited)		5
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		37
Item 4.	Controls and Procedures		37
	Supplemental Statistics		38
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		41
Item 4.	Submission of Matters to a Vote of Security Holders		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).

Index

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions, except per share data)	2009			2008			2009			2008
Revenues and other income:

Sales and other operating revenues (including	$	13,059		$	21,203		$	23,213		$	38,404
consumer excise taxes)
Sales to related parties		21			686			41			1,228
Income from equity method investments		62			256			109			465
Net gain on disposal of assets		191			12			195			22
Other income		25			45			77			104

Total revenues and other income		13,358			22,202			23,635			40,223
Costs and expenses:
Cost of revenues (excludes items below)		9,776			17,985			17,133			32,400
Purchases from related parties		110			226			205			365
Consumer excise taxes		1,226			1,295			2,400			2,511
Depreciation, depletion and amortization		701			493			1,363			933
Selling, general and administrative expenses		321			361			612			659
Other taxes		97			127			199			250
Exploration expenses		64			130			126			259

Total costs and expenses		12,295			20,617			22,038			37,377

Income from operations		1,063			1,585			1,597			2,846

Net interest and other financing costs		(11	)		(11	)		(28	)		(4	)


Income from continuing operations before income taxes		1,052			1,574			1,569			2,842

Provision for income taxes		711			806			962			1,357

Income from continuing operations		341			768			607			1,485

Discontinued operations		72			6			88			20

Net income	$	413		$	774		$	695		$	1,505

Per Share Data

Basic:

Income from continuing operations	$	0.48		$	1.08		$	0.86		$	2.09
Discontinued operations	$	0.10		$	0.01		$	0.12		$	0.02
Net income per share	$	0.58		$	1.09		$	0.98		$	2.11

Diluted:

Income from continuing operations	$	0.48		$	1.07		$	0.86		$	2.07
Discontinued operations	$	0.10		$	0.01		$	0.12		$	0.03
Net income per share	$	0.58		$	1.08		$	0.98		$	2.10

Dividends paid	$	0.24		$	0.24		$	0.48		$	0.48

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

Index

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

	June 30,			December 31,
(In millions, except per share data)	2009			2008
Assets
Current assets:
Cash and cash equivalents	$	1,496		$	1,285
Receivables, less allowance for doubtful accounts of $9 and $6		3,857			3,094
Receivables from United States Steel		24			23
Receivables from related parties		48			33
Inventories		3,498			3,507
Other current assets		191			461

Total current assets		9,114			8,403

Equity method investments		2,035			2,080
Receivables from United States Steel		457			469
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $16,394 and $15,581		30,452			29,414
Goodwill		1,423			1,447
Other noncurrent assets		960			873

Total assets	$	44,441		$	42,686
Liabilities
Current liabilities:
Accounts payable		5,513			4,712
Payables to related parties		29			21
Payroll and benefits payable		310			400
Accrued taxes		499			1,133
Deferred income taxes		615			561
Other current liabilities		704			828
Long-term debt due within one year		103			98

Total current liabilities		7,773			7,753

Long-term debt		8,518			7,087
Deferred income taxes		3,312			3,330
Defined benefit postretirement plan obligations		1,636			1,609
Asset retirement obligations		982			963
Payable to United States Steel		4			4
Deferred credits and other liabilities		403			531

Total liabilities		22,628			21,277

Commitments and contingencies

Stockholders’ Equity
Preferred stock – 5 million shares issued, 1 million and 3 million shares
outstanding (no par value, 6 million shares authorized)		-			-
Common stock:
Issued – 769 million and 767 million shares (par value $1 per share,
1.1 billion shares authorized)		769			767
Securities exchangeable into common stock – 5 million shares issued,
1 million and 3 million shares outstanding (no par value, unlimited
shares authorized)		-			-
Held in treasury, at cost – 61 million and 61 million shares		(2,713	)		(2,720	)
Additional paid-in capital		6,721			6,696
Retained earnings		17,614			17,259
Accumulated other comprehensive loss		(578	)		(593	)

Total stockholders' equity		21,813			21,409

Total liabilities and stockholders' equity	$	44,441		$	42,686

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

Index

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended
	June 30,
(In millions)	2009			2008
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	695		$	1,505
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		(88	)		(20	)
Deferred income taxes		333			8
Depreciation, depletion and amortization		1,363			933
Pension and other postretirement benefits, net		73			75
Exploratory dry well costs and unproved property impairments		33			114
Net gain on disposal of assets		(195	)		(22	)
Equity method investments, net		11			(149	)
Changes in the fair value of derivative instruments		23			748
Changes in:
Current receivables		(785	)		(1,759	)
Inventories		6			(1,737	)
Current accounts payable and accrued liabilities		168			3,191
All other, net		78			(49	)
Net cash provided by continuing operations		1,715			2,838
Net cash provided by discontinued operations		35			117
Net cash provided by operating activities		1,750			2,955
Investing activities:
Capital expenditures		(2,939	)		(3,329	)
Disposal of assets		402			24
Trusteed funds - withdrawals		16			258
Investing activities of discontinued operations		(47	)		(53	)
All other, net		(51	)		(58	)
Net cash used in investing activities		(2,619	)		(3,158	)
Financing activities:
Short term debt, net		-			980
Borrowings		1,491			1,248
Debt issuance costs		(11	)		(7	)
Debt repayments		(40	)		(1,331	)
Purchases of common stock		-			(295	)
Dividends paid		(340	)		(342	)
All other, net		(1	)		13
Net cash provided by financing activities		1,099			266
Effect of exchange rate changes on cash:
Continuing operations		(17	)		6
Discontinued operations		(2	)		2
Net increase in cash and cash equivalents		211			71
Cash and cash equivalents at beginning of period		1,285			1,199
Cash and cash equivalents at end of period	$	1,496		$	1,270

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

Index

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

These consolidated financial statements are unaudited; however, in the opinion of management, 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 of prior year data have been made to conform to 2009 classifications. Events and transactions subsequent to the balance sheet date have been evaluated through August 6, 2009, the date these consolidated financial statements were issued, for potential recognition or disclosure in the consolidated financial statements.

These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation (“Marathon”) 2008 Annual Report on Form 10-K. The results of operations for the quarter and six months ended June 30, 2009 are not necessarily indicative of the results to be expected for the full year.

2. New Accounting Standards

SFAS No. 165 – In May 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 165, “Subsequent Events.” This statement establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or available to be issued. SFAS No. 165 should not significantly change the subsequent events that an entity reports. It codifies into the accounting standards guidance that existed in the auditing standards. We began applying this standard prospectively in the second quarter of 2009. The disclosures required by SFAS No. 165 appear in Note 1.

FSP FAS 107-1 – In April 2009, the FASB issued a Staff Position (“FSP”) FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1”). FSP FAS 107-1 amends SFAS No. 107 and Accounting Principles Board (“APB”) Opinion No. 28 to require disclosures about fair value of financial instruments in interim reporting periods for publicly traded companies. Disclosures are expanded, making the annual disclosures of SFAS No. 107 required in interim periods. This FSP is effective for the second quarter of 2009 and does not require disclosures for earlier periods presented for comparative purposes. Adoption did not have an impact on our consolidated results of operations, financial position or cash flows. The required disclosures are presented in Note 10.

FSP FAS 157-4 – Also in April 2009, the FASB issued FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,”. FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability has significantly decreased. It also includes guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 is effective for the second quarter of 2009 and does not require disclosures for earlier periods presented for comparative purposes. Adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows.

EITF 08-6 – In November 2008, the FASB ratified Emerging Issues Task Force (“EITF”) Issue 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”) which clarifies how to account for certain transactions involving equity method investments. The initial measurement, decreases in value and changes in the level of ownership of the equity method investment are addressed. EITF 08-6 is effective on a prospective basis on January 1, 2009 and for interim periods. Early application by an entity that has previously adopted an alternative accounting policy is not permitted. Since this standard will be applied prospectively, adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows.

FSP EITF 03-6-1 – In June 2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” which provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method. FSP EITF 03-6-1 is effective January 1, 2009 and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) will be adjusted retrospectively to conform to its provisions. While our restricted stock awards meet this definition of participating securities, the application of FSP EITF 03-6-1 did not have a significant impact on our reported EPS.

FSP FAS 142-3 – In April 2008, the FASB issued FSP FAS 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP FAS 142-3”), which amends the factors that should be considered in developing renewal or extension

Index

Notes to Consolidated Financial Statements (Unaudited)

assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. FSP FAS 142-3 is effective on January 1, 2009. Early adoption is prohibited. The provisions of FSP FAS 142-3 are to be applied prospectively to intangible assets acquired after the effective date, except for the disclosure requirements which must be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. Since this standard is applied prospectively, adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows.

SFAS No. 161 – In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” This statement expands the disclosure requirements for derivative instruments to provide information regarding (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. To meet these objectives, the statement requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. This standard is effective January 1, 2009. The statement encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. The disclosures required by SFAS No. 161 appear in Note 11.

SFAS No. 141(R) – In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS No. 141(R)”). This statement significantly changes the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired, liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair value with limited exceptions. The statement expands the definition of a business and is expected to be applicable to more transactions than the previous standard on business combinations. The statement also changes the accounting treatment for changes in control, step acquisitions, transaction costs, acquired contingent liabilities, in-process research and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination and changes in income tax uncertainties after the acquisition date. Accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting recorded goodwill. Additional disclosures are also required. In April 2009, the FASB issued an FSP on FAS 141(R), “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (“FSP FAS 141(R)-1”), which addressed SFAS No. 141(R) implementation issues related to contingent assets and liabilities acquired in a business combination. Both SFAS No. 141(R) and FSP FAS 141(R)-1 are effective on January 1, 2009 for all new business combinations. Because we had no business combinations in progress at January 1, 2009, adoption of these standards did not have a significant impact on our consolidated results of operations, financial position or cash flows.

SFAS No. 160 – In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51.” This statement establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement clarifies that a noncontrolling interest in a subsidiary (sometimes called a minority interest) is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements, but separate from the parent's equity. It requires that the amount of consolidated net income attributable to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement. SFAS No. 160 clarifies that changes in a parent's ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, this statement requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated, based on the fair value of the noncontrolling equity investment on the deconsolidation date. Additional disclosures are required that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. In January 2009, the FASB ratified EITF Issue 08-10, “Selected Statement 160 Implementation Questions” (“EITF 08-10”). Both SFAS No. 160 and EITF 08-10 are effective January 1, 2009. The statements must be applied prospectively, except for the presentation and disclosure requirements which must be applied retrospectively for all periods presented in consolidated financial statements. Adoption of these standards did not have a significant impact on our consolidated results of operations, financial position or cash flows.

SFAS No. 157 – In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but may require some entities to change their measurement practices. We adopted SFAS No. 157 effective January 1, 2008 with respect to financial assets and liabilities and effective January 1, 2009 with respect to nonfinancial assets and

Index

Notes to Consolidated Financial Statements (Unaudited)

liabilities. Adoption did not have a significant effect on our consolidated results of operations, financial position or cash flows.

In February 2008, the FASB issued FSP FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13,” which removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which deferred the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.

In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued, and any revisions resulting from a change in the valuation technique or its application were required to be accounted for as a change in accounting estimate. Application of FSP FAS 157-3 did not cause us to change our valuation techniques for assets and liabilities measured under SFAS No. 157.

The additional disclosures regarding assets and liabilities recorded at fair value and measured under SFAS No. 157 are presented in Note 10.

FSP FASB 132(R)-1 – In December 2008, the FASB issued FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (“FSP FAS 132(R)-1”) which provides guidance on an employer’s disclosures about plan assets of defined benefit pension or other postretirement plans. This FSP requires additional disclosures about investment policies and strategies, the reporting of fair value by asset category and other information about fair value measurements. The FSP is effective January 1, 2009 and early application is permitted. Upon initial application, the provisions of FSP FAS 132(R)-1 are not required for earlier periods that are presented for comparative purposes. We will expand our disclosures in accordance with FSP FAS 132(R)-1 in our Annual Report on Form 10-K for the year ending December 31, 2009; however, the adoption of this standard is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

3. Income per Common Share

Basic income per share is based on the weighted average number of common shares outstanding, including securities exchangeable into common shares. Diluted income per share includes exercise of stock options, provided the effect is not antidilutive.

	Three Months Ended June 30,
	2009						2008
(In millions, except per share data)	Basic			Diluted			Basic		Diluted

Income from continuing operations		$	341		$	341	$	768		$	768
Discontinued operations			72			72		6			6
Net income		$	413		$	413	$	774		$	774

Weighted average common shares outstanding			709			709		710			710
Effect of dilutive securities			-			2		-			4
Weighted average common shares, including
dilutive effect			709			711		710			714

Per share:
Income from continuing operations		$	0.48		$	0.48	$	1.08		$	1.07
Discontinued operations		$	0.10		$	0.10	$	0.01		$	0.01
Net income		$	0.58		$	0.58	$	1.09		$	1.08

Index

Notes to Consolidated Financial Statements (Unaudited)

	Six Months Ended June 30,
	2009						2008
(In millions, except per share data)	Basic			Diluted			Basic		Diluted

Income from continuing operations		$	607		$	607	$	1,485		$	1,485
Discontinued operations			88			88		20			20
Net income		$	695		$	695	$	1,505		$	1,505

Weighted average common shares outstanding			709			709		711			711
Effect of dilutive securities			-			2		-			5
Weighted average common shares, including
dilutive effect			709			711		711			716

Per share:
Income from continuing operations		$	0.86		$	0.86	$	2.09		$	2.07
Discontinued operations		$	0.12		$	0.12	$	0.02		$	0.03
Net income		$	0.98		$	0.98	$	2.11		$	2.10

The per share calculations above exclude 8 million stock options for the second quarter and the first six months of 2009 and 6 million stock options for the second quarter and the first six months of 2008, as they were antidilutive.

4. Dispositions

Ireland disposition - 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. Activities related to our operated properties in Ireland had been reported in our Exploration and Production (“E&P”) segment.

On June 24, 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. Activities related to the Corrib development also had been reported in our E&P segment. Total proceeds will range between $235 million and $400 million, subject to the timing of first commercial gas at Corrib and closing adjustments. At closing on July 30, 2009, the initial $100 million payment plus closing adjustments was received. Additional proceeds of $135 million to $300 million will be received on the earlier of first commercial gas or December 31, 2012. The fair value of the consideration for this asset was $311 million which was less than its book value. An impairment of $154 million was recognized in the second quarter of 2009 in discontinued operations. Additional gains or losses may be recognized until the final proceeds payment is received (see Note 10).

As a result of these dispositions, our Irish exploration and production businesses have been reported as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented. The net loss on the sales reported in discontinued operations for 2009 was $14 million before income taxes. Revenues and pretax income associated with the operations are shown in the following table:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2009			2008		2009		2008
Revenues applicable to discontinued operations	$	4		$	23	$	83	$	102
Pretax income (loss) from discontinued operations	$	(2	)	$	10	$	33	$	40

Existing guarantees of our subsidiaries’ performance issued to Irish government entities will remain in place after the sales until the purchaser issues similar guarantees to replace them. The guarantees, related to asset retirement obligations and natural gas production levels, have been indemnified by the purchaser. Our maximum potential undiscounted payments under these guarantees were $155 million as of June 30, 2009.

Permian Basin disposition - In June 2009, we closed the 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

Index

Notes to Consolidated Financial Statements (Unaudited)

$292 million. A $199 million pretax gain on the sale was recorded. Activities related to these assets also had been reported in our E&P segment.

Pending Angola disposition - In July 2009, we entered into an agreement to sell an undivided 20 percent outside-operated interest in the Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola for $1.3 billion, excluding any purchase price adjustments at closing, with an effective date of January 1, 2009. We will retain a 10 percent outside-operated interest in Block 32. The carrying value of the 20 percent interest at June 30, 2009 was $430 million which will be classified as held for sale beginning August 1, 2009. We expect to close the transaction by year end 2009, subject to government and regulatory approvals. Activities related to these assets are being reported in our E&P segment.

Assets held for sale - As of June 30, 2009, assets held for sale primarily represented our outside-operated interest in the Corrib development in Ireland as shown in the following table:

(In millions)
Other current assets	$	1
Other noncurrent assets		373
Total assets		374

Other current liabilities		52
Deferred credits and other liabilities		9
Total liabilities		61
Net assets held for sale	$	313

5. 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 by-products;

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; and

Integrated Gas (“IG”) – markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis, and is developing other projects to link stranded natural gas resources with key demand areas.

As discussed in Note 4, our Irish businesses have been reported as discontinued operations. Segment information for all presented periods excludes amounts for these operations.

Index

Notes to Consolidated Financial Statements (Unaudited)

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

Revenues:
Customer		$	1,871		$	126		$	11,052		$	7	$	13,056
Intersegment (a)			123			29			8			-		160
Related parties			14			-			7			-		21
Segment revenues			2,008			155			11,067			7		13,237
Elimination of intersegment revenues			(123	)		(29	)		(8	)		-		(160	)
Gain on U.K. natural gas contracts			3			-			-			-		3
Total revenues		$	1,888		$	126		$	11,059		$	7	$	13,080
Segment income		$	220		$	2		$	165		$	13	$	400
Income from equity method investments(b)			26			-			8			28		62
Depreciation, depletion and amortization (c)			502			34			157			1		694
Income tax provision (c)			444			-			104			2		550
Capital expenditures (d)			617			281			713			1		1,612

	Three Months Ended June 30, 2008
(In millions)		E&P			OSM			RM&T			IG		Total

Revenues:
Customer		$	3,160		$	(80	)	$	18,267		$	21	$	21,368
Intersegment (a)			226			96			37			-		359
Related parties			15			-			671			-		686
Segment revenues			3,401			16			18,975			21		22,413
Elimination of intersegment revenues			(226	)		(96	)		(37	)		-		(359	)
Loss on U.K. natural gas contracts			(165	)		-			-			-		(165	)
Total revenues		$	3,010		$	(80	)	$	18,938		$	21	$	21,889
Segment income (loss)		$	822		$	(157	)	$	158		$	102	$	925
Income from equity method investments(b)			77			-			43			136		256
Depreciation, depletion and amortization (c)			300			33			150			1		484
Income tax provision (benefit)(c)			851			(54	)		108			36		941
Capital expenditures (d)			839			262			702			-		1,803

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

Revenues:
Customer		$	3,175		$	223		$	19,712		$	18	$	23,128
Intersegment (a)			242			54			17			-		313
Related parties			29			-			12			-		41
Segment revenues			3,446			277			19,741			18		23,482
Elimination of intersegment revenues			(242	)		(54	)		(17	)		-		(313	)
Gain on U.K. natural gas contracts			85			-			-			-		85
Total revenues		$	3,289		$	223		$	19,724		$	18	$	23,254
Segment income (loss)		$	305		$	(22	)	$	324		$	40	$	647
Income from equity method investments(b)			37			-			2			70		109
Depreciation, depletion and amortization (c)			969			71			309			2		1,351
Income tax provision (benefit)(c)			616			(8	)		210			15		833
Capital expenditures (d)			990			567			1,373			1		2,931

Index

Notes to Consolidated Financial Statements (Unaudited)

	Six Months Ended June 30, 2008
(In millions)	E&P			OSM			RM&T			IG		Total

Revenues:
Customer	$	5,900		$	99		$	32,600		$	40	$	38,639
Intersegment (a)		385			116			202			-		703
Related parties		29			-			1,199			-		1,228
Segment revenues		6,314			215			34,001			40		40,570
Elimination of intersegment revenues		(385	)		(116	)		(202	)		-		(703	)
Loss on U.K. natural gas contracts		(235	)		-			-			-		(235	)
Total revenues	$	5,694		$	99		$	33,799		$	40	$	39,632
Segment income (loss)	$	1,494		$	(130	)	$	83		$	201	$	1,648
Income from equity method investments(b)		139			-			71			255		465
Depreciation, depletion and amortization (c)		548			67			298			2		915
Income tax provision (benefit)(c)		1,521			(45	)		63			84		1,623
Capital expenditures (d)		1,596			510			1,213			1		3,320

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

(b)	Pilot Travel Centers LLC, which was reported in our RM&T segment, was sold in the fourth quarter of 2008.

(c)	Differences between segment totals and our 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 reconciliation below.

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

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

	Three Months Ended							Six Months Ended
	June 30,							June 30,
(In millions)	2009				2008			2009				2008
Segment income		$	400		$	925			$	647			$	1,648
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items			(89	)		(57	)			(140	)			(78	)
Foreign currency remeasurement of deferred taxes			(94	)		(16	)			(66	)			35
Gain (loss) on U.K. natural gas contracts			2			(84	)			44				(120	)
Gain on dispositions			122			-				122				-
Discontinued operations			72			6				88				20
Net income		$	413		$	774			$	695			$	1,505

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					Six Months Ended
	June 30,					June 30,
(In millions)	2009			2008		2009			2008
Total revenues		$	13,080	$	21,889		$	23,254		$	39,632
Less: Sales to related parties			21		686			41			1,228
Sales and other operating revenues (including
consumer excise taxes)		$	13,059	$	21,203		$	23,213		$	38,404

Index

Notes to Consolidated Financial Statements (Unaudited)

6. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Three Months Ended June 30,
	Pension Benefits								Other Benefits
(In millions)	2009				2008				2009				2008
Service cost		$	37			$	39			$	4			$	4
Interest cost			42				41				9				10
Expected return on plan assets			(40	)			(42	)			-				-
Amortization:
– prior service cost (credit)			4				4				(2	)			-
– actuarial loss (gain)			10				11				(2	)			(2	)
– net settlement/curtailment loss(a)			18				-				-				-
Net periodic benefit cost		$	71			$	53			$	9			$	12

	Six Months Ended June 30,
	Pension Benefits								Other Benefits
(In millions)	2009				2008				2009				2008
Service cost		$	72			$	73			$	9			$	9
Interest cost			84				80				20				22
Expected return on plan assets			(80	)			(84	)			-				-
Amortization:
– prior service cost (credit)			7				7				(3	)			(4	)
– actuarial loss (gain)			16				15				(2	)			1
– net settlement/curtailment loss(a)			18				-				-				-
Net periodic benefit cost		$	117			$	91			$	24			$	28

(a) The curtailment and settlement is related to our discontinued operations in Ireland, as discussed in Note 4. Pension expense related to Ireland was not material in any period presented.

During the first six months of 2009, we made contributions of $40 million to our funded pension plans. We expect to make additional contributions up to an estimated $290 million to our funded pension plans over the remainder of 2009, the majority of which will occur in the third quarter of 2009. We are still evaluating guidance issued by the Internal Revenue Service on March 31, 2009, which may cause actual contributions to differ from our estimate. Current benefit payments related to unfunded pension and other postretirement benefit plans were $8 million and $16 million during the first six months of 2009.

Index

Notes to Consolidated Financial Statements (Unaudited)

7. Income Taxes

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

	Six Months Ended June 30,
	2009			2008
Statutory U.S. income tax rate		35	%		35	%
Foreign taxes in excess of federal statutory rate		25			14
State and local income taxes, net of federal income tax effects		1			1
Other tax effects		-			(2	)
Effective income tax rate		61	%		48	%

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 change in mix of liquid hydrocarbon and natural gas sales in 2009 from 2008 included more sales in jurisdictions with high tax rates. This change, as well as unfavorable foreign currency remeasurement effects, contributed to the increase in the effective income tax rate in the first six months of 2009 when compared to the same period in 2008.

We are continuously undergoing examination of our U.S. federal income tax returns by the Internal Revenue Service. Such audits have been completed through the 2005 tax year. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. Further, we are routinely involved in U.S. state income tax audits and foreign jurisdiction tax audits. We believe all other audits will be resolved within the amounts paid and/or provided for these liabilities. As of June 30, 2009, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated.

United States (a)	2001 - 2007
Canada	2000 - 2008
Equatorial Guinea	2006 - 2008
Libya	2006 - 2008
Norway	2007 - 2008
United Kingdom	2007

(a)	Includes federal and state jurisdictions.

8. Comprehensive Income

The following sets forth comprehensive income for the periods indicated:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2009		2008			2009			2008
Net income	$	413	$	774		$	695		$	1,505
Other comprehensive income, net of taxes:
Defined benefit postretirement plans		19		(31	)		18			(20	)
Derivatives		26		1			(4	)		4
Other		-		-			1			(5	)
Comprehensive income	$	458	$	744		$	710		$	1,484

Index

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.

	June 30,		December 31,
(In millions)	2009		2008
Liquid hydrocarbons, natural gas and bitumen	$	1,122	$	1,376
Refined products and merchandise		1,935		1,797
Supplies and sundry items		441		334
Total, at cost	$	3,498	$	3,507

10. Fair Value Measurements

Fair Values - Recurring

The following table presents the assets (liabilities) accounted for at fair value on a recurring basis as of June 30, 2009, and December 31, 2008:

	June 30, 2009
(In millions)		Level 1		Level 2			Level 3			Total
Derivative Instruments:
Commodity		$	18	$	1		$	(6	)	$	13
Interest rate			-		-			(23	)		(23	)
Foreign currency			-		(22	)		-			(22	)
Total derivative instruments			18		(21	)		(29	)		(32	)
Other assets			2		-			-			2
Total at fair value		$	20	$	(21	)	$	(29	)	$	(30	)


	December 31, 2008
(In millions)		Level 1		Level 2			Level 3			Total
Derivative Instruments:
Commodity		$	107	$	6		$	(55	)	$	58
Interest rate			-		-			29			29
Foreign currency			-		(75	)		-			(75	)
Total derivative instruments			107		(69	)		(26	)		12
Other assets			2		-			-			2
Total at fair value		$	109	$	(69	)	$	(26	)	$	14

Deposits of $17 million in broker accounts covered by master netting agreements are netted against the value to arrive at the fair values of commodity derivatives. 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 prices for the market. Derivatives in Level 2 are measured at fair value with a market approach using broker quotes or third-party pricing services, which have been corroborated with data from active markets. Level 3 derivatives are measured at fair value using either a market or income approach. Generally at least one input is unobservable, such as the use of an internally generated model or an external data source.

Commodity derivatives in Level 3 at June 30, 2009 include two U.K. natural gas sales contracts that are accounted for as derivative instruments and crude oil options related to sales of Canadian synthetic crude oil. The fair value of the U.K. natural gas contracts is measured with an income approach by applying the difference between the contract price

Index

Notes to Consolidated Financial Statements (Unaudited)

and the U.K. forward natural gas strip price to the expected sales volumes for the remaining contract term. These contracts originated in the early 1990s and expire in September 2009. The contract prices are reset annually in October based on the previous twelve-month changes in a basket of energy and other indices. Consequently, the prices under these contracts do not track forward natural gas prices. The crude oil options, which expire December 2009, are measured at fair value using a Black-Scholes option pricing model, an income approach that utilizes prices from an active market and market volatility calculated by a third-party service.

Also in Level 3 are commodity derivatives intended to manage price risk related to acquisition of ethanol for blending and light products fixed priced sales contracts. The fair value of these derivatives is measured using quoted market prices adjusted for broker market assessments.

The fair value of interest rate swaps is measured using broker quotes or quotes from a reporting service which are not corroborated to data from an active market; therefore these inputs are classified as Level 3.

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 for the three and six months ended June 30, 2009:

	Three Months Ended
(In millions)	June 30, 2009
Beginning balance	$	9
Total realized and unrealized losses:
Included in net income		(33	)
Purchases, sales, issuances and settlements, net		(5	)
Ending balance	$	(29	)

	Six Months Ended
(In millions)	June 30, 2009
Beginning balance	$	(26	)
Total realized and unrealized losses:
Included in net income		44
Purchases, sales, issuances and settlements, net		(47	)
Ending balance	$	(29	)

Net income for the second quarter and first six months of 2009 included unrealized losses of $4 million and unrealized gains of $76 million, respectively, related to instruments held at June 30, 2009. Amounts reported in net income are classified as sales and other operating revenues or cost of revenues for commodity derivative instruments, as net interest and other financing income for interest rate derivative instruments and as cost of revenues for foreign currency derivatives, except those designated as hedges of future capital expenditures.

Fair Values - Nonrecurring

The following table shows the June 30, 2009 values of assets measured at fair value on a nonrecurring basis during the second quarter of 2009 by major category:

	June 30, 2009
(In millions)	Total		Level 1		Level 2		Level 3		Impairment

Long-lived assets held for sale	$	311	$	-	$	-	$	311	$	154
Long-lived assets held for use		5		-		-		5		15

Index

Notes to Consolidated Financial Statements (Unaudited)

The impairment charge related to the sale of the Corrib natural gas development offshore Ireland was based on a fair value assessment of the anticipated sale proceeds (see Note 4). At closing on July 30, 2009, the initial $100 million payment was received. Additional proceeds of $135 million to $300 million will be received on the earlier of first commercial gas or December 31, 2012. These proceeds were classified as Level 3 inputs because a portion is variable in timing and amount depending upon timing of first gas. The Level 3 inputs were valued 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. The minimum amount due of $135 million is payable no later than December 31, 2012.

The ultimate timing of the gain or loss recognized related to the sale of the Corrib development will depend on the resolution by accounting standard-setters of the appropriate accounting for contingent consideration. The EITF is currently deliberating the appropriate accounting treatment for contingent consideration by sellers. In connection with that deliberation, the EITF has asked the FASB staff for interpretative guidance on the initial recognition of contingent consideration by sellers. The timing of any further gain or loss recognition will depend on the resolution reached by the FASB staff and the EITF and may or may not require a reassessment of the fair value of the contingent consideration each reporting period.

Several long-lived assets held for use were evaluated for impairment in the second quarter of 2009 due to reductions in estimated reserves and declining natural gas prices. An impairment was required on one natural gas field in East Texas. Fair value of the asset was measured using an income approach based upon internal estimates of future production levels, prices and discount rate, which are Level 3 inputs.

Fair Values - Reported

The following table summarizes financial instruments, excluding the derivative financial instruments, and their reported fair value by individual balance sheet line item at June 30, 2009 and December 31, 2008:


	June 30, 2009				December 31, 2008
	Fair		Carrying		Fair		Carrying
(In millions)	Value		Amount		Value		Amount
Financial assets
Receivables from United States Steel, including current portion	$	470	$	481	$	438	$	492
Other noncurrent assets(a)		405		217		286		113

Total financial assets		875		698		724		605

Financial liabilities
Long-term debt, including current portion(b)		8,508		8,333		5,683		6,854

Total financial liabilities	$	8,508	$	8,333	$	5,683	$	6,854

(a)	Includes restricted cash, cost method investments and miscellaneous long-term receivables or deposits of which $132 million related to deposits in property exchange trusts.

(b)	Excludes capital leases.

Our current assets and liabilities accounts contain 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 and the current portion of our long-term debt, which is reported 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 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 asset is not publicly-traded and not

Index

Notes to Consolidated Financial Statements (Unaudited)

easily transferable, a hypothetical market based upon United States Steel’s borrowing rate curve is assumed and the majority of inputs to the calculation are Level 3. The industrial revenue bonds are to be redeemed on or before December 31, 2011.

The majority of our restricted cash represents cash accounts that earn interest or will be held for a short time; therefore, the balance approximates fair value. Other financial assets included in the other noncurrent assets line include cost method investments and miscellaneous long-term receivables or deposits. Fair value for the cost method investments is measured using an income approach. Estimated future cash flows, obtained from the partially owned companies, are discounted at an appropriate discount rate to obtain the fair value. We may adjust the companies’ estimates based upon current market conditions. Long-term receivables and deposits are measured using an income approach. The expected timing of payments is scheduled and then discounted using a rate deemed appropriate.

Over 75 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-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.

11. Derivatives

We may use derivatives to manage our exposure to commodity price risk, interest rate risk and foreign currency risk. Derivative instruments are recorded at fair value. Derivative instruments on our consolidated balance sheet are reported on a net basis by brokerage firm, as permitted by master netting agreements. For further information regarding the fair value measurement of derivative instruments see Note 10. The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheet as of June 30, 2009:

(In millions)	Asset		Liability			Net Asset		Balance Sheet Location
Cash Flow Hedges
Foreign currency	$	1	$	-		$	1	Other current assets
Total Designated Hedges		1		-			1

Not Designated as Hedges
Commodity		292		(270	)		22	Other current assets
Total Not Designated as Hedges		292		(270	)		22

Total	$	293	$	(270	)	$	23

(In millions)	Asset		Liability			Net Liability			Balance Sheet Location
Cash Flow Hedges
Foreign currency	$	-	$	(23	)	$	(23	)	Other current liabilities
Fair Value Hedges
Commodity		-		(7	)		(7	)	Other current liabilities
Interest rate		-		(23	)		(23	)	Deferred credits and other liabilities
Total Designated Hedges		-		(53	)		(53	)

Not Designated as Hedges

Commodity		8		(27	)		(19	)	Other current liabilities

Total Not Designated as Hedges		8		(27	)		(19	)
Total	$	8	$	(80	)	$	(72	)

Index

Notes to Consolidated Financial Statements (Unaudited)

Derivatives Designated as Cash Flow Hedges

We also use foreign currency forwards and options to hedge anticipated transactions, primarily expenditures for capital projects, in certain foreign currencies and designate them cash flow hedges. As of June 30, 2009, the following foreign currency forwards were outstanding:

(In millions)	Period		Notional Amount	Weighted Average Forward Rate
Foreign Currency Forwards:
Dollar (Canada)	July 2009 - February 2010	$	275	1.069 (b)
Euro	July 2009- June 2010	$	6	1.278 (a)
Kroner (Norway)	July 2009 - November 2009	$	40	6.285 (b)

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

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

We may use interest rate derivative instruments to manage the market risk of interest rate movements on anticipated borrowings. No such derivatives were outstanding at June 30, 2009. In recent past transactions, such derivatives have been outstanding for a period of less than one month.

For derivatives qualifying as hedges of future cash flows, the effective portion of any changes in fair value is recognized in other comprehensive income (“OCI”) and is reclassified to net income when the underlying forecasted transaction is recognized in net income. Any ineffective portion of cash flow hedges is recognized in net income as it occurs. For discontinued cash flow hedges, prospective changes in the fair value of the derivative are recognized in net income. The accumulated gain or loss recognized in OCI at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in OCI is immediately reclassified into net income.

Approximately $1 million in losses are expected to be reclassified from accumulated other comprehensive income (“AOCI”) over the next 12 months. The ineffective portion of currently outstanding cash flow hedges was less than $1 million; therefore, ineffectiveness is not reported in the tables below. In the second quarter and six months ended June 30, 2009, no significant cash flow hedges were discontinued.

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

	Gain (Loss) in OCI
(In millions)	Three Months Ended			Six Months Ended

Foreign currency		$	30		$	18
Interest rate		$	-		$	(15	)

The following table summarizes the effect of AOCI reclasses related to derivative instruments designated as hedges of cash flows in our consolidated statement of income:

		Gain (Loss) reclassified from
		AOCI into Net Income
(In millions)	Income Statement Location	Three Months Ended			Six Months Ended

Foreign currency	Discontinued operations		$	1		$	1
Interest rate	Net interest and other financing costs		$	-		$	(1	)

Derivatives Designated as Fair Value Hedges

We use interest rate swaps to manage the mix of fixed and floating interest rate debt in our portfolio. As of June 30, 2009, we had multiple interest rate swap agreements with a total notional amount of $1.25 billion at a weighted-average, LIBOR-based, floating rate of 4.49 percent. For such derivatives designated as hedges of fair value, changes in

Index

Notes to Consolidated Financial Statements (Unaudited)

the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.

We use commodity derivative instruments to manage the price risk for natural gas that is purchased to be marketed with our own natural gas production. These are also designated as fair value hedges. As of June 30, 2009, commodity derivative instruments for a weighted average 5,000 mcf (“thousand cubic feet”) were outstanding for the period July 2009 through March 2010.

The following table summarizes the pretax effect of derivative instruments designated as hedges of fair value in our consolidated statement of income for the three months and six months ended June 30, 2009:

		Gain (Loss)
(In millions)	Income Statement Location	Three Months Ended			Six Months Ended

Derivative
Commodity	Sales and other operating revenues	$	(4	)	$	(10	)
Interest rate	Net interest and other financing costs		(29	)		(29	)
			(33	)		(39	)
Hedged Item
Commodity	Sales and other operating revenues		4			10
Interest rate	Net interest and other financing costs		29			29
			33			39

The interest rate swaps have no hedge ineffectiveness. Hedge ineffectiveness related to the commodity derivatives is less than $1 million and is therfore not reflected in the above table.

Derivatives not Designated as Hedges

Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income. Some derivative instruments not designated as hedges may be classified as trading activities, for which all related effects, are recognized in net income and are classified as other income.

Two long-term natural gas delivery commitment contracts in the U.K. are classified as derivative instruments. These contracts, which expire September 2009, contain pricing provisions that are not clearly and closely related to the underlying commodity and therefore must be accounted for as derivative instruments. Crude oil options entered by Western Oil Sands Inc. (“Western”) to protect against price decreases on a portion of future sales of synthetic crude oil were not designated as hedges upon our acquisition of Western in October 2007. In the first quarter of 2009, we sold derivative instruments which effectively offset the open put options for the remainder of 2009. The following table summarizes the put and call options outstanding at June 30, 2009:


Option Contract Volumes (Barrels per day)
Put options purchased		20,000
Put options sold		20,000
Call options sold		15,000
Average Exercise Price (Dollars per barrel)
Put options	$	50.50
Call options	$	90.50

We use commodity derivative instruments to manage price risk on inventories and natural gas held in storage before it is sold. We also use derivative instruments to manage price risk related to fixed price sales of refined products, the acquisition of foreign-sourced crude oil, the acquisition of feedstocks used in the refining process and the acquisition of ethanol for blending with refined products. The following table summarizes volumes related to our net open positions as of June 30, 2009:

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Notes to Consolidated Financial Statements (Unaudited)

	Buy/(Sell)
Crude oil (million barrels)		2.1
Refined products (million barrels)		3.6
Natural gas (billion cubic feet)
Price		(2.4	)
Basis		(1.3	)

The following table summarizes the effect of all derivative instruments not designated as hedges in our consolidated statement of income for the three months and six months ended June 30, 2009:

		Gain (Loss)
(In millions)	Income Statement Location	Three Months Ended			Six Months Ended

Commodity	Sales and other operating revenues	$	(1	)	$	92
Commodity	Cost of revenues		17			(42	)
Commodity	Other income		2			3
			18			53

Contingent Credit Features

Our derivative instruments contain no significant contingent credit features.

Concentrations of Credit Risk

All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.

12. Debt

At June 30, 2009, 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.

On February 17, 2009, we issued $700 million aggregate principal amount of senior notes bearing interest at 6.5 percent with a maturity date of February 15, 2014 and $800 million aggregate principal amount of senior notes bearing interest at 7.5 percent with a maturity date of February 15, 2019. Interest on both issues is payable semi-annually beginning August 15, 2009.

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Notes to Consolidated Financial Statements (Unaudited)

13. Stock-Based Compensation Plans

The following table presents a summary of stock option award and restricted stock award activity for the six month period ended June 30, 2009:

	Stock Options					Restricted Stock
				Weighted					Weighted Average
	Number of			Average					Grant Date Fair
	Shares			Exercise Price		Awards			Value
Outstanding at December 31, 2008		13,841,748		$	37.59		2,049,255		$	47.72
Granted (a)		4,970,500			27.62		227,935			24.15
Options Exercised/Stock Vested		(28,610	)		15.86		(282,291	)		43.13
Canceled		(141,990	)		52.41		(69,995	)		43.15
Outstanding at June 30, 2009		18,641,648		$	34.85		1,924,904		$	45.77

(a) The weighted average grant date fair value of stock option awards granted was $7.67 per share.

14. 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.

Litigation – We settled a number of lawsuits pertaining to methyl tertiary-butyl ether (“MTBE”) in 2008. Presently, we are a defendant, along with other refining companies, in 26 cases arising in four states alleging damages for MTBE contamination. Of the 26 cases in which we remain a defendant, 20 are pending in New York, 4 in Florida and 1 in Illinois. These 25 cases allege damages to water supply wells, similar to the damages claimed in the cases that were settled in 2008. In the other remaining case, the State of New Jersey is seeking natural resources damages allegedly resulting from contamination of groundwater by MTBE. This is the only MTBE contamination case in which we are a defendant and natural resources damages are sought. Thirteen of the 20 New York cases have been dismissed from the multi-district litigation (“MDL”) and re-filed in the state courts of Nassau and Suffolk Counties, New York. The remaining cases, like the cases that were settled in 2008, are consolidated in the MDL in the Southern District of New York for pretrial proceedings. We are vigorously defending these cases. We have engaged in settlement discussions related to the majority of the cases. We do not expect our share of liability, if any, for the remaining cases to significantly impact our consolidated results of operations, financial position or cash flows. We voluntarily discontinued producing MTBE in 2002.

We are currently a party in two qui tam cases, which allege that federal and Indian leases violated the False Claims Act with respect to the reporting and payment of royalties on natural gas and natural gas liquids. A qui tam action is an action in which the relator files suit on behalf of himself as well as the federal government. One case is U.S. ex rel Harrold E. Wright v. Agip Petroleum Co. et al. which is primarily a gas valuation case. A settlement agreement has been reached, but not yet finalized. Such settlement is not expected to significantly impact our consolidated results of operations, financial position or cash flows. The other case is U.S. ex rel Jack Grynberg v. Alaska Pipeline, et al. involving allegations of natural gas measurement. This case was dismissed by the trial court and the dismissal has been affirmed by the 10th Circuit Court of Appeals. The relator is expected to file an appeal to the U.S. Supreme Court. The outcome of this case is not expected to significantly impact our consolidated results of operations, financial position or cash flows.

A lawsuit filed in the U.S. District Court for the Southern District of West Virginia alleged that our Catlettsburg, Kentucky, refinery distributed contaminated gasoline to wholesalers and retailers for a period prior to August 2003, causing permanent damage to storage tanks, dispensers and related equipment, resulting in lost profits, business disruption and personal and real property damages. Following the incident, we conducted remediation operations at affected facilities and there was no permanent damage to wholesaler and retailer equipment. Class action certification was granted in August 2007. A settlement of the case was approved by the court on March 18, 2009, payment has been

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Notes to Consolidated Financial Statements (Unaudited)

made and the case has been dismissed with prejudice. The settlement did not significantly impact our consolidated results of operations, financial position or cash flows.

Contractual commitments – At June 30, 2009, Marathon’s contract commitments to acquire property, plant and equipment totaled $3,407 million.

15. Supplemental Cash Flow Information

	Six Months Ended June 30,
(In millions)	2009			2008

Net cash provided from operating activities included:
Interest paid (net of amounts capitalized)	$	-		$	54
Income taxes paid to taxing authorities		1,050			1,498
Short term debt, net:
Commercial paper - issuances	$	897		$	28,992
- repayments		(897	)		(28,012	)
Noncash investing and financing activities:
Capital lease and sale-leaseback financing obligations	$	47		$	32

16. Accounting Standards Not Yet Adopted

SFAS No. 167 – In June 2009, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard (“SFAS”) No. 167, “Amendments of FASB Interpretation No. 46(R).” This statement replaces the existing 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 and therefore, will now be evaluated for consolidation in accordance with the applicable consolidation guidance. Ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity are also required. SFAS No. 167 requires 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. SFAS No. 167 will be applied prospectively beginning in the first quarter of 2010, and for all interim and annual periods thereafter. Earlier application of SFAS No. 167 is prohibited. We are currently evaluating the provisions of this statement.

Reporting on Oil & Gas Producing Activities – In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include volumes in their reserve base from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices. The SEC indicated that they will continue to communicate with the FASB staff to align their accounting standards with these rules. The FASB currently requires a single-day, year-end price for accounting purposes.

Permit companies to disclose their probable and possible reserves on a voluntary basis. Under current rules, proved reserves were the only reserves allowed in the disclosures.

Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.

Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

Replace the existing "certainty" test for areas beyond one offsetting drilling unit from a productive well with a "reasonable certainty" test.

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Notes to Consolidated Financial Statements (Unaudited)

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company's overall reserve estimation process. Additionally, disclosures regarding internal controls surrounding reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.

Require separate disclosure of reserves in foreign countries if they represent more than 15 percent of total proved reserves, based on barrels of oil equivalents.

We expect to begin complying with the disclosure requirements in our Annual Report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We are currently in the process of evaluating the new requirements.

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

We are a global integrated energy company with significant 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 by-products.
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.
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, and is developing other projects to link stranded natural gas resources with key demand areas.

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 2008 Annual Report on Form 10-K.

Activities related to discontinued operations have been excluded from segment results and operating statistics.

Overview and Outlook

Exploration and Production (“E&P”)

Production

Net liquid hydrocarbon and natural gas sales averaged 436 and 415 thousand barrels of oil equivalent per day (“mboepd”) during the second quarter and first six months of 2009 compared to 347 and 357 mboepd during the second quarter and first six months of 2008. These increases over the same periods of 2008 primarily reflect the impact of a full quarter of production from the Alvheim/Vilje development offshore Norway and the Neptune development in the Gulf of Mexico compared to partial quarters in 2008 when they commenced production. For the second quarter, worldwide natural gas sales are down 5 percent, primarily in the U.S. as a result of property sales, the timing of Alaska storage activities and natural decline in Gulf of Mexico, while natural gas sales in Equatorial Guinea have increased due to improved reliability at the LNG plant which purchase this natural gas.

We have drilled all four development wells on the Droshky discovery in the Gulf of Mexico on Green Canyon Block 244. Well completions are underway and the project is on track for our first production target of 2010.

Exploration

During the second quarter 2009, we announced the Oberon discovery on Block 31 offshore Angola. We also participated in 2 exploration wells in Block 31 and are in the process of drilling another exploration well. We hold a 10 percent outside-operated interest in Block 31 and a 30 percent outside-operated interest in Block 32, pending the sale of two-thirds of our Block 32 interest as discussed below.

During the second quarter 2009, we were awarded all 16 blocks bid in the Central Gulf of Mexico Lease Sale No. 208 conducted by the Minerals Management Service. Ten blocks are 100 percent Marathon, and the remaining six blocks were bid with partners, for a total of $62 million. We have acquired a total of 59 new leases from lease sales held 2007 through 2009.

We were awarded a 49 percent interest and will serve as operator in the Kumawa Block offshore Indonesia, our third Indonesian offshore exploration block. The Kumawa Block encompasses 1.24 million acres.

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Divestitures

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. Net production from these operations averaged 5,000 boepd in the first quarter of 2009. Our net proved reserves associated with these assets as of December 31, 2008, were 6 million barrels of oil equivalent (“mmboe”). As a result of this sale, we terminated our pension plan in Ireland, incurring a charge of $18 million which reduced the gain on sale.

On June 24, 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. Total proceeds will range between $235 million and $400 million, subject to the timing of first commercial gas at Corrib and closing adjustments. At closing on July 30, 2009, the initial $100 million payment plus closing adjustments was received. Additional proceeds of $135 million to $300 million will be received on the earlier of first commercial gas or December 31, 2012. The fair value of the consideration for this asset was $311 million which was less than its book value. An impairment of $154 million was recognized in the second quarter of 2009 in discontinued operations. Additional gains or losses may be recognized until the final proceeds payment is received (see Note 10).

In July 2009, we entered into an agreement to sell an undivided 20 percent outside-operated interest in the Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola for $1.3 billion, excluding any purchase price adjustments at closing, with an effective date of January 1, 2009. We will retain a 10 percent outside-operated interest in Block 32. We expect to close the transaction by year-end 2009, subject to government and regulatory approvals.

In June 2009, we closed the 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 $292 million. A $199 million pretax gain on the sale was recorded. Net production from these operations averaged 8,150 boepd in the first quarter of 2009. Our net proved reserves associated with these assets as of December 31, 2008, were 14 mmboe.

The above discussions include forward-looking statements with respect to the timing and levels of future production, anticipated future exploratory drilling activity and pending divestitures. Some factors that could potentially affect these forward-looking statements include pricing, supply and demand for 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 forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals and permits. The divestitures could also be adversely affected by customary closing conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Oil Sands Mining (“OSM”)

Our bitumen production was 26 thousand barrels per day (“mbpd”) in the second quarter and 25 mbpd in the first six months of 2009.

In the second quarter of 2009, the operator of AOSP offered three additional leases to the other joint venture partners for the Muskeg River Mine. Terms of the transaction were as agreed in the original 1999 AOSP Joint Venture Agreement. We elected to participate in these leases and our net proved reserves increased 168 million barrels. These additional reserve barrels will initially reduce our depreciation, depletion and amortization (“DD&A”) rate per barrel by approximately 40 percent beginning in June 2009.

The Alberta government announced its decision to consider the proposed AOSP’s Quest carbon capture and sequestration (“CCS”) project, involving the Scotford upgrader, for possible government funding. The AOSP partners are currently working with the government on a letter of intent, after which a funding agreement will be negotiated. A final investment decision on the Quest project will be made at a later date, pending agreement on funding details with the Government of Alberta, regulatory approvals, stakeholder engagement, as well as final agreement of the joint venture partners.

The above discussion includes forward-looking statements with respect to future DD&A levels. The DD&A rate change is an estimate and actual future results may differ.

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

Our total refinery throughputs were 4 percent and 2 percent lower in the second quarter and first six months of 2009 than in the second quarter and first six months of 2008. Crude oil refined likewise decreased 6 percent and 3 percent in the same periods. The throughput declines in 2009 relate primarily to our level of planned maintenance activities. Planned major maintenance activities were completed at our Canton, Ohio; Catlettsburg, Kentucky; Robinson, Illinois, and Garyville, Louisiana, refineries in the first half of 2009. In the first and second quarters of 2008, major maintenance activities occurred at our Detroit, Michigan; Garyville and Robinson refineries.

Volumes under our ethanol blending program increased to 70 mbpd for the first six months of 2009, a 39 percent increase over the same period of 2008. For the second quarter of 2009 we blended an average of 73 mbpd, or 30 percent more ethanol than in the same period of 2008. The future expansion or contraction of our ethanol blending program will be driven by the economics of ethanol supply and government regulations.

Second quarter 2009 Speedway SuperAmerica LLC (“SSA”) same store gasoline sales volume increased 3 percent when compared to the second quarter of 2008. This compares to an estimated demand decline of about 2 percent in our market area in the second quarter 2009, while same store merchandise sales increased by 14 percent for the same period.

As of July 31, 2009, the expansion of our Garyville, Louisiana refinery is 91 percent complete with an on-schedule startup expected in the fourth quarter 2009. We now forecast that the project will cost $3.7 billion, or approximately 10 percent more than our previously stated cost estimate. Delays in receipt of materials and fabricated equipment contributed to revisions in work execution plans, resulting in increased project costs. Construction activities continue on the heavy oil upgrading and expansion project at our Detroit refinery with completion expected in the last half of 2012.

The above discussion includes forward-looking statements with respect to the Garyville and Detroit refinery expansion projects. Factors that could affect those projects 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. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas (“IG”)

Our share of LNG sales worldwide totaled 6,611 metric tonnes per day (“mtpd”) for the second quarter of 2009 compared to 6,402 mtpd in the second quarter of 2008 and 6,690 mtpd in the first six months of 2009 compared to 6,657 mtpd in the first six months of 2008. 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. The LNG production facility in Equatorial Guinea had operational availability of 99 percent in the second quarter of 2009.

We continue to invest in the development of new technologies to create value and supply new energy sources. In the second quarter and first six months of 2009, we recorded costs of approximately $18 and $36 million related to natural gas technology research, including our GTF™ technology. Similar spending in the same periods of 2008 was $22 million and $38 million.

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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 continue to be volatile in 2009, with the following table listing benchmark crude oil and natural gas price averages for the second quarter and first six months of 2009 and 2008 are listed below to illustrate the volatility:

	Three Months Ended June 30,				Six Months Ended June 30,
Benchmark	2009		2008		2009		2008
WTI crude oil (Dollars per barrel)	$	59.79	$	123.80	$	51.68	$	111.12
Brent crude oil (Dollars per barrel)	$	59.13	$	121.18	$	51.68	$	109.05
Henry Hub natural gas (Dollars per mcf)(a)	$	3.51	$	10.94	$	4.21	$	9.49

(a)	First-of-month price index.

On average, crude oil prices in 2009 were lower than in 2008. Crude oil prices declined rapidly through February 2009 from a high of over $140 per barrel in July 2008. By June 2009 prices were approximately half of the previous year’s maximum levels.

Our domestic crude oil production is on average heavier and higher in sulfur content than light sweet WTI. Heavier and higher sulfur crude oil (commonly referred to as heavy sour crude oil) typically sells at a discount to light sweet crude oil. Our international crude oil production is relatively sweet and is generally sold in relation to the Brent crude oil benchmark.

Natural gas prices on average were also lower in 2009 than in 2008. Our natural gas sales in Alaska are subject to term contracts. Our other major natural gas-producing regions are Europe and Equatorial Guinea, where large portions of our natural gas sales are subject to term contracts, making realized prices in these areas less volatile. As we sell larger quantities of natural gas from these regions, to the extent that these fixed prices are lower than prevailing prices, our reported average natural gas prices realizations may decrease.

Our worldwide E&P revenues during the second quarter and first six months of 2009 were 41 and 45 percent lower than in the same periods of 2008, with the majority of the revenue decreases tied to these decreases in average commodity prices.

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 marker, primarily Western Canadian Select. Output mix can be impacted by operational problems or planned unit outages at the mine or upgrader.

The operating cost structure of the oil sands mining operations is predominantly fixed, and therefore many of the costs incurred in times of full operation continue during production downtime. Per 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 second quarter and first six months of 2009 and 2008:

Index

	Three Months Ended June 30,				Six Months Ended June 30,
Benchmark	2009		2008		2009		2008
WTI crude oil (Dollars per barrel)	$	59.79	$	123.80	$	51.68	$	111.12
Western Canadian Select (Dollars per barrel)(a)	$	52.36	$	102.18	$	43.50	$	89.58
AECO natural gas sales index (Canadian dollars per gigajoule)(b)	$	3.28	$	9.67	$	4.00	$	8.56

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

(b)	Alberta Energy Company day ahead index.

Excluding the impact of derivatives, our OSM segment revenues for the second quarter and first six months of 2009 were lower than for the same periods of 2008, reflecting the impact of lower price realizations for synthetic crude oil and vacuum gas oil sales. Realizations were 53 percent lower in the second quarter and 55 percent lower for the first six months of 2009, compared to the same periods of 2008.

Refining, Marketing and Transportation

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

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 spot market prices at major trading locations for refined products and crude oil, commonly used by the industry as an indicator of the impact of price on 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. Posted 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. The following table lists calculated average crack spreads for the Midwest and Gulf Coast markets and the sweet/sour differential for the second quarter and first six months of 2009 and 2008:

	Three Months Ended June 30,				Six Months Ended June 30,
(Dollars per barrel)	2009		2008		2009		2008
Chicago LLS 6-3-2-1 crack spread	$	5.73	$	2.71	$	4.34	$	1.42
U.S. Gulf Coast LLS 6-3-2-1 crack spread	$	3.59	$	1.99	$	3.25	$	1.70
Sweet/Sour differential(a)	$	3.98	$	13.74	$	5.60	$	13.31

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

In addition to the market changes indicated by the crack spreads, 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.

Our refineries can process significant amounts of sour crude oil which may enhance our margin compared to what the change in the relevant crack spread indicators would suggest, as sour crude oil typically can be purchased at a discount to sweet crude oil. The amount of this discount can and does vary significantly and can therefore have a significant impact on our refining and wholesale marketing gross margin. Manufacturing costs are primarily driven by the cost of energy used by our refineries and the level of maintenance activities.

Index

Our refining and wholesale marketing gross margin for the second quarter and first six months of 2009 was higher when compared to the same periods of 2008, as anticipated based upon the improvement in crack spreads, but the significantly unfavorable sweet/sour differential offset most of the favorable crack spread impact.

Integrated Gas

Our integrated gas strategy is to link stranded natural gas resources with areas where a supply gap is emerging due to declining production and growing demand. 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 2008 world demand. Also included in the financial results of the Integrated Gas segment are costs associated with ongoing development of integrated gas projects, including natural gas technology research.

The impact of lower Henry Hub prices in the second quarter and first six months of 2009 compared to the same periods of 2008 can be seen in decreased earnings from the LNG production facility although the production levels increased over the same periods. Our methanol realizations were also down during the second quarter. This was in line with methanol prices in the U.S. and European markets that averaged approximately $200 per metric tonne in the second quarter of 2009, down from approximately $485 per metric tonne in the same quarter of 2008.

Management's Discussion and Analysis of Results of Operations

Consolidated Results of Operations

Revenues are summarized by segment in the following table:

	Three Months Ended								Six Months Ended
	June 30,								June 30,
(In millions)	2009				2008				2009				2008
E&P		$	2,008			$	3,401			$	3,446			$	6,314
OSM			155				16				277				215
RM&T			11,067				18,975				19,741				34,001
IG			7				21				18				40

Segment revenues			13,237				22,413				23,482				40,570

Elimination of intersegment revenues			(160	)			(359	)			(313	)			(703	)
Gain (loss) on U.K. natural gas contracts			3				(165	)			85				(235	)

Total revenues		$	13,080			$	21,889			$	23,254			$	39,632

Items included in both revenues and costs:

Consumer excise taxes on petroleum products
and merchandise		$	1,226			$	1,295			$	2,400			$	2,511

E&P segment revenues decreased $1,393 million in the second quarter and $2,868 million in the first six months of 2009 from the comparable prior-year periods. The decrease was primarily a result of lower liquid hydrocarbon and natural gas price realizations. Liquid hydrocarbon realizations averaged $55.49 per barrel in the second quarter and $48.70 in the first six months of 2009 compared to $111.90 and $100.07 in the same periods of 2008, while natural gas realizations averaged $2.19 per mcf in the second quarter and $2.51 in the first six months of 2009 compared to $5.08 and $4.79 in the same periods of 2008.

Index

Net sales volumes during the quarter averaged 436 mboepd, compared to 347 mboepd for the same period last year. This 26 percent increase in sales volumes partially offsets the liquid hydrocarbon and natural gas realization decreases previously discussed. Net sales volumes for the first six months of 2009 were 16 percent higher than the comparable prior-year period.

See Supplemental Statistics for information regarding net sales volumes and average realizations by geographic area.

Excluded from E&P segment revenues were gains of $3 million and losses of $165 million for the second quarters of 2009 and 2008 related to natural gas sales contracts in the U.K. that are accounted for as derivative instruments. For the first six months of 2009 and 2008 gains of $85 million and losses of $235 million are excluded from E&P segment revenues.

OSM segment revenues increased $139 million in the second quarter and $62 million in the first six months of 2009 compared to the same periods of 2008, reflecting the impact of the options we entered in the first quarter of 2009 which effectively offset the open put options for the remainder of 2009. The impact of derivatives in 2009 was insignificant compared to pretax derivative losses of $338 million and $386 million in the second quarter and first six months of 2008. Net synthetic crude sales for the second quarter of 2009 were 30 mbpd at an average realized price of $55.02 per barrel compared to 31 mbpd at an average realized price of $116.40 in the same period last year.

See Note 11 to the consolidated financial statements for additional information about derivative instruments.

RM&T segment revenues decreased $7,908 million in the second quarter of 2009 and $14,260 million in the first six months of 2009 from the comparable prior-year periods. The second quarter and the six month decreases compared to prior year primarily reflect lower refined product selling prices.

Sales to related parties decreased as a result of the sale of our interest in Pilot Travel Centers LLC (“PTC”) during the fourth quarter of 2008.

Income from equity method investments decreased $194 million in the second quarter of 2009 and $356 million in the first six months of 2009 from the comparable prior-year periods. Lower commodity prices negatively impacted the earnings of many of our equity investees. The sale of our equity method investment in PTC during the fourth quarter of 2008 also contributed to the decrease.

Net gain on disposal of assets in the second quarter and first six 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 decreased $8,209 million and $15,267 million in the second quarter and first six months of 2009 from the comparable prior-year periods. These decreases resulted primarily from decreases in acquisition costs of crude oil, refinery charge and blendstocks and purchased refined products in the RM&T segment.

Depreciation, depletion and amortization increased in the second quarter and first six months of 2009 from the comparable prior-year periods. The DD&A increase is primarily due to the commencement of production from the Alvheim/Vilje and Neptune developments in mid-year 2008.

Selling, general and administrative expenses decreased in the second quarter and first six months of 2009 from the comparable prior-year periods primarily due to lower variable compensation expenses.

Exploration expenses were $64 million and $126 million in the second quarter and first six months of 2009, including expenses related to dry wells of $8 million and $12 million. Exploration expenses were $130 million and $259 million in the second quarter and first six months of 2008, including expenses related to dry wells of $52 million and $82 million. Other exploration expense in the first six months of 2008 related to the acquisition of seismic data in Indonesia and the evaluation of Canadian in-situ oil sands leases.

Provision for income taxes decreased $95 million and $395 million in the second quarter and first six months of 2009 from the comparable periods of 2008 as a result of decreases in income before income taxes. The effective tax rate is influenced by a variety of factors including the geographic and functional sources of income and the relative magnitude of these sources of income. The change in mix of liquid hydrocarbon and natural gas sales in 2009 from 2008 included more sales in jurisdictions with high tax rates. This change, as well as unfavorable foreign currency remeasurement effects, contributed to the increase in the effective income tax rate in the second quarter and first six months of 2009 as compared to the same periods in 2008. The following is an analysis of the effective income tax rates for the first six months of 2009 and 2008:

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	Six Months Ended June 30,
	2009			2008
Statutory U.S. income tax rate		35	%		35	%
Foreign taxes in excess of federal statutory rate		25			14
State and local income taxes, net of federal income tax effects		1			1
Other tax effects		-			(2	)
Effective income tax rate		61	%		48	%

Discontinued operations reflect the impact of the disposal of our E&P businesses in Ireland to date (see Note 4) and the historical results of those operations, net of tax, for all periods presented.

Segment Results

Segment income is summarized in the following table:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2009			2008			2009			2008
E&P

United States	$	(41	)	$	359		$	(93	)	$	603
International		261			463			398			891

E&P segment		220			822			305			1,494

OSM		2			(157	)		(22	)		(130	)

RM&T		165			158			324			83

IG		13			102			40			201

Segment income		400			925			647			1,648
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(89	)		(57	)		(140	)		(78	)
Foreign currency remeasurement of deferred taxes		(94	)		(16	)		(66	)		35
Gain on dispositions		122			-			122			-
Gain (loss) on U.K. natural gas contracts		2			(84	)		44			(120	)
Discontinued operations		72			6			88			20

Net income	$	413		$	774		$	695		$	1,505

United States E&P income decreased $400 million and $696 million in the second quarter and first six months of 2009 compared to the same periods of 2008. Revenues decreased approximately 60 percent in the second quarter and 58 percent in the first six months of 2009, primarily as a result of lower realizations on both liquid hydrocarbons and natural gas. Liquid hydrocarbon sales volumes were higher in both periods due to sales from the Neptune development. The benefit was offset by the DD&A impact of Neptune production, which was $90 million in the second quarter and $142 million in the first six months of 2009. In the first quarter of 2009, proved reserves for Neptune were revised downward, increasing the DD&A per barrel. Other expenses totaling $28 million in the second quarter of 2009 and $65 million for the six-month period included rig cancellation fees and partial impairment of a natural gas field in east Texas and a Gulf of Mexico pipeline investment.

International E&P income decreased $202 million and $493 million in the second quarter and first six months of 2009 compared to the same periods of 2008. The decrease was primarily due to approximately 50 percent lower liquid hydrocarbon realizations for the second quarter and first six months of 2009 compared to the same periods of 2008. Liquid hydrocarbon sales from the Alvheim/Vilje development which commenced production in June 2008 had a favorable income impact, partially offset by the DD&A related to its production. Lower exploration expenses had a positive income impact.

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OSM segment income increased $159 million and $108 million in the second quarter and first six months of 2009. After-tax derivative losses of $250 million and $286 million were included in reported income for the second quarter and first six months of 2008. Derivative gains or losses in 2009 were not significant. Exclusive of the derivative effects, OSM segment income would reflect decreases in both periods driven by lower synthetic crude realizations, partially offset by lower energy and feedstock costs.

RM&T segment income increased by $7 million and $241 million in the second quarter and first six months of 2009 compared to the same periods of 2008. The increase in the six-month period was primarily due to improvement in our refining and wholesale marketing gross margin which averaged 8.71 cents per gallon in the second quarter of 2009 and 8.33 cents per gallon in the first six months of 2009 compared to 8.35 cents per gallon and 4.2 cents per gallon in the comparable periods of 2008. The gross margin increase was primarily due to improved crack spreads as reflected in the relevant market indicators [Light Louisiana Sweet (LLS) 6-3-2-1 crack spreads] in the Midwest (Chicago) and Gulf Coast, and lower manufacturing expenses in the second quarter 2009 compared to the same quarter last year. The lower manufacturing expenses resulted primarily from lower energy costs. However, these favorable impacts were largely offset by a relatively higher cost of crude oil, primarily driven by a substantially narrower sweet/sour differential, and other feedstock costs, compared to the average prices reflected in the market indicators.

Our refining and wholesale marketing gross margin also included pretax derivative gains of $13 million and losses of $47 million in the second quarter and first six months of 2009 compared to losses of $187 million and $307 million in the second quarter and first six months of 2008.

SSA’s product and merchandise margin improved $29 million in the second quarter and $36 million in the first six months of 2009 compared to the same periods of 2008, reflecting both increases in our retail light products margin per gallon and total sales volumes year over year.

IG segment income decreased $89 million in the second quarter of 2009 and $161 million in the first six months of 2009 compared to the same periods of 2008. The decrease was primarily the result of lower price realizations.

Management’s Discussion and Analysis of Cash Flows and Liquidity

Cash Flows

Net cash provided by operating activities totaled $1,750 million in the first six months of 2009, compared to $2,955 million in the first six months of 2008. Cash provided by operating activities decreased primarily due to lower net income. Working capital changes decreased net cash provided by operations, primarily as a result of increases in pricing from the end of 2008 for our E&P and RM&T receivables.

Net cash used in investing activities totaled $2,619 million in the first six months of 2009, compared to $3,158 million in the first six months of 2008. Our long-term projects, such as the Garyville refinery major expansion, Expansion 1 of the AOSP, exploration offshore Angola and in the Gulf of Mexico, and development of Alvheim, the Bakken Shale resource play and the Droshky prospect, were the most significant investing activities in both periods. For further information regarding capital expenditures by segment, see Supplemental Statistics. In addition, proceeds of $402 million were generated from the sale of assets in 2009.

Net cash provided by financing activities was $1,099 million in the first six months of 2009, compared to $266 million in the first six months of 2008. Sources of cash in the first six months of 2009 included the issuance of $1.5 billion in senior notes, while $1.0 billion in senior notes and $959 in commercial paper were issued in the first six months of 2008. Uses of cash in the first six months of 2008 included the repayment of $400 million 6.85 percent notes, and the payment and termination of the Marathon Oil Canada Corporation (previously Western Oil Sands Inc.) revolving credit facility. Dividends paid were a significant use of cash in both years.

Liquidity and Capital Resources

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations and our $3.0 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.

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Capital Resources

On July 26, 2007, 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 an indeterminate amount of various types of debt and equity securities.

Our senior unsecured debt is currently rated investment grade by Standard and Poor’s Corporation, Moody’s Investor Services, Inc. and Fitch Ratings with ratings of BBB+, Baa1, and BBB+.

Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 25 percent at June 30, 2009, compared to 22 percent at December 31, 2008. This includes $473 million of debt that is serviced by United States Steel.

	June 30,			December 31,
(In millions)	2009			2008
Long-term debt due within one year	$	103		$	98
Long-term debt		8,518			7,087

Total debt	$	8,621		$	7,185

Cash	$	1,496		$	1,285
Trusteed funds from revenue bonds	$	-		$	16
Equity	$	21,813		$	21,409

Calculation:

Total debt	$	8,621		$	7,185
Minus cash		1,496			1,285
Minus trusteed funds from revenue bonds		-			16

Total debt minus cash	$	7,125		$	5,884

Total debt		8,621			7,185
Plus equity		21,813			21,409
Minus cash		1,496			1,285
Minus trusteed funds from revenue bonds		-			16

Total debt plus equity minus cash	$	28,938		$	27,293

Cash-adjusted debt-to-capital ratio		25	%		22	%

Capital Requirements

On July 29, 2009, our Board of Directors declared a dividend of 24 cents per share, payable September 10, 2009, to stockholders of record at the close of business on August 19, 2009.

Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion. As of June 30, 2009, 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

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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

As of June 30, 2009, our consolidated contractual cash obligations have increased by $1,362 million from December 31, 2008. Short and long-term debt increased by $1,459 million primarily due to the issuance of $1.5 billion in senior notes as previously discussed. There have been no other significant changes to our obligations to make future payments under existing contracts subsequent to December 31, 2008. The portion of our obligations to make future payments under existing contracts that have been assumed by United States Steel has not changed significantly subsequent to December 31, 2008.

Receivable from United States Steel

We remain obligated (primarily or contingently) for $501 million of certain debt and other financial arrangements for which United States Steel Corporation (“United States Steel”) has assumed responsibility for repayment (see the USX Separation in Item 1. of our 2008 Annual Report on 10-K). In its Form 10-Q for the six months ended June 30, 2009, United States Steel management stated that it believes its liquidity will be adequate to satisfy its obligations for the foreseeable future. During the three months ended June 30, 2009 United States Steel undertook certain plans and actions designed to preserve and enhance its liquidity and financial flexibility, including the sale of its common stock and issuance of senior convertible notes due 2014 for net proceeds of approximately $1,496 million. United States Steel’s senior unsecured debt ratings are BB by Standard and Poor’s Corporation, Ba3 by Moody’s Investment Service, Inc. and BBB- by Fitch Ratings.

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 or if demand for our products is lowered because of these additional costs, 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, operational efficiencies, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil, refined products and feedstocks.

We disclosed in our 2008 Annual Report on Form 10-K, that legislation and regulations pertaining to climate change and greenhouse gas emissions have the potential to impact us and that we were awaiting the U.S. Environmental Protection Agency’s (“EPA”) actions upon the remand of the U.S. Supreme Court decision in Massachusetts v. EPA, which could have impacts on a number of air permitting and environmental regulatory programs. On April 17, 2009, the EPA issued a proposed finding that greenhouse gases contribute to air pollution that may endanger public health or welfare. Action by EPA on this finding is expected later this year and should EPA finalize this finding, standards or regulations limiting greenhouse gas emissions from mobile sources would then have to be developed. EPA has also proposed greenhouse gas emission reporting rules which it plans to finalize to be effective for calendar year 2010. In May 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009 (H.R. 2454) (commonly referred to as the “Waxman-Markey Bill”) which includes a cap and trade system to reduce carbon emissions in the United States. This bill will now be considered by the U.S. Senate.

Adverse impacts to our business if a cap and trade system as in the Waxman-Markey Bill or some other comprehensive greenhouse gas legislation is enacted include increased compliance costs, permitting delays, added costs to the products we produce, an increased cost of carbon, and reduced demand for crude oil or certain refined products. The extent and magnitude of such adverse impacts cannot be reliably or accurately estimated at this time. Because these requirements have not been finalized, uncertainty exists with respect to the additional measures or legislation being considered and the time frames for compliance.

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We have estimated that we may spend approximately $1 billion over a six-year period that began in 2008 to comply with Mobile Source Air Toxics II (“MSAT II”) regulations relating to benzene content in refined products. We have not finalized our strategy or cost estimates to comply with these requirements. Our actual MSAT II expenditures since inception have totaled $145 million through June 30, 2009, with $42 million in the second quarter of 2009. We expect 2009 spending will be approximately $220 million. The cost estimates are forward-looking statements and are subject to change as further work is completed in 2009.

We previously discussed in our 2008 Annual Report on Form 10-K that the Texas Commission on Environmental Quality (“TCEQ”) issued a notice of enforcement relating to benzene waste national emission standards for hazardous air pollutants inspection at the Texas City Refinery. We resolved this matter in the second quarter of 2009 with an order including a civil penalty of $46,000. We are also required to continue to operate an ambient air monitoring system for an additional six months as a supplemental environmental project in settlement of this enforcement action brought by the TCEQ. We have also previously mentioned an EPA notice of violation for oil spills at the Catlettsburg Refinery in 2004 and 2008. We resolved this matter in the second quarter of 2009 through an order and civil penalty of $118,000.

There have been no other significant changes to our environmental matters subsequent to December 31, 2008.

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.

Effective January 1, 2009, we adopted SFAS No. 157 with respect to nonfinancial assets and liabilities. SFAS No. 157 defines fair value, establishes a fair value framework for measuring fair value and expands disclosures about fair value measurements. It does not require us to make any new fair value measurements, but rather establishes a fair value hierarchy that prioritizes the inputs to the valuation techniques to measure fair value. See Note 10 of the consolidated financial statements for disclosures regarding our fair value measurements.

There have been no other changes to our critical accounting estimates subsequent to December 31, 2008.

Accounting Standards Not Yet Adopted

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holds a variable interest in a variable interest entity. SFAS No. 167 will be applied prospectively beginning in the first quarter of 2010, and for all interim and annual periods thereafter. Earlier application of SFAS No. 167 is prohibited. We are currently evaluating the provisions of this statement.

Permit companies to disclose their probable and possible reserves on a voluntary basis. Under current rules, proved reserves were the only reserves allowed in the disclosures.

Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.

Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

Replace the existing "certainty" test for areas beyond one offsetting drilling unit from a productive well with a "reasonable certainty" test.

Require separate disclosure of reserves in foreign countries if they represent more than 15 percent of total proved reserves, based on barrels of oil equivalents.

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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 2008 Annual Report on Form 10-K.

Disclosures about how derivatives are reported in our consolidated financial statements and how the fair values of our derivative instruments are measured may be found in Note 10 and 11 to the consolidated financial statements.

Item 4. Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective. During the quarter ended June 30, 2009, 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.

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MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions, except as noted)	2009			2008			2009			2008

Segment Income (Loss)
Exploration and Production
United States	$	(41	)	$	359		$	(93	)	$	603
International		261			463			398			891
E&P segment		220			822			305			1,494
Oil Sands Mining		2			(157	)		(22	)		(130	)
Refining, Marketing and Transportation		165			158			324			83
Integrated Gas		13			102			40			201
Segment income		400			925			647			1,648

Items not allocated to segments, net of income taxes		13			(151	)		48			(143	)
Net income	$	413		$	774		$	695		$	1,505
Capital Expenditures
Exploration and Production	$	617		$	839		$	990		$	1,596
Oil Sands Mining		281			262			567			510
Refining, Marketing and Transportation		713			702			1,373			1,213
Integrated Gas		1			-			1			1
Discontinued Operations		31			35			47			53
Corporate		7			7			8			9
Total	$	1,650		$	1,845		$	2,986		$	3,382
Exploration Expenses
United States	$	31		$	55		$	65		$	105
International		33			75			61			154
Total	$	64		$	130		$	126		$	259
E&P Operating Statistics
Net Liquid Hydrocarbon Sales (mbpd)
United States		64			63			65			63

Europe		112			38			92			31
Africa		101			81			93			92
Total International		213			119			185			123
Worldwide		277			182			250			186
Net Natural Gas Sales (mmcfd) (a)
United States		365			431			395			456

Europe		151			160			155			170
Africa		439			398			436			396
Total International		590			558			591			566
Worldwide Continuing Operations		955			989			986			1,022
Discontinued Operations		3			15			33			44
Worldwide		958			1,004			1,019			1,066
Total Worldwide Sales (mboepd)
Continuing operations		436			347			415			357
Discontinued operations		1			3			6			7
Worldwide		437			350			421			364

(a)	Includes natural gas acquired for injection and subsequent resale of 18 mmcfd and 25 mmcfd in the second quarters of 2009 and 2008, and 21 mmcfd and 31 mmcfd for the first six months of 2009 and 2008.

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MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions, except as noted)	2009		2008		2009		2008

E&P Operating Statistics (continued)
Average Realizations (b)
Liquid Hydrocarbons (per bbl)
United States	$	53.25	$	109.85	$	44.84	$	96.96

Europe		60.91		121.96		55.71		111.54
Africa		50.90		108.70		44.45		98.33
Total International		56.16		112.99		50.06		101.66
Worldwide	$	55.49	$	111.90	$	48.70	$	100.07

Natural Gas (per mcf)
United States	$	3.60	$	8.66	$	4.08	$	7.70

Europe		4.43		7.43		4.90		7.56
Africa(c)		0.25		0.25		0.25		0.25
Total International		1.32		2.31		1.47		2.44
Worldwide Continuing Operations		2.19		5.08		2.51		4.79
Discontinued Operations		7.49		12.37		8.54		8.83
Worldwide	$	2.21	$	5.19	$	2.71	$	4.95

OSM Operating Statistics
Net Bitumen Production (mbpd)		26		24		25		24
Net Synthetic Crude Sales (mbpd)		30		31		31		31
Synthetic Crude Average Realization (per bbl)	$	55.02	$	116.40	$	46.63	$	102.70

RM&T Operating Statistics
Refinery Runs (mbpd)
Crude oil refined		959		1,023		905		934
Other charge and blend stocks		199		180		210		207
Total		1,158		1,203		1,115		1,141
Refined Product Yields (mbpd)
Gasoline		659		607		638		604
Distillates		319		367		314		326
Propane		23		23		22		22
Feedstocks and special products		73		116		62		108
Heavy fuel oil		25		23		24		27
Asphalt		75		86		70		73
Total		1,174		1,222		1,130		1,160

Refined Products Sales Volumes (mbpd) (d)		1,371		1,369		1,329		1,324
Refining and Wholesale Marketing Gross
Margin (per gallon) (e)	$	0.0871	$	0.0835	$	0.0833	$	0.0420
Speedway SuperAmerica
Retail outlets		1,611		1,625		-		-
Gasoline and distillate sales (millions of gallons)		806		788		1,590		1,580
Gasoline and distillate gross margin (per gallon)	$	0.1051	$	0.0862	$	0.1059	$	0.1005
Merchandise sales	$	809	$	722	$	1,499	$	1,369
Merchandise gross margin	$	192	$	181	$	370	$	344

IG Operating Statistics
Net Sales (mtpd) (f)
LNG		6,611		6,402		6,690		6,657
Methanol		1,362		1,188		1,258		1,159

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

(c)

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

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

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

(f)	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.

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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 settled a number of lawsuits pertaining to methyl tertiary-butyl ether (“MTBE”) in 2008. Presently, we are a defendant, along with other refining companies, in 26 cases arising in four states alleging damages for MTBE contamination. Of the 26 cases in which we remain a defendant, 20 are pending in New York, 4 in Florida and 1 in Illinois. These 25 cases allege damages to water supply wells, similar to the damages claimed in the cases that were settled in 2008. In the other remaining case, the State of New Jersey is seeking natural resources damages allegedly resulting from contamination of groundwater by MTBE. This is the only MTBE contamination case in which we are a defendant and natural resources damages are sought. Thirteen of the 20 New York cases have been dismissed from the multi-district litigation (“MDL”) and re-filed in the state courts of Nassau and Suffolk Counties, New York. The remaining cases, like the cases that were settled in 2008, are consolidated in the MDL in the Southern District of New York for pretrial proceedings. We are vigorously defending these cases. We have engaged in settlement discussions related to the majority of the cases. We do not expect our share of liability, if any, for the remaining cases to significantly impact our consolidated results of operations, financial position or cash flows. We voluntarily discontinued producing MTBE in 2002.

Natural Gas Royalty Litigation

Product Contamination Litigation

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. See the discussion of such risks and uncertainties under Item 1A. Risk Factors in our 2008 Annual Report on Form 10-K.

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

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

04/01/09 – 04/30/09	4,008	$26.25	-	$2,080,366,711
05/01/09 – 05/31/09	24,109	$30.29	-	$2,080,366,711
06/01/09 – 06/30/09	81,493 (c)	$32.22	-	$2,080,366,711
Total	109,610	$31.58	-

(a)	64,098 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.

(b)

Under the terms of the transaction whereby we acquired the minority interest in Marathon Petroleum Company and other businesses from Ashland, Ashland shareholders have the right to receive 0.2364 shares of Marathon common stock for each share of Ashland common stock owned as of June 30, 2005 and cash in lieu of fractional based on a value of $52.17 per share. In the second quarter of 2009, we acquired 4 shares due to acquisition share exchanges and Ashland share transfers pending at the closing of the transaction.

(c)

45,508 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.

(d)

We announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion. As of June 30, 2009, 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.

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Item 4. Submission of Matters to a Vote of Security Holders

The annual meeting of stockholders was held on April 29, 2009. In connection with the meeting, proxies were solicited pursuant to the Securities Exchange Act of 1934. The following are the voting results on proposals considered and voted upon at the meeting, all of which were described in Marathon's 2009 Proxy Statement.

1.	Votes regarding the persons elected to serve as directors for a term expiring in 2010 were as follows:

NOMINEE	VOTES FOR	VOTES AGAINST	VOTES ABSTAINED
Charles F. Bolden, Jr.	582,957,778	2,906,331	1,542,544
Gregory H. Boyce	582,607,120	3,266,860	1,532,673
Clarence P. Cazalot, Jr.	582,892,926	3,064,791	1,448,936
David A. Daberko	580,993,631	4,901,840	1,511,182
William L. Davis	582,836,862	3,048,824	1,520,966
Shirley Ann Jackson	527,111,663	58,878,633	1,415,772
Philip Lader	568,077,303	17,773,084	1,556,266
Charles R. Lee	568,527,576	17,371,114	1,506,272
Michael E. J. Phelps	570,991,900	14,531,273	1,883,480
Dennis H. Reilley	573,447,332	5,131,342	1,465,825
Seth E. Schofield	576,694,732	9,305,120	1,406,802
John W. Snow	581,055,920	4,895,700	1,455,033
Thomas J. Usher	576,987,727	9,013,170	1,405,757

2.	PricewaterhouseCoopers LLP was ratified as our independent registered public accounting firm for 2009. The voting results were as follows:

VOTES FOR	VOTES AGAINST	VOTES ABSTAINED
580,231,304	6,199,982	974,783

3.	The stockholder proposal requesting that the Board of Directors amend our By-laws and any other appropriate governing documents to give holders of 10% of Marathon’s outstanding common stock the power to call a special stockholder meeting was approved. The voting results were as follows:

VOTES FOR	VOTES AGAINST	VOTES ABSTAINED	BROKER NON-VOTES
265,373,133	236,865,205	1,113,986	84,054,330

The stockholder proposal requesting that the Board of Directors adopt a policy that provides stockholders the opportunity at each stockholder meeting to vote on an advisory management resolution to ratify the compensation of the named executive officers was defeated. Abstentions are counted as votes present and entitled to vote and have the same effect as votes against this proposal. The voting results were as follows:

VOTES FOR	VOTES AGAINST	VOTES ABSTAINED	BROKER NON-VOTES
250,583,568	248,401,398	4,367,339	84,054,349

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Item 6. Exhibits

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

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SIGNATURES

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

August 6, 2009	MARATHON OIL CORPORATION

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