Edgar Filing: MARATHON OIL CORP

mro10-q09302008.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended September 30, 2008

[ ]	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 ü No

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

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

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

There were 705,576,258 shares of Marathon Oil Corporation common stock outstanding as of October 31, 2008.

MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended September 30, 2008

		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		17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		29
Item 4.	Controls and Procedures		32
	Supplemental Statistics		33
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		35
Item 1A.	Risk Factors		36
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		36
Item 6.	Exhibits		37
	Signatures		38

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

Part I - Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Income (Unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions, except per share data)	2008		2007		2008		2007
Revenues and other income:

Sales and other operating revenues (including	$	22,477	$	16,347	$	60,983	$	45,221
consumer excise taxes)
Sales to related parties		637		415		1,865		1,146
Income from equity method investments		270		170		735		394
Net gain on disposal of assets		15		2		37		20
Other income		47		20		151		62

Total revenues and other income		23,446		16,954		63,771		46,843
Costs and expenses:
Cost of revenues (excludes items below)		16,992		12,951		49,432		34,358
Purchases from related parties		244		104		609		240
Consumer excise taxes		1,273		1,352		3,784		3,856
Depreciation, depletion and amortization		597		409		1,552		1,198
Selling, general and administrative expenses		351		336		1,012		950
Other taxes		126		95		376		286
Exploration expenses		109		88		368		264

Total costs and expenses		19,692		15,335		57,133		41,152

Income from operations		3,754		1,619		6,638		5,691

Net interest and other financing income (costs)		(53)		19		(54)		58
Gain on foreign currency derivative instruments		-		120		-		120
Loss on early extinguishment of debt		-		(11)		-		(14)
Minority interests in loss of Equatorial Guinea
LNG Holdings Limited		-		-		-		3

Income from continuing operations before
income taxes		3,701		1,747		6,584		5,858

Provision for income taxes		1,637		726		3,015		2,578

Income from continuing operations		2,064		1,021		3,569		3,280

Discontinued operations		-		-		-		8

Net income	$	2,064	$	1,021	$	3,569	$	3,288

Per Share Data

Basic:
Income from continuing operations	$	2.92	$	1.50	$	5.03	$	4.80
Discontinued operations	$	-	$	-	$	-	$	0.01
Net income	$	2.92	$	1.50	$	5.03	$	4.81

Diluted:
Income from continuing operations	$	2.90	$	1.49	$	5.00	$	4.76
Discontinued operations	$	-	$	-	$	-	$	0.01
Net income	$	2.90	$	1.49	$	5.00	$	4.77

Dividends	$	0.24	$	0.24	$	0.72	$	0.68

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)

	September 30,		December 31,
(In millions, except per share data)	2008		2007
Assets
Current assets:
Cash and cash equivalents	$	1,479	$	1,199
Receivables, less allowance for doubtful accounts of $4 and $3		6,094		5,818
Receivables from United States Steel		23		22
Receivables from related parties		115		79
Inventories		4,446		3,277
Other current assets		216		192

Total current assets		12,373		10,587

Equity method investments		2,827		2,630
Receivables from United States Steel		469		485
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $16,152 and $14,857		28,129		24,675
Goodwill		2,887		2,899
Intangible assets, less accumulated amortization of $93 and $80		279		288
Other noncurrent assets		1,942		1,182

Total assets	$	48,906	$	42,746
Liabilities
Current liabilities:
Short-term debt	$	1,290	$	-
Accounts payable and accrued liabilities		8,975		8,281
Payables to related parties		40		44
Payroll and benefits payable		364		417
Accrued taxes		992		712
Deferred income taxes		397		547
Accrued interest		131		128
Long-term debt due within one year		88		1,131

Total current liabilities		12,277		11,260

Long-term debt		7,074		6,084
Deferred income taxes		4,873		3,389
Defined benefit postretirement plan obligations		1,205		1,092
Asset retirement obligations		1,135		1,131
Payable to United States Steel		4		5
Deferred credits and other liabilities		411		562

Total liabilities		26,979		23,523

Commitments and contingencies

Stockholders’ Equity
Preferred stock – 5 million shares issued, 3 million and 5 million shares
outstanding (no par value, 6 million shares authorized)		-		-
Common stock:
Issued – 767 million and 765 million shares (par value $1 per share,
1.1 billion shares authorized)		767		765
Securities exchangeable into common stock – 5 million shares issued,
3 million and 5 million shares outstanding (no par value, unlimited
shares authorized)		-		-
Held in treasury, at cost – 61 million and 55 million shares		(2,722)		(2,384)
Additional paid-in capital		6,686		6,679
Retained earnings		17,470		14,412
Accumulated other comprehensive loss		(274)		(249)

Total stockholders' equity		21,927		19,223

Total liabilities and stockholders' equity	$	48,906	$	42,746

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)


	Nine Months Ended
	September 30,
(In millions)	2008		2007
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	3,569	$	3,288
Adjustments to reconcile net income to net cash provided by operating activities:
Loss on early extinguishment of debt		-		14
Income from discontinued operations		-		(8)
Deferred income taxes		314		12
Minority interests in loss of Equatorial Guinea LNG Holdings Limited		-		(3)
Depreciation, depletion and amortization		1,552		1,198
Pension and other postretirement benefits, net		115		68
Exploratory dry well costs and unproved property impairments		154		109
Net gain on disposal of assets		(37)		(20)
Equity method investments, net		(139)		(123)
Changes in the fair value of U.K. natural gas contracts		37		111
Changes in:
Current receivables		(287)		(1,190)
Inventories		(1,173)		(1,444)
Current accounts payable and accrued liabilities		703		988
All other, net		(1)		(49)
Net cash provided by operating activities		4,807		2,951
Investing activities:
Capital expenditures		(5,168)		(2,725)
Disposal of assets		68		51
Trusteed funds - withdrawals		402		163
Investments - loans and advances		(104)		(88)
Investments - repayments of loans and return of capital		18		35
Deconsolidation of Equatorial Guinea LNG Holdings Limited		-		(37)
All other, net		(16)		(8)
Net cash used in investing activities		(4,800)		(2,609)
Financing activities:
Short term debt, net		1,288		-
Borrowings		1,248		2,071
Debt issuance costs		(7)		(19)
Debt repayments		(1,331)		(541)
Issuance of common stock		9		23
Purchases of common stock		(402)		(800)
Excess tax benefits from stock-based compensation arrangements		8		25
Dividends paid		(511)		(465)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited		-		39
Net cash provided by financing activities		302		333
Effect of exchange rate changes on cash		(29)		9
Net increase in cash and cash equivalents		280		684
Cash and cash equivalents at beginning of period		1,199		2,585
Cash and cash equivalents at end of period	$	1,479	$	3,269

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements (Unaudited)

1. Basis of Presentation

These consolidated financial statements are unaudited but, 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 2008 classifications. These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Marathon Oil Corporation (“Marathon” or the “Company”) 2007 Annual Report on Form 10-K. The results of operations for the quarter and nine-months ended September 30, 2008 are not necessarily indicative of the results to be expected for the full year.

2. New Accounting Standards

In April 2007, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FASB Interpretation No. 39 (“FSP FIN 39-1”), “Offsetting of Amounts Related to Certain Contracts”, which allows a party to a master netting agreement to offset the fair value amounts related to the right to reclaim collateral against the fair value amounts recognized for derivative instruments. Such treatment was consistent with Marathon’s accounting policy; therefore, adoption of FSP FIN No. 39-1 effective January 1, 2008, did not have any effect on our consolidated financial position.

In February 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure at fair value many financial instruments and certain other items that are not currently required to be measured at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income. The statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. We did not elect the fair value option when this standard became effective on January 1, 2008.

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. 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 defers 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. Effective January 1, 2008, we adopted SFAS No. 157, except for measurements of those nonfinancial assets and liabilities subject to the one-year deferral, which for us includes impairments of goodwill, intangible assets and other long-lived assets, and initial measurement of asset retirement obligations, asset exchanges, business combinations and partial sales of proved properties. Adoption did not have a significant effect on our consolidated results of operations or financial position. The additional disclosures regarding assets and liabilities recorded at fair value and measured under SFAS No. 157 are presented in Note 11.

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,” (“FSP FAS 157-3”) 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 is effective upon issuance, including prior periods for which financial statements have not been issued, and any revisions resulting from a change in the valuation technique or its application shall 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.

Notes to Consolidated Financial Statements (Unaudited)

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 and restricted shares, provided the effect is not antidilutive.

	Three Months Ended September 30,
	2008					2007
(In millions, except per share data)	Basic		Diluted			Basic	Diluted

Net income	$	2,064	$	2,064	$	1,021	$	1,021

Weighted average common shares outstanding		707		707		680		680
Effect of dilutive securities		-		4		-		5
Weighted average common shares, including
dilutive effect		707		711		680		685

Per share:
Net income	$	2.92	$	2.90	$	1.50	$	1.49

	Nine Months Ended September 30,
	2008					2007
(In millions, except per share data)	Basic		Diluted			Basic	Diluted

Income from continuing operations	$	3,569	$	3,569	$	3,280	$	3,280
Discontinued operations		-		-		8		8
Net income	$	3,569	$	3,569	$	3,288	$	3,288

Weighted average common shares outstanding		710		710		684		684
Effect of dilutive securities		-		4		-		5
Weighted average common shares, including
dilutive effect		710		714		684		689

Per share:
Income from continuing operations	$	5.03	$	5.00	$	4.80	$	4.76
Discontinued operations	$	-	$	-	$	0.01	$	0.01
Net income	$	5.03	$	5.00	$	4.81	$	4.77

The per share calculations above exclude 5.5 million stock options for the third quarter and the first nine months of 2008 and 3.0 million stock options for the third quarter and the first nine months of 2007, as they were antidilutive.

4. Acquisition

On October 18, 2007, we completed the acquisition of all the outstanding shares of Western Oil Sands Inc. (“Western”) for cash and securities of $5,833 million. Subsequent to the transaction, Western’s name was changed to Marathon Oil Canada Corporation. The acquisition was accounted for under the purchase method of accounting and, as such, our results of operations include Western’s results from October 18, 2007. Western’s oil sands mining and bitumen upgrading operations are reported as a separate Oil Sands Mining segment, while its ownership interests in leases where in-situ recovery techniques are expected to be utilized are included in the Exploration and Production segment.

Notes to Consolidated Financial Statements (Unaudited)

The following shows our unaudited pro forma data as if the acquisition of Western had been consummated at the beginning of each period presented. The pro forma data is based on historical information and does not reflect the actual results that would have occurred nor is it indicative of future results of operations.

	Three Months Ended September 30, 2007			Nine Months Ended September 30, 2007
(In millions, except per share amounts)	Three Months Ended September 30, 2007			Nine Months Ended September 30, 2007
Revenues and other income		$	17,246		$	47,670
Income from continuing operations			1,086			3,102
Net income			1,086			3,110
Per share data:
Income from continuing operations - basic		$	1.52		$	4.32
Income from continuing operations - diluted		$	1.51		$	4.29
Net income - basic		$	1.52		$	4.33
Net income - diluted		$	1.51		$	4.30

5. Segment Information

We have four reportable operating segments:

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.

(In millions)		E&P		OSM		RM&T		IG		Total
Three Months Ended September 30, 2008
Revenues:
Customer	$	3,584	$	532	$	18,139	$	24	$	22,279
Intersegment (a)		278		68		1		-		347
Related parties		11		-		626		-		637
Segment revenues		3,873		600		18,766		24		23,263
Elimination of intersegment revenues		(278)		(68)		(1)		-		(347)
Gain on U.K. natural gas contracts		198		-		-		-		198
Total revenues	$	3,793	$	532	$	18,765	$	24	$	23,114
Segment income	$	939	$	288	$	771	$	65	$	2,063
Income from equity method investments		65		-		115		90		270
Depreciation, depletion and amortization (b)		402		37		148		1		588
Income tax provision (b)		991		98		464		34		1,587
Capital expenditures (c)		738		271		765		3		1,777

Notes to Consolidated Financial Statements (Unaudited)

(In millions)		E&P		OSM		RM&T		IG		Total
Three Months Ended September 30, 2007
Revenues:
Customer	$	2,318	$	-	$	14,088	$	64	$	16,470
Intersegment (a)		116		-		115		-		231
Related parties		13		-		402		-		415
Segment revenues		2,447		-		14,605		64		17,116
Elimination of intersegment revenues		(116)		-		(115)		-		(231)
Loss on U.K. natural gas contracts		(123)		-		-		-		(123)
Total revenues	$	2,208	$	-	$	14,490	$	64	$	16,762
Segment income	$	479	$	-	$	482	$	52	$	1,013
Income from equity method investments		60		-		44		66		170
Depreciation, depletion and amortization (b)		254		-		146		1		401
Income tax provision(b)		544		-		262		8		814
Capital expenditures (c)(d)		582		-		430		2		1,014

(In millions)		E&P		OSM		RM&T		IG		Total
Nine Months Ended September 30, 2008
Revenues:
Customer	$	9,586	$	631	$	50,739	$	64	$	61,020
Intersegment (a)		663		184		203		-		1,050
Related parties		40		-		1,825		-		1,865
Segment revenues		10,289		815		52,767		64		63,935
Elimination of intersegment revenues		(663)		(184)		(203)		-		(1,050)
Loss on U.K. natural gas contracts		(37)		-		-		-		(37)
Total revenues	$	9,589	$	631	$	52,564	$	64	$	62,848
Segment income	$	2,451	$	158	$	854	$	266	$	3,729
Income from equity method investments		204		-		186		345		735
Depreciation, depletion and amortization (b)		972		104		446		3		1,525
Income tax provision (b)		2,532		53		527		118		3,230
Capital expenditures (c)(d)		2,387		781		1,978		4		5,150

Notes to Consolidated Financial Statements (Unaudited)

(In millions)		E&P		OSM		RM&T		IG		Total
Nine Months Ended September 30, 2007
Revenues:
Customer	$	6,041	$	-	$	39,103	$	188	$	45,332
Intersegment (a)		372		-		199		-		571
Related parties		24		-		1,122		-		1,146
Segment revenues		6,437		-		40,424		188		47,049
Elimination of intersegment revenues		(372)		-		(199)		-		(571)
Loss on U.K. natural gas contracts		(111)		-		-		-		(111)
Total revenues	$	5,954	$	-	$	40,225	$	188	$	46,367
Segment income	$	1,264	$	-	$	2,073	$	83	$	3,420
Income from equity method investments		165		-		116		113		394
Depreciation, depletion and amortization (b)		733		-		436		5		1,174
Minority interest in loss of subsidiary		-		-		-		3		3
Income tax provision (b)		1,438		-		1,181		20		2,639
Capital expenditures (c)(d)		1,623		-		981		93		2,697

(a)

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

(b)

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.

(c)

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

(d)

Through April 2007, Integrated Gas segment capital expenditures include Equatorial Guinea LNG Holdings Limited (“EGHoldings”) at 100 percent. Effective May 1, 2007, we no longer consolidate EGHoldings and our investment in EGHoldings is accounted for under the equity method of accounting; therefore, EGHoldings’ capital expenditures subsequent to April 2007 are not included in our capital expenditures.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008			2007	2008		2007
Segment income	$	2,063	$	1,013	$	3,729	$	3,420
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(100)		3		(141)		(149)
Gain (loss) on U.K. natural gas contracts		101		(62)		(19)		(56)
Gain on foreign currency derivative instruments (a)		-		74		-		74
Loss on early extinguishment of debt		-		(7)		-		(9)
Discontinued operations(b)		-		-		-		8
Net income	$	2,064	$	1,021	$	3,569	$	3,288

(a)

Represents unrealized gains in the third quarter 2007 on foreign currency derivative instruments entered into to limit our exposure to the Canadian dollar exchange rate related to the cash portion of the purchase prices for Western Oil Sand Inc.

(b)

The Russian businesses sold in June 2006 were accounted for as discontinued operations. Adjustments to the sales price were completed in 2007 and an additional gain on the sale of $8 million ($13 million before income taxes) was recognized. See our 2007 Form 10-K for further information.

Notes to Consolidated Financial Statements (Unaudited)

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008			2007	2008		2007
Total revenues	$	23,114	$	16,762	$	62,848	$	46,367
Less: Sales to related parties		637		415		1,865		1,146
Sales and other operating revenues (including
consumer excise taxes)	$	22,477	$	16,347	$	60,983	$	45,221

6. Defined Benefit Postretirement Plans

The following summarizes the components of net periodic benefit cost:

	Three Months Ended September 30,
	Pension Benefits				Other Benefits
(In millions)	2008		2007		2008		2007
Service cost	$	37	$	35	$	5	$	6
Interest cost		40		36		11		11
Expected return on plan assets		(42)		(38)		-		-
Amortization:
– prior service cost (credit)		3		3		(2)		(2)
– actuarial loss		8		9		-		2
Net periodic benefit cost	$	46	$	45	$	14	$	17

	Nine Months Ended September 30,
	Pension Benefits				Other Benefits
(In millions)	2008		2007		2008		2007
Service cost	$	110	$	105	$	14	$	17
Interest cost		120		107		33		33
Expected return on plan assets		(126)		(115)		-		-
Amortization:
– prior service cost (credit)		10		10		(6)		(7)
– actuarial loss		23		27		1		6
Net periodic benefit cost	$	137	$	134	$	42	$	49

During the first nine months of 2008, we made contributions of $37 million to our funded international pension plans. We expect to make additional contributions of an estimated $32 million to our funded pension plans over the remainder of 2008, with $29 million of that made in October 2008. Contributions made from our general assets to cover current benefit payments related to unfunded pension and other postretirement benefit plans were $14 million and $24 million during the first nine months of 2008.

Notes to Consolidated Financial Statements (Unaudited)

7. Income Taxes

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

	Nine Months Ended September 30,
	2008		2007
Statutory U.S. income tax rate	35	%	35	%
Effects of foreign operations, including foreign tax credits	11		8
State and local income taxes, net of federal income tax effects	1		2
Other tax effects	(1)		(1)
Effective income tax rate for continuing operations	46	%	44	%

The geographic sources of income and related tax expense contributed to the increase in the effective income tax rate in the first nine months of 2008 when compared to the same period in 2007. The estimated 2008 effective tax rate is reduced by approximately 4 percent by the reversal of previously recorded valuation allowances on Norwegian net operating losses.

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 September 30, 2008, 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 - 2007
	Equatorial Guinea	2006 - 2007
	Libya	2006 - 2007
	United Kingdom	2005 - 2007

(a)

Includes federal and state jurisdictions.

8. Comprehensive Income

The following sets forth comprehensive income for the periods indicated:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
Net income	$	2,064	$	1,021	$	3,569	$	3,288
Other comprehensive income, net of taxes:
Defined benefit postretirement plans (a)		22		7		2		(29)
Other		(26)		10		(27)		12

Comprehensive income	$	2,060	$	1,038	$	3,544	$	3,271

(a)

During the first six months of 2008 and 2007, changes were made to the estimates used to measure certain assumptions necessary in determining the funded status of our postretirement benefit plans as of December 31, 2007 and 2006.

Notes to Consolidated Financial Statements (Unaudited)

9. Inventories

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

	September 30,		December 31,
(In millions)	2008		2007
Liquid hydrocarbons, natural gas and bitumen	$	2,303	$	1,203
Refined products and merchandise		1,847		1,792
Supplies and sundry items		296		282
Total, at cost	$	4,446	$	3,277

10. Property, Plant and Equipment

Exploratory well costs capitalized greater than one year after completion of drilling were $54 million as of September 30, 2008, a decrease of $46 million from December 31, 2007, primarily due to the transfer of the Ozona prospect exploratory wells in progress. A well on the Ozona prospect was re-entered and production casing was set in the second quarter of 2008. In October 2008, the development of the Ozona prospect was authorized by our board of directors.

11. Fair Value Measurements

As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

SFAS No. 157 does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows.

· Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

· Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

· Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

We use a market or income approach for recurring fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Notes to Consolidated Financial Statements (Unaudited)

The following table presents net financial assets (liabilities) accounted for at fair value on a recurring basis as of September 30, 2008:

(In millions)		Level 1		Level 2		Level 3		Total
Derivative Instruments:
Commodity	$	44	$	6	$	(495)	$	(445)
Interest rate		-		-		3		3
Foreign currency		-		(9)		1		(8)
Total at fair value	$	44	$	(3)	$	(491)	$	(450)

Deposits of $11 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 include a $328 million liability related to two U.K. natural gas sales contracts that are accounted for as derivative instruments and a $131 million liability for 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 and the U.K. forward natural gas strip price to the expected sales volumes for the shorter of the remaining contract term or 18 months. 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.

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 nine months ended September 30, 2008.

		Three Months Ended September 30, 2008
(In millions)		Three Months Ended September 30, 2008
Beginning balance	$	(988)
Total realized and unrealized losses:
Included in net income		445
Purchases, sales, issuances and settlements, net		52
Ending balance	$	(491)

		Nine Months Ended September 30, 2008
(In millions)		Nine Months Ended September 30, 2008
Beginning balance	$	(356)
Total realized and unrealized losses:
Included in net income		(235)
Included in other comprehensive income		1
Purchases, sales, issuances and settlements, net		99
Ending balance	$	(491)

The change in unrealized losses included in net income related to instruments held at September 30, 2008 was a reduction of $413 million and an increase of $126 million for the third quarter and first nine months of 2008. 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

Notes to Consolidated Financial Statements (Unaudited)

capital expenditures. Amounts related to foreign currency derivatives designated as hedges of future capital expenditures accumulate in other comprehensive income and are amortized to depletion, depreciation and amortization on a units-of-production basis over the life of the capital asset.

12. Debt

At September 30, 2008, we had $886 million of commercial paper, at a weighted average interest rate of 5.9 percent, outstanding under our U.S. commercial paper program which is supported by our $3.0 billion revolving credit facility. An additional $404 million in borrowings was outstanding under the revolving credit facility at a weighted average interest rate of 5.0 percent. Neither commercial paper nor borrowings under the revolving credit facility were outstanding at December 31, 2007.

In March 2008, we issued $1 billion aggregate principal amount of senior notes bearing interest at 5.9 percent with a maturity date of March 15, 2018. Interest on the senior notes is payable semi-annually beginning September 15, 2008.

In February 2008, the 805 million Canadian dollar revolving term credit facility of Marathon Oil Canada Corporation was repaid and the facility was terminated.

13. Stock-Based Compensation Plans

The following table presents a summary of stock option award and restricted stock award activity for the nine month period ended September 30, 2008:

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


Outstanding at December 31, 2007	12,214,853	$34.58	1,527,831	$39.87
Granted (b)	2,555,218	51.77	1,402,413	48.27
Options Exercised/Stock Vested	(479,632)	23.87	(603,697)	29.47
Canceled	(365,682)	51.68	(117,289)	43.15
Outstanding at September 30, 2008	13,924,757	$37.65	2,209,258	$47.87

(a)

Of the stock option awards outstanding as of September 30, 2008, 5,486,987, 7,938,260 and 499,510 were outstanding under the 2007 Incentive Compensation Plan, the 2003 Incentive Compensation Plan and the 1990 Stock Plan, including 749,282 stock options with tandem stock appreciation rights.

(b)

The weighted average grant date fair value of stock option awards granted was $13.03 per share.

14. Stockholders’ Equity

Share repurchase – As of September 30, 2008, we had acquired 66 million common shares at a cost of $2,922 million under our $5 billion authorized share repurchase program, including 8 million common shares acquired during the first nine months of 2008 at a cost of $402 million.

15. 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.

We, along with some other defendants with refinery operations, recently settled a number of lawsuits alleging methyl tertiary butyl ether (“MTBE”) contamination of water supply wells. We were a defendant in 40 of the cases settled. Our share of the cash portion of the settlement was paid in October 2008 and did not significantly impact our consolidated results of operations, financial position or cash flows. Under the settlement, the settling

Notes to Consolidated Financial Statements (Unaudited)

defendants, including our company, are responsible for addressing future MTBE contamination in certain water supply wells. We do not expect that our share of liability for any such future obligations under the settlement to significantly impact our consolidated results of operations, financial position or cash flows.

Contractual commitments – At September 30, 2008, Marathon’s contract commitments to acquire property, plant and equipment totaled $3,966 million.

16. Supplemental Cash Flow Information

	Nine Months Ended September 30,
(In millions)	2008		2007

Net cash provided from operating activities included:
Interest paid (net of amounts capitalized)	$	85	$	66
Income taxes paid to taxing authorities		2,458		2,711

Noncash investing and financing activities:
Bond obligation assumed for trusteed funds	$	-	$	1,000

Noncash effect of deconsolidation of EGHoldings:
Decrease in non-cash assets	$	-	$	1,759
Record equity method investment		-		942
Decrease in liabilities		-		310
Elimination of minority interest		-		544

17. Accounting Standards Not Yet Adopted

In June 2008, the FASB issued FSP on EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”) 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. Early application of FSP EITF 03-6-1 is not permitted. Although restricted stock awards meet this definition of participating securities, we do not expect application of FSP EITF 03-6-1 to have a significant impact on our reported EPS.

In April 2008, the FASB issued FSP on FAS 142-3 (“FSP FAS 142-3”) which amends the factors that should be considered in developing renewal or extension 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 will be applied prospectively, adoption is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

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

Notes to Consolidated Financial Statements (Unaudited)

for earlier periods presented for comparative purposes at initial adoption. We will expand our disclosures in accordance with SFAS No. 161 beginning in the first quarter of 2009; however, the adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

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 non-controlling 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 business combinations standard. 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. SFAS No. 141(R) is effective on January 1, 2009 for all new business combinations. We are currently evaluating the provisions of this statement.

Also 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. SFAS No. 160 is effective January 1, 2009 and early adoption is prohibited. The statement must be applied prospectively, except for the presentation and disclosure requirements which must be applied retrospectively for all periods presented in consolidated financial statements. We do not have significant noncontrolling interests in consolidated subsidiaries, and therefore, adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

18. Evaluation of Separation of Business

On July 31, 2008, Marathon announced that the board of directors is evaluating the separation of Marathon into two independent, publicly-traded companies, each focused on its own set of business opportunities. One entity would consist of the Exploration and Production, Integrated Gas and Oil Sands Mining businesses; and the other entity would consist of the Refining, Marketing and Transportation business.

19. Subsequent Events

On October 8, 2008, we completed the sale of our 50 percent ownership interest in Pilot Travel Centers LLC (“PTC”). Sale proceeds, before closing costs, were $625 million, with a pretax gain on the sale of approximately $125 million expected. Immediately preceding the sale, we received a $75 million redemption of our partnership interest from PTC that was accounted for as a return of investment.

On October 31, 2008, we closed the sale of our Norwegian outside-operated properties and undeveloped offshore acreage for proceeds of $320 million, before post-closing adjustments. After post-closing adjustments are finalized, the pretax gain is expected to be between $250 and $275 million. As of September 30, 2008, operating assets and liabilities with a net carrying value of $36 million were classified as held for sale, with $3 million reported in Other current assets, $94 million in Other noncurrent assets and $61 million in Deferred credits and other liabilities on the consolidated balance sheet.

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

Marathon Oil Corporation is engaged in worldwide exploration, production and marketing of liquid hydrocarbons and natural gas; mining, extraction and transportation of bitumen from oil sands deposits in Alberta, Canada, and upgrading of the bitumen for the production and marketing of synthetic crude oil and by-products; domestic refining, marketing and transportation of crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States; and worldwide marketing and transportation of products manufactured from natural gas, such as LNG and methanol, and development of other projects to link stranded natural gas resources with key demand areas. Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Consolidated Financial Statements and Selected Notes to Consolidated Financial Statements, the Supplemental Statistics and our 2007 Annual Report on Form 10-K.

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2007 Annual Report on Form 10-K.

We hold a 60 percent interest in Equatorial Guinea LNG Holdings Limited (“EGHoldings”). Effective May 1, 2007, we no longer consolidate EGHoldings. Our investment is accounted for prospectively using the equity method of accounting. Unless specifically noted, amounts presented for the Integrated Gas segment for periods prior to May 1, 2007, include amounts related to the minority interests.

Overview and Outlook

Exploration and Production (“E&P”)

Production

Net liquid hydrocarbon and natural gas sales averaged 379 and 369 thousand barrels of oil equivalent per day (“mboepd”) during the third quarter and first nine months of 2008, an increase of 2 percent and 5 percent over the same periods of 2007. Sales from the Alvheim/Vilje development offshore Norway and the Neptune development in the Gulf of Mexico more than offset declines in sales due to the deferral of certain production in the Gulf of Mexico as a result of hurricanes. Natural gas sales from the Alba field in Equatorial Guinea contributed to the increased sales in the year-to-date period.

The Alvheim development offshore Norway commenced production in June 2008. The Vilje field, which is tied back to the Alvheim floating production, storage and offloading vessel, began producing July 31, 2008. Commissioning of the Alvheim/Vilje project is continuing with a total of 10 wells currently available for production, out of 12 producing wells planned for the first phase. We have seen extended periods of production at facility capacity of 125 mboepd (75 mboepd net to Marathon) and expect further stabilization at these rates. We have a 65 percent operated interest in the Alvheim fields and a 47 percent outside-operated interest in the Vilje field.

The Neptune development in the Gulf of Mexico commenced production of liquid hydrocarbons and natural gas in early July 2008 and reached full oil capacity after 15 days of operations. The field is currently producing from 6 wells. Marathon has a 30 percent outside-operated interest in the Neptune development. The facility’s design capacity is 50 thousand barrels per day (“mbpd”) of oil and 50 million cubic feet per day (“mmcfd”) of natural gas.

Hurricanes Gustav and Ike impacted Gulf of Mexico production in the latter part of the third quarter, resulting in 9,500 net barrels of oil equivalent per day (“boepd”) being shut-in during the quarter. The Ewing Bank development resumed production in late October. The outside-operated Troika and Ursa fields remain shut-in for repairs. These fields are expected to impact fourth quarter 2008 sales by approximately 6 mboepd. We have an approximate 65 percent working interest in Ewing Bank, a 50 percent working interest in Troika and a 4 percent overriding royalty interest in Ursa.

We continue to increase sales from the Williston Basin (the Bakken shale formation) in North Dakota. We currently have 7 rigs drilling. We expect to drill 71 company-operated wells in 2008 and will have over 100 wells in the play by the end of 2008.

Exploration

During the first nine months of 2008, we announced the Portia and the Dione discoveries on Block 31 offshore Angola which were our 27th and 28th discoveries on Blocks 31 and 32. We also participated in 3 wells in our Angola exploration and appraisal program that have reached total depth, the results of which will be announced upon receipt of government and partner approval. At September 30, 2008 we were participating in one appraisal well in Block 32. On Block 31 we are currently drilling an exploratory well and plan to drill two additional exploratory wells the remainder of 2008. We hold a 10 percent outside-operated interest in Block 31 and a 30 percent outside-operated interest in Block 32.

Offshore Angola, we have received approval to proceed with the first deepwater oil development project in Block 31. The development is comprised of the Plutao, Saturno, Venus and Marte (“PSVM”) fields. Key contracts are ready to be awarded and construction work is expected to begin later this year. A total of 48 production and injection wells are planned for the PSVM development.

In the third quarter of 2008, we announced a Gulf of Mexico deepwater discovery on the Gunflint prospect located on Mississippi Canyon Block 948. We own a 13 percent outside-operated interest in the block. We are also currently participating in another deepwater exploration well in the Gulf of Mexico and an appraisal well on the Stones prospect located on Walker Ridge Block 508. We hold a 25 percent outside-operated interest in Stones.

In October 2008, development of the Droshky discovery, located in the Gulf of Mexico on Green Canyon Block 244, was authorized by our board of directors. The initial Droshky discovery well and two sidetracks were drilled in 2007, followed in 2008 by a second delineation and sidetrack well. The project will consist of four development wells, which will be tied back to the nearby outside-operated Bullwinkle platform. We have secured a rig to begin drilling in 2009, and first production is targeted for 2010. Our share of sales is expected to peak at about 45 mbpd of liquid hydrocarbons and 43 mmcfd of natural gas, after royalties. We hold a 100 percent working interest in Droshky.

Also in October 2008, development of the Ozona prospect, located in the Gulf of Mexico on Garden Banks Block 515 was authorized. We have secured a rig to complete the previously drilled appraisal well and tie back to the nearby outside-operated Auger platform. First production is expected in 2011. We hold a 68 percent working interest in Ozona.

During the second quarter of 2008 we were awarded all 15 blocks bid in the Central Gulf of Mexico Lease Sale No. 206 conducted by the Minerals Management Service in the first quarter of 2008. Two blocks are 100 percent Marathon, and the remaining blocks were bid with partners, at a total cost of $121 million. Initial drilling on these leases, and those acquired at Lease Sale No. 205 in October 2007, is planned for 2009.

In Indonesia, we are the operator of a drilling rig consortium which has secured a two-year contract for a deepwater exploration drilling rig. The rig will be used for deepwater exploration activities by us and four other companies in Indonesia. The participants have the right to extend this rig commitment. Additionally, in October 2008, we were granted a 49 percent interest and operatorship in the Bone Bay Block offshore Indonesia. The Bone Bay Block is 200 miles southeast of our PasangkayuBlock, which was awarded in 2006. Current exploration plans call for the acquisition of 2D seismic starting in 2009, followed by drilling in 2011.

We ceased efforts to pursue exploration opportunities in Ukraine and closed our Kiev office in the third quarter of 2008.

Divestitures

On October 31, 2008, we closed the sale of our outside-operated interests (24 percent of Heimdal field, 47 percent of Vale field and 20 percent of Skirne field) and associated undeveloped acreage offshore Norway for proceeds of $320 million, before post-closing adjustments. When post-closing adjustments are finalized, the pretax gain on the sale is expected to be between $250 and $270 million.

During the first quarter of 2008, we transferred our interest in an exploration and production license in Sudan to the operator, and as a result, we no longer have any interests in Sudan.

The above discussions include forward-looking statements with respect to the timing and levels of future production, and anticipated future exploratory drilling activity. 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 disposition of interests 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, before royalties, was 28 thousand barrels per day (“mbpd”) in the third quarter and 25 mbpd in the first nine months of 2008. Third quarter production increased 15 percent over second quarter as a result of a greater volume of ore being mined and available to the mine processing facility. This improvement is largely a result of additional shovel excavation locations being opened in the mine enabling more consistency in ore availability.

The Athabasca Oil Sands Project (“AOSP”) Expansion 1, which includes construction of mining and extraction facilities at the Jackpine mine, expansion of treatment facilities at the existing Muskeg River mine, expansion of the Scotford upgrader and development of related infrastructure, is anticipated to begin operations in 2010 or 2011. As recently announced by the operator, a final investment decision on Expansion 2 has been postponed.

In the third quarter of 2008, following achievement of project payout, the royalty rate increased to the 25 percent of net revenue post-payout rate from the one percent of gross revenue rate that had been in effect for most of the year. During the first quarter of 2008, the royalty calculation methodology for the AOSP was revised to allow for additional eligible costs to the project such that the royalty calculation adjusted retroactively to the one percent as of July 1, 2007.

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

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

Our total refinery throughputs were 8 percent lower in the third quarter and first nine months of 2008 than in the third quarter and first nine months of 2007. Crude oil refined likewise decreased 8 percent in the same periods. Third quarter throughput declines were primarily weather-related, while planned maintenance activities at several of our refineries earlier in the year also contributed to the year-to-date throughput declines.

Our ethanol blending program in the third quarter of 2008 increased 50 percent compared to the same period of 2007. For the first nine months of 2008 we blended 36 percent more ethanol than in the same period of 2007. The future expansion or contraction of our ethanol blending program will be driven by the economics of ethanol supply and government regulations.

Third quarter 2008 Speedway SuperAmerica LLC same store gasoline sales volume decreased 12 percent when compared to the third quarter of 2007 while same store merchandise sales increased by 2 percent for the same period. Our 2007 gasoline sales included the effect of a special sales promotion.

The expansion of our Garyville refinery is 70 percent complete with an on-schedule startup expected in the fourth quarter 2009. We have identified minor cost increases for additional quantities of materials required, material and labor cost escalation and some additional costs associated with the recent hurricanes in the Gulf Coast region. We now project the expansion will cost about $3.4 billion, excluding capitalized interest, or about 5 percent more than the original estimate.

All the permits have been received for the upgrading and expansion project at the Detroit refinery. Construction started at the end of the second quarter of 2008. Due to the current market conditions, we are reevaluating the project construction schedule and expect to defer the project completion. We are currently compiling the new project schedule and cost, and expect to complete this analysis by year end 2008.

In October 2008, we completed the sale of our 50 percent ownership interest in PTC. Sale proceeds, before closing costs, were $625 million, with a pretax gain on the sale of approximately $125 million expected. Immediately preceding the sale, we received a $75 million redemption of our partnership interest from PTC that was accounted for as a return of investment.

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”)

We own 45 percent of Atlantic Methanol Production Company LLC (“AMPCO”) and 60 percent of Equatorial Guinea LNG Holdings Limited (“EGHoldings”), both of which are accounted for under the equity method of accounting. AMPCO operates a methanol plant and EGHoldings operates a liquefied natural gas (“LNG”) production facility, both located on

Bioko Island, Equatorial Guinea. Alba field dry natural gas, which remains after the condensate and liquefied petroleum gas (“LPG”) are removed, is supplied to both of these facilities under long-term, fixed price contracts. We consider the prices under these contracts to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances, because of the location of the natural gas and limited local demand for natural gas in Equatorial Guinea.

The EGHoldings LNG production facility delivered 13 cargoes during the third quarter of 2008. Our share of LNG sales worldwide totaled 6,048 metric tonnes per day (“mtpd”) for the third quarter of 2008 compared to 6,137 mtpd in the third quarter of 2007 and 6,453 mtpd in the first nine months of 2008 compared to 3,117 mtpd in the first nine months of 2007. 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.

Production at the LNG facility in Equatorial Guinea was curtailed in July while scheduled repairs and modifications were completed on the facility to improve the overall efficiency of the plant. The methanol plant experienced a series of planned and unplanned maintenance events, but the facility returned to full production in October 2008. Neither situation significantly impacted our financial results for the quarter.

We continue to invest in the development of new technologies to create value and supply new energy sources. In the first nine months of 2008, we recorded costs of approximately $59 million related to natural gas technology research, including completing construction and beginning the commissioning of the demonstration plant for Gas-To-FuelsTM technology.

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				Nine Months Ended
	September 30,				September 30,
(In millions)	2008		2007		2008		2007
E&P	$	3,873	$	2,447	$	10,289	$	6,437
OSM		600		-		815		-
RM&T		18,766		14,605		52,767		40,424
IG		24		64		64		188
Segment revenues		23,263		17,116		63,935		47,049

Elimination of intersegment revenues		(347)		(231)		(1,050)		(571)
Gain (loss) on U.K. natural gas contracts		198		(123)		(37)		(111)
Total revenues	$	23,114	$	16,762	$	62,848	$	46,367

Items included in both revenues and costs and
expenses:

Consumer excise taxes on petroleum products and merchandise	$	1,273