UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2006

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)

Delaware		25-0996816
(State of Incorporation)		(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)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o

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

There were 362,436,024 shares of Marathon Oil Corporation common stock outstanding as of April 30, 2006.

 

 

MARATHON OIL CORPORATION

INDEX

						Page
PART I — FINANCIAL INFORMATION
		Item 1.		Financial Statements:
				Consolidated Statements of Income			3
				Consolidated Balance Sheets			4
				Consolidated Statements of Cash Flows			5
				Selected Notes to Consolidated Financial Statements			6
		Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			15
		Item 3.		Quantitative and Qualitative Disclosures About Market Risk			25
		Item 4.		Controls and Procedures			28
				Supplemental Statistics			29
PART II — OTHER INFORMATION
		Item 1.		Legal Proceedings			31
		Item 1A.		Risk Factors			31
		Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			31
		Item 4.		Submission of Matters to a Vote of Security Holders			32
		Item 6.		Exhibits			33
				Signatures			34
Restated Certificate of Incorporation
Certificate of Amendment
Amendment #1 to Five-Year Credit Agreement
Computation of Ratio of Earnings to Combined Fixed Charges
Computation of Ratio of Earnings to Fixed Charges
Certification of President and CEO
Certification of Senior Vice President and CFO
Certification of President and CEO
Certification of Senior Vice President and CFO

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, typically between 20 and 50 percent). Effective September 1, 2005, Marathon Ashland Petroleum LLC changed its name to Marathon Petroleum Company LLC. In this Form 10-Q, references to Marathon Petroleum Company LLC (“MPC”) are references to the entity formerly known as Marathon Ashland Petroleum LLC.

Part I — Financial Information

Item 1. Financial Statements

MARATHON OIL CORPORATION

		First Quarter Ended March 31,
(Dollars in millions, except per share data)		2006				2005
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)		$	12,998			$	9,840
Revenues from matching buy/sell transactions			3,206				2,809
Sales to related parties			312				283
Income from equity method investments			92				40
Net gains on disposal of assets			11				11
Other income			19				27
Total revenues and other income			16,638				13,010
Costs and expenses:
Cost of revenues (excludes items below)			9,769				7,692
Purchases related to matching buy/sell transactions			3,233				2,832
Purchases from related parties			51				56
Consumer excise taxes			1,165				1,084
Depreciation, depletion and amortization			415				323
Selling, general and administrative expenses			287				260
Other taxes			149				105
Exploration expenses			71				34
Total costs and expenses			15,140				12,386
Income from operations			1,498				624
Net interest and other financing costs			24				32
Minority interests in income (loss) of:
Marathon Petroleum Company LLC			—				70
Equatorial Guinea LNG Holdings Limited			(3	)			(1	)
Income before income taxes			1,477				523
Provision for income taxes			693				199
Net income		$	784			$	324
Per share information:
Net income per share — basic		$	2.15			$	0.94
Net income per share — diluted		$	2.13			$	0.93
Dividends paid per share		$	0.33			$	0.28

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

MARATHON OIL CORPORATION

		March 31,				December 31,
(Dollars in millions, except per share data)		2006				2005
Assets
Current assets:
Cash and cash equivalents		$	1,269			$	2,617
Receivables, less allowance for doubtful accounts of $3 and $3			3,614				3,476
Receivables from United States Steel			20				20
Receivables from related parties			55				38
Inventories			3,409				3,041
Other current assets			218				191
Total current assets			8,585				9,383
Investments and long-term receivables, less allowance for doubtful accounts of $9 and $10			1,841				1,864
Receivables from United States Steel			529				532
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $12,746 and $12,384			15,186				15,011
Goodwill			1,307				1,307
Intangible assets, less accumulated amortization of $63 and $58			196				200
Other noncurrent assets			160				201
Total assets		$	27,804			$	28,498
Liabilities
Current liabilities:
Accounts payable		$	5,194			$	5,353
Consideration payable under Libya re-entry agreement			212				732
Payables to related parties			108				82
Payroll and benefits payable			286				344
Accrued taxes			846				782
Deferred income taxes			466				450
Accrued interest			49				96
Long-term debt due within one year			15				315
Total current liabilities			7,176				8,154
Long-term debt			3,687				3,698
Deferred income taxes			2,033				2,030
Employee benefits obligations			1,221				1,321
Asset retirement obligations			750				711
Payable to United States Steel			6				6
Deferred credits and other liabilities			295				438
Total liabilities			15,168				16,358
Minority interests in Equatorial Guinea LNG Holdings Limited			471				435
Commitments and contingencies
Stockholders’ Equity
Common stock issued – 367,280,367 and 366,925,852 shares (par value $1 per share, 550,000,000 shares authorized)			367				367
Common stock held in treasury, at cost – 3,457,472 and 179,977 shares			(245	)			(8	)
Additional paid-in capital			5,116				5,111
Retained earnings			7,068				6,406
Accumulated other comprehensive loss			(141	)			(151	)
Unearned compensation			—				(20	)
Total stockholders’ equity			12,165				11,705
Total liabilities and stockholders’ equity		$	27,804			$	28,498

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

MARATHON OIL CORPORATION

		First Quarter Ended March 31,
(Dollars in millions)		2006				2005
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income		$	784			$	324
Adjustments to reconcile to net cash provided from operating activities:
Deferred income taxes			41				3
Minority interests in income (loss) of subsidiaries			(3	)			69
Depreciation, depletion and amortization			415				323
Pension and other postretirement benefits, net			(92	)			47
Exploratory dry well costs and unproved property impairments			34				12
Net gains on disposal of assets			(11	)			(11	)
Changes in the fair value of long-term U.K. natural gas contracts			(78	)			57
Equity method investments, net			(59	)			(2	)
Changes in:
Current receivables			(192	)			2
Inventories			(366	)			(277	)
Current accounts payable and accrued expenses			(173	)			(137	)
All other, net			(60	)			(53	)
Net cash provided from operating activities			240				357
Investing activities:
Capital expenditures			(599	)			(556	)
Acquisitions			(527	)			—
Disposal of assets			38				36
Investments — loans and advances			—				(30	)
— repayments of loans and advances			87				—
All other, net			14				6
Net cash used in investing activities			(987	)			(544	)
Financing activities:
Debt repayments			(302	)			(2	)
Issuance of common stock			8				39
Purchases of common stock			(229	)			—
Excess tax benefits from stock-based compensation arrangements			10				—
Dividends paid			(121	)			(97	)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited			30				73
Net cash provided from (used in) financing activities			(604	)			13
Effect of exchange rate changes on cash			3				(4	)
Net decrease in cash and cash equivalents			(1,348	)			(178	)
Cash and cash equivalents at beginning of period			2,617				3,369
Cash and cash equivalents at end of period		$	1,269			$	3,191

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

MARATHON OIL CORPORATION

1.		Basis of Presentation
		These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for a fair presentation of the results for the periods reported. All such adjustments are of a normal recurring nature unless disclosed otherwise. These consolidated financial statements, including selected 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 2006 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”) 2005 Annual Report on Form 10-K.
2.		New Accounting Standards
		In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123 (Revised 2004), “Share-Based Payment,” (“SFAS No. 123(R)”) as a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” This statement requires entities to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the grant date. That cost is recognized over the period during which an employee is required to provide service in exchange for the award, usually the vesting period. In addition, awards classified as liabilities are remeasured at fair value each reporting period. Marathon had previously adopted the fair value method under SFAS No. 123 for grants made, modified or settled on or after January 1, 2003.
		Marathon adopted SFAS No. 123(R) as of January 1, 2006, for all awards granted, modified or cancelled after adoption, and for the unvested portion of awards outstanding at January 1, 2006. At the date of adoption, SFAS No. 123(R) requires that an assumed forfeiture rate be applied to any unvested awards and that awards classified as liabilities be measured at fair value. Prior to adopting SFAS No. 123(R), Marathon recognized forfeitures as they occurred and applied the intrinsic value method to awards classified as liabilities. The adoption did not have a significant impact on Marathon’s consolidated results of operations, financial position or cash flows.
		SFAS No. 123(R) also requires a company to calculate the pool of excess tax benefits (the “APIC Pool”) available to absorb tax deficiencies recognized subsequent to adopting the statement. In November 2005, the FASB issued FASB Staff Position No. 123R-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” to provide an alternative transition election (the “short cut method”) to account for the tax effects of share-based payment awards to employees. Marathon has elected the long-form method to determine its APIC Pool as of January 1, 2006. See Note 3 for the disclosures regarding share-based payments required by SFAS No. 123(R).
		Effective January 1, 2006, Marathon adopted SFAS No. 151, “Inventory Costs – an amendment of ARB No. 43, Chapter 4.” This statement requires that items such as idle facility expense, excessive spoilage, double freight and re-handling costs be recognized as a current-period charge. The adoption did not have a significant effect on Marathon’s consolidated results of operations, financial position or cash flows.
		Effective January 1, 2006, Marathon adopted SFAS No. 154, “Accounting Changes and Error Corrections – A Replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 requires companies to recognize (1) voluntary changes in accounting principle and (2) changes required by a new accounting pronouncement, when the pronouncement does not include specific transition provisions, retrospectively to prior periods’ financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change.

3.		Stock-Based Compensation Arrangements
		Description of the Plans
		The Marathon Oil Corporation 2003 Incentive Compensation Plan (the “Plan”) authorizes the Compensation Committee of the Board of Directors of Marathon to grant stock options, stock appreciation rights, stock awards, cash awards and performance awards to employees. The Plan also allows Marathon to provide equity compensation to its non-employee directors. No more than 20,000,000 shares of common stock may be issued under the Plan, and no more than 8,500,000 of those shares may be used for awards other than stock options or stock appreciation rights. Shares subject to awards that are forfeited, terminated, expire unexercised, settled in cash, exchanged for other awards, tendered to satisfy the purchase price of an award, withheld to satisfy tax obligations or otherwise lapse become available for future grants. Shares issued as a result of stock option exercises and restricted stock grants are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.
		The Plan replaced the 1990 Stock Plan, the Non-Officer Restricted Stock Plan, the Non-Employee Director Stock Plan, the deferred stock benefit provision of the Deferred Compensation Plan for Non-Employee Directors, the Senior Executive Officer Annual Incentive Compensation Plan and the Annual Incentive Compensation Plan (collectively, the “Prior Plans”). No new grants will be made from the Prior Plans. Any awards previously granted under the Prior Plans shall continue to vest and/or be exercisable in accordance with their original terms and conditions.
		Stock-Based Awards Under the Plans
		Marathon’s stock options represent the right to purchase shares of common stock at the fair market value of the common stock on the date of grant. Through 2004, certain options were granted with a tandem stock appreciation right, which allows the recipient to instead elect to receive cash and/or common stock equal to the excess of the fair market value of shares of common stock, as determined in accordance with the Plan, over the option price of the shares. Most stock options granted under the Plan vest ratably over a three-year period and all expire ten years from the date they are granted.
		Similar to stock options, stock appreciation rights (“SARs”) represent the right to receive a payment equal to the excess of the fair market value of shares of common stock on the date the right is exercised over the exercise price. In general, SARs that have been granted under the Plan are settled in shares of stock, vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.
		In 2003 and 2004, the Compensation Committee granted stock-based performance awards to Marathon’s and MPC’s officers under the Plan. The stock-based performance awards represent shares of common stock that are subject to forfeiture provisions and restrictions on transfer. Those restrictions may be removed if certain pre-established performance measures are met. The stock-based performance awards granted under the Plan generally vest at the end of a 36-month performance period if the performance targets are achieved and the recipient remains employed by Marathon at that date.
		In 2005, the Compensation Committee granted time-based restricted stock to the officers under the Plan. The restricted stock awards vest three years from the date of grant, contingent on the recipient’s continued employment. Prior to vesting, the restricted stock recipients have the right to vote such stock and receive dividends thereon. The nonvested shares are not transferable and are retained by Marathon until they vest.
		Marathon also grants restricted stock to certain non-officer employees and phantom stock units to certain international employees under the Plan (“restricted stock awards”) based on their performance within certain guidelines and for retention purposes. The restricted stock awards generally vest in one-third increments over a three-year period, contingent on the recipient’s continued employment. Prior to vesting, the restricted stock recipients have the right to vote such stock and receive dividends thereon. The nonvested shares are not transferable and are retained by Marathon until they vest.
		Marathon maintains an equity compensation program for its non-employee directors under the Plan. Prior to January 1, 2006, pursuant to the program, non-employee directors were required to defer 50 percent of their annual retainers in the form of common stock units. In addition, each non-employee director receives an annual grant of non-retainer common stock units under the Plan. The program also provided each non-employee director with a matching grant of up to 1,000 shares of common stock on his or her initial election to the Board if he or she purchased an equivalent number of shares within 60 days of joining the Board. Effective January 1, 2006, non-employee directors are no longer required to defer 50 percent of their annual retainers in the form of common stock units and the matching grant program was discontinued.

		Stock-Based Compensation Expense
		The fair values of stock options, stock options with tandem SARs and stock-settled SARs (“stock option awards”) are estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of the Company’s stock price have the most significant impact on the fair value calculation. Marathon has utilized historical data and analyzed current information which reasonably support these assumptions.
		The fair value of Marathon’s restricted stock awards is determined based on the fair market value of the Company’s common stock on the date of grant. Prior to adoption of SFAS No. 123(R) on January 1, 2006, the fair values of Marathon’s stock-based performance awards were determined in the same manner as restricted stock awards. Under SFAS No. 123(R), on a prospective basis, these awards are required to be valued utilizing an option pricing model. No stock-based performance awards have been granted since May 2004.
		Effective January 1, 2006, Marathon’s stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods. Unearned stock-based compensation is charged to stockholders’ equity when restricted stock awards and stock-based performance awards are granted. Compensation expense is recognized over the balance of the vesting period and is adjusted if conditions of the restricted stock award or stock-based performance award are not met. Options with tandem SARs are classified as a liability and are remeasured at fair value each reporting period until settlement.
		Prior to January 1, 2006, Marathon recorded stock-based compensation expense over the stated vesting period for stock option awards that are subject to specific vesting conditions and specify (1) that an employee vests in the award upon becoming “retirement eligible” or (2) that the employee will continue to vest in the award after retirement without providing any additional service. Under SFAS No. 123(R), from the date of adoption, such compensation cost is recognized immediately for awards granted to retirement-eligible employees or over the period from the grant date to the retirement eligibility date if retirement eligibility will be reached during the stated vesting period. No stock option awards were granted during the quarter ended March 31, 2006, and therefore awards with such vesting terms did not impact stock-based compensation expense for the quarter. Marathon previously determined that the compensation expense determined under the current and previous approaches did not differ materially.
		During the quarters ended March 31, 2006 and 2005, total employee stock-based compensation expense was $23 million and $42 million. The total related income tax benefits were $9 million and $16 million. During the first quarter 2006, cash received upon exercise of stock option awards was $8 million. Tax benefits realized for deductions during the first quarter 2006 that were in excess of the stock-based compensation expense recorded for options exercised and other stock-based awards vested during the quarter totaled $10 million. No stock option awards were settled in cash during the first quarter 2006.
		Outstanding Stock-Based Awards
		The following is a summary of stock option award activity for the quarter ended March 31, 2006:

		Shares				Price (a)
Outstanding at December 31, 2005			6,007,954			$	36.51
Granted			—				—
Exercised			(357,265	)		$	30.04
Canceled			(27,848	)		$	44.58
Outstanding at March 31, 2006 (b)			5,622,841			$	36.88

(a)		Weighted-average exercise price.
(b)		Of the stock option awards outstanding as of March 31, 2006, 4,732,234 and 890,607 were outstanding under the 2003 Incentive Compensation Plan and 1990 Stock Plan, including 913,902 options with tandem SARs.

The following table presents information on stock option awards at March 31, 2006:

		Outstanding												Exercisable
		Number				Weighted-Average				Weighted-				Number				Weighted-
Range of Exercise		of Shares				Remaining				Average				of Shares				Average
Prices		Under Option				Contractual Life				Exercise Price				Under Option				Exercise Price
$22.38 – 25.52			1,189,837				6.8			$	25.50				670,209			$	25.49
$26.91 – 30.88			510,538				5.7			$	28.38				498,872			$	28.37
$32.52 – 34.00			2,062,246				7.5			$	33.49				759,603			$	33.29
$47.65 – 51.67			1,860,220				9.2			$	50.25				13,600			$	47.65
Total			5,622,841				7.7			$	36.88				1,942,284			$	29.43

		As of March 31, 2006 the aggregate intrinsic value of stock option awards outstanding was $221 million. The aggregate intrinisic value and weighted average remaining contractual life of stock option awards currently exercisable were $91 million and 6.4 years. As of March 31, 2006, the number of fully vested stock option awards and stock option awards expected to vest was 5,394,081. The weighted average exercise price and weighted average remaining contractual life of these stock option awards were $36.46 and 7.7 years and the aggregate intrinsic value was $214 million.
		No stock option awards were granted during the quarters ended March 31, 2006 and 2005. The total intrinsic value of stock option awards exercised during each of these quarters was $16 million. Of these amounts, $7 million in the first quarter 2006 and $11 million in the first quarter 2005 was related to options with tandem SARs. As of March 31, 2006, unrecognized compensation cost related to stock option awards was $16 million, which is expected to be recognized over a weighted average period of 1.4 years.
		The following is a summary of stock-based performance award and restricted stock award activity for the quarter ended March 31, 2006:

		Stock-Based				Weighted				Restricted				Weighted
		Performance				Average Grant				Stock and				Average Grant
		Awards				Date Fair Value				Units				Date Fair Value
Unvested at December 31, 2005			448,600			$	29.93				985,556			$	47.94
Granted			67,848			$	76.82				35,020			$	76.68
Vested			(273,448	)		$	38.30				(123,626	)		$	37.96
Forfeited			—				—				(11,950	)		$	52.20
Unvested at March 31, 2006			243,000			$	33.61				885,000			$	50.61

During the quarters ended March 31, 2006 and 2005, the weighted average grant date fair value of restricted stock awards was $76.68 and $46.86. The total vesting date fair value of restricted stock awards that vested during the quarters ended March 31, 2006 and 2005 was $32 million and $6 million. Of these amounts, $21 million related to the vesting of the officer stock-based performance awards during the first quarter of 2006. As of March 31, 2006, there was $33 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of 2 years.

4.		Computation of Income per Share
		Basic net income per share is based on the weighted average number of common shares outstanding. Diluted net income per share assumes exercise of stock options, provided the effect is not antidilutive.

		First Quarter Ended March 31,
		2006								2005
(Dollars in millions, except per share data)		Basic				Diluted				Basic				Diluted
Net income		$	784			$	784			$	324			$	324
Shares of common stock outstanding (thousands):
Average number of common shares outstanding			365,110				365,110				346,006				346,006
Effect of dilutive securities			—				3,270				—				2,639
Average common shares including dilutive effect			365,110				368,380				346,006				348,645
Per share:
Net income per share		$	2.15			$	2.13			$	0.94			$	0.93

5.		Segment Information
		Marathon’s operations consist of three reportable operating segments:

	1)		Exploration and Production (“E&P”) – explores for, produces and markets crude oil and natural gas on a worldwide basis;
	2)		Refining, Marketing and Transportation (“RM&T”) – refines, markets and transports crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and
	3)		Integrated Gas (“IG”) – markets and transports products manufactured from natural gas, such as liquid natural gas (“LNG”) and methanol, on a worldwide basis, and is developing other projects to link stranded natural gas resources with key demand areas.

Effective January 1, 2006, Marathon revised its measure of segment income to include the effects of minority interests and income taxes related to the segments to facilitate comparison of segment results with Marathon’s peers. Income taxes were allocated to the segments using estimated effective rates for each segment. In addition, the results of activities primarily associated with the marketing of the Company’s equity natural gas production, which had been presented as part of the Integrated Gas segment prior to 2006, are now included in the Exploration and Production segment as those activities are better aligned with E&P operations. Segment income amounts for all periods presented reflect these changes.

														Total
(Dollars in millions)		E&P				RM&T				IG				Segments
First Quarter Ended March 31, 2006
Revenues:
Customer		$	2,206			$	13,890			$	30			$	16,126
Intersegment (a)			190				13				—				203
Related parties			3				309				—				312
Segment revenues			2,399				14,212				30				16,641
Elimination of intersegment revenues			(190	)			(13	)			—				(203	)
Gain on long-term U.K. natural gas contracts			78				—				—				78
Total revenues		$	2,287			$	14,199			$	30			$	16,516
Segment income		$	477			$	319			$	8			$	804
Income from equity method investments			53				26				13				92
Depreciation, depletion and amortization (b)			251				133				2				386
Minority interests in income (loss) of subsidiaries (b)			—				—				(3	)			(3	)
Provision for income taxes (b)			489				204				5				698
Capital expenditures (c)			384				104				94				582

														Total
(Dollars in millions)		E&P				RM&T				IG				Segments
First Quarter Ended March 31, 2005
Revenues:
Customer		$	1,572			$	11,073			$	61			$	12,706
Intersegment (a)			144				42				—				186
Related parties			2				281				—				283
Segment revenues			1,718				11,396				61				13,175
Elimination of intersegment revenues			(144	)			(42	)			—				(186	)
Loss on long-term U.K. natural gas contracts			(57	)			—				—				(57	)
Total revenues		$	1,517			$	11,354			$	61			$	12,932
Segment income		$	334			$	74			$	22			$	430
Income from equity method investments			5				17				18				40
Depreciation, depletion and amortization (b)			210				104				2				316
Minority interests in income (loss) of subsidiaries (b)			—				67				(1	)			66
Provision for income taxes (b)			212				68				(5	)			275
Capital expenditures (c)			294				136				125				555

(a)		Management believes intersegment transactions were conducted under terms comparable to those with unrelated parties.
(b)		Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities and other unallocated items and are included in “Items not allocated to segments, net of income taxes” in the reconciliation below.
(c)		Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities.

The following reconciles segment income to net income as reported in Marathon’s consolidated statements of income:

		First Quarter Ended March 31,
(Dollars in millions)		2006				2005
Segment income		$	804			$	430
Items not allocated to segments, net of income taxes:
Gain (loss) on long-term U.K. natural gas contracts			45				(33	)
Corporate and other unallocated items			(65	)			(73	)
Net income		$	784			$	324

6.		Pensions and Other Postretirement Benefits
		The following summarizes the components of net periodic benefit costs:

		First Quarter Ended March 31,
		Pension Benefits								Other Benefits
(Dollars in millions)		2006				2005				2006				2005
Service cost		$	34			$	31			$	6			$	5
Interest cost			32				27				10				10
Expected return on plan assets			(26	)			(23	)			—				—
Amortization:
– net transition gain			—				(1	)			—				—
– prior service costs (credits)			1				1				(3	)			(3	)
– actuarial loss			13				15				2				2
Net periodic benefit cost		$	54			$	50			$	15			$	14

During the quarter ended March 31, 2006, Marathon made contributions of $148 million to its funded pension plans. Of this amount, $6 million related to foreign pension plans. Contributions made from the general assets of Marathon to cover current benefit payments related to unfunded pension and other postretirement benefit plans were $3 million and $9 million during the quarter. Marathon expects to make additional contributions to its funded pension plans of between $125 million and $195 million over the remainder of 2006.

7.		Income Taxes
		The provision for income taxes for interim periods is based on management’s best estimate of the effective income tax rate expected to be applicable for the current year plus any adjustments arising from a change in the estimated amount of taxes related to prior periods. The effective income tax rate for the first quarter 2006 was 47 percent compared to 38 percent for first quarter 2005. The following is an analysis of the effective income tax rate for the periods presented:

		First Quarter Ended March 31,
		2006				2005
Statutory U.S. income tax rate			35	%			35	%
Effects of foreign operations			11				—
State and local income taxes after federal income tax effects			2				5
Other tax effects			(1	)			(2	)
Effective income tax rate			47	%			38	%

8.		Comprehensive Income
		The following sets forth Marathon’s comprehensive income for the periods indicated:

		First Quarter Ended March 31,
(Dollars in millions)		2006				2005
Net income		$	784			$	324
Other comprehensive income (loss), net of taxes:
Minimum pension liability adjustments			10				—
Change in fair value of derivative instruments			—				(6	)
Total Comprehensive income		$	794			$	318

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

		March 31,				December 31,
(Dollars in millions)		2006				2005
Liquid hydrocarbons and natural gas		$	1,435			$	1,093
Refined products and merchandise			1,810				1,763
Supplies and sundry items			164				185
Total, at cost		$	3,409			$	3,041

10.		Property, Plant and Equipment
		Exploratory well costs capitalized greater than one year after completion of drilling as of March 31, 2006 were $99 million, including $40 million added to this category during the first quarter 2006 for wells in Equatorial Guinea (Corona, Bococo and Gardenia), where Marathon is evaluating various development scenarios for the discoveries around the Alba Field, including plans that would integrate the resources into the Company’s long-term LNG supply.

11.		Commitments and Contingencies
		Marathon is 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. Certain of these commitments are discussed below. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to Marathon’s consolidated financial statements. However, management believes that Marathon will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably.
		Contract commitments – At March 31, 2006 and December 31, 2005, Marathon’s contract commitments to acquire property, plant and equipment totaled $724 million and $668 million, respectively. During the first quarter of 2006, additional contract commitments were made related to the potential expansion of the Garyville, Louisiana refinery while the commitments related to the Equatorial Guinea LNG plant and the Alvheim project in Norway declined due to the continued construction progress on both projects.
12.		Stock Repurchase Program
		On January 29, 2006, Marathon’s Board of Directors authorized the repurchase of up to $2 billion of common stock over a period of two years. Such purchases will be made during this period as Marathon’s financial condition and market conditions warrant. Any purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. The repurchase program does not include specific price targets or timetables, and is subject to termination prior to completion. Marathon will use cash on hand, cash generated from operations or cash from available borrowings to acquire shares. During the quarter ended March 31, 2006, Marathon acquired approximately 3.2 million common shares, at an acquisition cost of $229 million, which were recorded as common stock held in treasury in the consolidated balance sheet.
13.		Supplemental Cash Flow Information

		First Quarter Ended March 31,
(Dollars in millions)		2006				2005
Net cash provided from operating activities included:
Interest and other financing costs paid (net of amounts capitalized)		$	74			$	91
Income taxes paid to taxing authorities (excluding excess tax benefits on stock-based compensation in 2006)			601				194
Commercial paper and revolving credit arrangements, net:
Borrowings		$	197			$	—
Repayments			(197	)			—

14.		MPC Receivables Purchase and Sale Facility
		On July 1, 2005, MPC entered into a $200 million, three-year Receivables Purchase and Sale Agreement with certain purchasers. The program was structured to allow MPC to periodically sell a participating interest in pools of eligible accounts receivable. During the term of the agreement MPC was obligated to pay a facility fee of 0.12%. In the first quarter of 2006, the facility was terminated. No receivables were sold under the agreement during its term.

15.		Accounting Standards Not Yet Adopted
		In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets – An Amendment of FASB Statement No. 140.” This statement amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” with respect to the accounting for separately recognized servicing assets and servicing liabilities. Adoption of SFAS No. 156 is required as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. Marathon does not expect adoption of this statement to have a significant effect on its consolidated results of operations, financial position or cash flows.
		In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments – An Amendment of FASB Statements No. 133 and 140.” SFAS No. 155 simplifies the accounting for certain hybrid financial instruments, eliminates the interim FASB guidance which provides that beneficial interests in securitized financial assets are not subject to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and eliminates the restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Marathon is currently studying the provisions of this Statement to determine the impact on its consolidated financial statements.
		In September 2005, the FASB ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The issue defines when a purchase and a sale of inventory with the same party that operates in the same line of business is recorded at fair value or considered a single non-monetary transaction subject to the fair value exception of APB Opinion No. 29. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw materials, work-in-process, or finished goods. In general, two or more transactions with the same party are treated as one if they are entered into in contemplation of each other. The rules apply to new arrangements entered into in reporting periods beginning after March 15, 2006. The accounting for certain of the transactions that Marathon considers as matching buy/sell transactions will be affected by this consensus and therefore, upon adoption, these transactions will no longer be recorded on a gross basis. Management does not believe any impact on net income would be material. There will be no impact on cash flows from operations as a result of adoption.

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

     Marathon Oil Corporation is engaged in worldwide exploration and production of crude oil and natural gas; domestic refining, marketing and transportation of crude oil and petroleum products primarily in the Midwest, the upper Great Plains and southeastern 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 2005 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 2005 Annual Report on Form 10-K.

     We acquired the 38 percent interest in MPC previously held by Ashland Inc. on June 30, 2005. Unless specifically noted as being after minority interests, amounts for the Refining, Marketing and Transportation segment include amounts related to the 38 percent interest held by Ashland prior to June 30, 2005.

     Marathon holds a 60 percent interest in Equatorial Guinea LNG Holdings Limited. The remaining interests are held by a company controlled by the government of Equatorial Guinea (25 percent interest), Mitsui & Co., Ltd. (8.5 percent interest) and a subsidiary of Marubeni Corporation (6.5 percent interest). Unless specifically noted as being after minority interests, amounts for the Integrated Gas segment include amounts related to the minority interests.

Overview and Outlook

Exploration and Production (“E&P”)

     Production available for sale during the first quarter of 2006 averaged 418,600 barrels of oil equivalent per day (“boepd”). Reported liquid hydrocarbon and natural gas sales during the quarter averaged 376,800 boepd. This period’s variance between production available for sale and actual sales volumes is primarily attributable to the timing of liquid hydrocarbon liftings from our operations in Libya, Equatorial Guinea and the U.K.

     We resumed our operations in the Waha concessions of Libya and achieved our first crude oil liftings there during the first quarter 2006. Our production available for sale for this quarter was consistent with our expectations when we re-entered these operations at the end of 2005. During 2006, we will work with our partners to define growth plans for this major asset.

     We continue to advance our major E&P projects. In Norway, the Alvheim project is 53 percent complete as of March 31, 2006, and is progressing on schedule with first production projected for the first quarter of 2007. As part of this project, the hull modifications to the Alvheim Floating Production Storage Offloading Vessel (FPSO) have been completed and the vessel sailed from Singapore to Norway where it will undergo topside installation work. Development drilling is scheduled to begin in May 2006. Also, the Neptune development in the Gulf of Mexico is 22 percent complete as of March 31, 2006, and is expected to deliver production by early 2008, with development drilling scheduled to begin in May 2006.

     We recently completed leasehold acquisitions totaling approximately 200,000 acres in the Bakken Shale resource play. The majority of the acreage is located in North Dakota with the remainder in eastern Montana. We now own a substantial position in the Bakken Shale with approximately 300 locations to be drilled over the next four to five years, with additional infill potential likely.

     During the first quarter 2006, we announced two exploration/appraisal successes. Offshore Norway, we participated in a successful appraisal well on the Gudrun prospect. Two zones were tested at an aggregate rate of over 10,000 barrels of oil per day and 30 million cubic feet of natural gas per day (“mmcfpd”). Marathon holds a 28 percent non-operated interest in Gudrun. Future activities will primarily be focused on evaluating development scenarios. Offshore Angola, we participated in a discovery well on the Mostarda prospect in Block 32. This discovery is the thirteenth discovery in Marathon’s deepwater Angola exploration program on Blocks 31 and 32 in which the Company holds a 10 percent and 30 percent interest, respectively. The Mostarda discovery is located near the previously announced Gindungo, Canela and Gengibre discoveries. In Block 31 we also participated in a successful appraisal well in the northeast part of the block

and a dry hole in the southeast portion of the block. The Urano well reached total depth and its results will be reported upon government approval.

     We continue to estimate our 2006 production available for sale will average between 365,000 and 395,000 boepd, excluding the effect of any acquisitions or dispositions. Reported volumes are based upon sales volumes which may vary from production available for sale primarily due to the timing of liftings from certain of our international locations.

     The above discussion includes forward-looking statements with respect to the timing and levels of our worldwide liquid hydrocarbon, natural gas and condensate production, the development of the Alvheim field, the Neptune development, the Gudrun prospect and anticipated future drilling activity in the Bakken Shale resource play. Some factors that could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, amount of capital available for exploration and development, acquisitions or dispositions of oil and natural gas properties, regulatory constraints, timing of commencing production from new wells, drilling rig availability, inability or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response and other geological, operating and economic considerations. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

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

     In the first quarter 2006, our RM&T operations benefited from refining margins (crack spreads) in the Midwest (Chicago) and Gulf Coast that were stronger than the comparable period of 2005. As a result of these strong margins and favorable sweet/sour crude oil differentials, our refining and wholesale marketing gross margin averaged 11.37 cents per gallon in the first quarter 2006 versus 6.85 cents per gallon in the first quarter 2005. In addition, during the first quarter of 2006, our total refinery throughput was approximately five percent higher than the same quarter in 2005. We continue to expect that our 2006 average crude oil throughput will exceed our record throughput for 2005. Also during the first quarter of 2006, we blended approximately 30 thousand barrels per day (“mbpd”) of ethanol into gasoline, approximately 13 percent more than we blended in the first quarter of 2005. The expansion or contraction of our ethanol blending program will be driven by the economics of the ethanol supply. In addition, we are on schedule to comply with the Federal Environmental Protection Agency regulations which require ultra low sulfur diesel fuel production beginning June 1, 2006.

     Speedway SuperAmerica LLC continued to realize strong same store merchandise sales with an increase of approximately 10.2 percent, while same store gasoline sales volume increased 3.3 percent when compared to the first quarter of 2005.

     The above discussion includes forward-looking statements with respect to projections of crude oil throughput that could be affected by planned and unplanned refinery maintenance projects, the levels of refining margins and other operating considerations. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas (“IG”)

     Our integrated gas activities during the first quarter 2006 were marked by continued progress in constructing the LNG plant in Equatorial Guinea. The project is approximately 73 percent complete on an engineering, procurement and construction basis as of March 31, 2006. Construction remains on schedule for first shipments of LNG in the third quarter of 2007.

     The above discussion contains forward-looking statements with respect to the estimated construction and startup dates of a LNG project which could be affected by unforeseen problems arising from construction, inability or delay in obtaining necessary government and third-party approvals, unanticipated changes in market demand or supply, environmental issues, availability or construction of sufficient LNG vessels, and unforeseen hazards such as weather conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Corporate

     Historically, we have maintained insurance coverage for physical damage and resulting business interruption to our major onshore and offshore facilities. Higher margins and commodity prices have increased our exposure to business interruptions. Due to recent hurricane activity, the availability of insurance coverage for windstorms in the Gulf of Mexico region has been reduced or, in many instances, it is prohibitively expensive. As a result, our exposure to losses from future windstorm activity in the Gulf of Mexico region has increased.

Critical Accounting Estimates

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

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

     There have been no significant changes to our critical accounting estimates subsequent to December 31, 2005.

Results of Operations

Consolidated Results

     Revenues for the first quarters of 2006 and 2005 are summarized by segment in the following table:

		First Quarter Ended March 31,
(Dollars in millions)		2006				2005
E&P		$	2,399			$	1,718
RM&T			14,212				11,396
IG			30				61
Segment revenues			16,641				13,175
Elimination of intersegment revenues			(203	)			(186	)
Gain (loss) on long-term U.K. natural gas contracts			78				(57	)
Total revenues		$	16,516			$	12,932
Items included in both revenues and costs and expenses:
Consumer excise taxes on petroleum products and merchandise			1,165				1,084
Matching crude oil and refined product buy/sell transactions settled in cash:
E&P			11				36
RM&T			3,195				2,773
Total buy/sell transactions included in revenues		$	3,206			$	2,809

     E&P segment revenues increased by $681 million in the first quarter of 2006 from the comparable prior-year period. The increase was primarily due to increased net liquid hydrocarbon sales volumes and higher prices for both liquid hydrocarbons and natural gas in all regions. The first crude oil liftings from Libya occurred this quarter, contributing to the net sales volume increase. In addition, net liquid hydrocarbon sales volumes benefited from a full quarter of production in the first quarter of 2006 from the Petronius field in the Gulf of Mexico that was down during the first quarter of 2005 due to hurricane damage.

     Excluded from E&P segment revenues are a gain of $78 million for the first quarter of 2006 and a loss of $57 million for the first quarter of 2005 on long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.

     RM&T segment revenues increased by $2.816 billion, including an increase from matching buy/sell transactions of $422 million, in the first quarter of 2006 from the comparable prior-year period. The increases primarily reflected higher refined product and crude oil prices as well as increased refined product volumes, partially offset by lower crude oil volumes.

     For additional information on segment results, see Segment Income.

     Income from equity method investments for the first quarter 2006 increased $52 million from the comparable prior-year period primarily due to the liquefied petroleum gas expansion in Equatorial Guinea which ramped up to full production in the third quarter of 2005.

     Cost of revenues for the first quarter 2006 increased by $2.077 billion from the comparable prior-year period. The increases are primarily in the RM&T segment and resulted mainly from higher acquisition costs for crude oil, other refinery charge and blend stocks, and refined products. Additionally, we experienced higher manufacturing expenses, primarily a result of higher purchased energy and maintenance costs.

     Depreciation, depletion and amortization for the first quarter of 2006, increased by $92 million compared to the same period of 2005. RM&T segment depreciation expense increased primarily as a result of the asset value increase recorded for the minority interest acquisition in the second quarter of 2005 and the Detroit refinery expansion completed in the fourth quarter of 2005. Included in first quarter 2006 for the E&P segment was a $20 million impairment of capitalized costs related to the Camden Hills field in the Gulf of Mexico and the associated Canyon Express pipeline. Natural gas production from the Camden Hills field ended during the first quarter 2006 as a result of increased water production from the well. Depreciation, depletion and amortization for the first quarter 2006 was also impacted by increased E&P volumes.

     Selling, general and administrative expenses for the first quarter 2006 increased by $27 million compared to the first quarter 2005. This increase reflects engineering costs for various RM&T projects, the cost to study the feasibility of adding a second natural gas liquefaction unit (or “train”) to our LNG plant in Equatorial Guinea and increased costs for outside professional services, partially offset by lower stock-based compensation expense.

     Exploration expenses were $71 million in the first quarter of 2006 compared to $34 million in the first quarter of 2005. Exploration expenses related to dry wells in the first quarter of 2006 totaled $30 million and primarily included costs related to the Davan well in the U.K. and the Soulandaka well in Gabon.

     Minority interest in income of MPC decreased $70 million in the first quarter of 2006 from the comparable 2005 period due to the completion of our acquisition of Ashland Inc.’s 38 percent interest in MPC on June 30, 2005.

     Provision for income taxes in the first quarter of 2006 increased by $494 million compared to the first quarter 2005 primarily due to increased income before income taxes as discussed above. Our effective income tax rate for 2006 was 47 percent compared to 38 percent for 2005 and the increase is primarily a result of the income taxes related to our Libyan operations, where the statutory income tax rate is in excess of 90 percent. The following is an analysis of the effective tax rates for the periods presented:

		First Quarter Ended March 31,
		2006				2005
Statutory U.S. income tax rate			35	%			35	%
Effects of foreign operations			11				—
State and local income taxes after federal income tax effects			2				5
Other tax effects			(1	)			(2	)
Effective income tax rate			47	%			38	%

Segment Results

     Segment income for the first quarter of 2006 and 2005 is summarized in the following table. Effective January 1, 2006, we revised our measure of segment income to include the effects of minority interests and income taxes related to the segments. In addition, the results of activities primarily associated with the marketing of our equity natural gas production, which had been presented as part of the Integrated Gas segment prior to 2006, are now included in the Exploration and Production segment. Segment results for all periods presented reflect these changes.

		First Quarter Ended March 31,
(Dollars in millions)		2006				2005
E&P:
United States		$	245			$	177
International			232				157
E&P segment			477				334
RM&T			319				74
IG			8				22
Segment income			804				430
Items not allocated to segments, net of income taxes:
Gain (loss) on long-term U.K. natural gas contracts			45				(33	)
Corporate and other unallocated items			(65	)			(73	)
Net income		$	784			$	324

     United States E&P income in the first quarter of 2006 increased $68 million compared to the first quarter of 2005. Pretax income increased $95 million and the effective income tax rate declined from 40 percent in the first quarter of 2005 to 37 percent in the first quarter of 2006.

     The increase in pretax income was primarily the result of an increase in revenues from higher product prices and liquid hydrocarbon sales volumes. Our domestic average realized liquid hydrocarbon price was $49.30 per barrel (“bbl”) compared with $38.47 per bbl in the comparable prior-year period. The average realized natural gas price of $6.66 per thousand cubic feet (“mcf”) was an increase from the $4.95 per mcf in the corresponding 2005 period. Domestic net liquid hydrocarbon sales volumes were 80 mbpd, an increase of 12 percent compared to the first quarter of 2005, primarily because of the resumption of production from the Petronius field in the Gulf of Mexico that was down in 2005 due to hurricane damage. Net natural gas sales volumes of 561 million cubic feet per day (“mmcfd”) were down nearly 2 percent from the first quarter of 2005.

     This revenue increase was partially offset by higher variable costs, including depreciation, depletion and amortization expense.

     International E&P income in the first quarter of 2006 increased $75 million from the first quarter of 2005. Pretax income increased $325 million and the effective income tax rate increased from 37 percent in the first quarter of 2005 to 60 percent in the first quarter of 2006. The 23 percentage point increase in the effective income tax rate was primarily a result of the income taxes related to our Libyan operations, where the statutory income tax rate is in excess of 90 percent.

     The increase in pretax income was primarily the result of an increase in revenues from higher product prices and higher net liquid hydrocarbon sales volumes. Additionally, income from equity method investments for the first quarter of 2006 benefited from a full quarter of operations from the liquefied petroleum gas expansion in Equatorial Guinea, which ramped up to full production in the third quarter of 2005.

     Our international average realized liquid hydrocarbon price was $50.68 per bbl in the first quarter of 2006 compared with $39.10 per bbl in the comparable prior-year period. The average realized natural gas price of $6.16 per mcf in the first quarter of 2006 was an increase from the $4.17 per mcf in the corresponding 2005 period. International net liquid hydrocarbon sales volumes were 131 mbpd in the first quarter of 2006 as compared to 91 mbpd in the first quarter of 2005 primarily due to our resumption of production in Libya. The increase also reflects the effect of the Equatorial Guinea condensate expansion project. Net natural gas sales volumes averaged 435 mmcfd, down 4 percent from the 2005 comparable period.

     These increases in pretax income were partially offset by higher variable costs and dry hole costs in the first quarter of 2006.

     RM&T segment income in the first quarter of 2006 increased by $245 million from the first quarter of 2005. Segment income in the first quarter of 2006 benefited from the 38 percent minority interest in MPC that we acquired on June 30, 2005. In the first quarter of 2005, the pretax earnings reduction related to the minority interest was $76 million. A key driver of the increase in RM&T pretax income was our refining and wholesale marketing gross margin, which averaged 11.37 cents per gallon in the first quarter of 2006 compared to 6.85 cents per gallon in the first quarter of 2005. This margin improvement reflected favorable sweet/sour crude oil differentials in the first quarter of 2006 and was consistent with the relevant indicators (crack spreads) in the Midwest (Chicago) and Gulf Coast markets.

     Derivative losses related to non-trading activities (which are included in the refining and wholesale marketing gross margin) were $11 million in the first quarter of 2006 as compared to losses of $172 million in the first quarter of 2005. Included in first quarter 2005 derivative losses was a $73 million charge for crack spread derivative contracts, $61 million of which related to mark-to-market losses on crack spread derivative contracts primarily related to No. 2 high sulfur fuel oil crack spreads that expired over the remainder of 2005. Derivative gains related to trading activities were $5 million in the first quarter of 2006 as compared to losses of $31 million in the comparable prior-year period. See Quantitative and Qualitative Disclosures About Market Risk — RM&T Segment for further details of derivative results.

     The 9 percentage point decrease in the effective income tax rate from 48 percent in the first quarter of 2005 to 39 percent in the first quarter of 2006 is primarily the result of the effect of the 2005 Kentucky tax increase on deferred tax balances at the beginning of that quarter.

     IG segment income in the first quarter of 2006 decreased by $14 million from the first quarter of 2005 primarily as a result of a $10 million increase in the provision for income taxes. This increase is primarily a result of providing for U.S. deferred income taxes on foreign income in 2006. No provision for U.S. deferred income taxes was made in 2005 because we permanently reinvested such income in those foreign operations.

Cash Flows and Liquidity

Cash Flows

     Net cash provided from operating activities totaled $240 million in the first quarter of 2006, compared with $357 million in the first quarter of 2005. The $117 million decrease mainly reflects contributions of $148 million to our pension plans and various working capital changes during the quarter.

     Net cash used in investing activities totaled $987 million in the first quarter of 2006. Capital expenditures were $599 million compared with $556 million for the comparable prior-year period. E&P spending increased $90 million, partially offset by decreases in RM&T and IG spending as a result of major projects being completed, such as the Detroit refinery expansion in the RM&T segment, or nearing completion, such as the LNG plant in the IG segment. E&P spending in the first quarter of 2006 reflected higher expenditures related to the Alvheim development offshore Norway and the Neptune development in the Gulf of Mexico. For information regarding capital expenditures by segment, refer to Supplemental Statistics. Cash paid for acquisitions totaled $527 million, primarily related to the initial $520 million payment associated with our re-entry into Libya.

     Net cash used in financing activities was $604 million in the first quarter of 2006, compared to net cash provided from financing activities of $13 million in the first quarter 2005. Significant uses of cash in financing activities during the first quarter of 2006 included the repayment of our $300 million 6.65% notes that matured during the quarter, stock repurchases of $229 million under a previously announced plan discussed under Liquidity and Capital Resources below and dividend payments of $121 million.

Dividends to Stockholders

     On April 26, 2006, our Board of Directors declared a dividend of 40 cents per share, payable June 12, 2006, to stockholders of record at the close of business on May 17, 2006. This was a seven cent, or 21 percent, increase in our quarterly dividend.

Derivative Instruments

     See Quantitative and Qualitative Disclosures About Market Risk for a discussion of derivative instruments and associated market risk.

Liquidity and Capital Resources

     Our main sources of liquidity and capital resources are internally generated cash flow from operations, committed and uncommitted credit facilities, and access to both the debt and equity capital markets. Our ability to access the debt capital market is supported by our investment grade credit ratings. 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+, respectively. Because of the liquidity and capital resource alternatives available to us, including internally generated cash flow, we believe that our short-term and long-term liquidity is adequate to fund operations, including our capital spending programs, stock repurchase program, repayment of debt maturities for the years 2006, 2007 and 2008, and any amounts that may ultimately be paid in connection with contingencies.

     During the first quarter 2006, we had a committed $1.5 billion five-year revolving credit facility with third-party financial institutions terminating in May 2009. At March 31, 2006, there were no borrowings against this facility and we had no commercial paper outstanding under the U.S. commercial paper program backed by the five-year revolving credit facility.

     During the first quarter 2006, MPC had a committed $500 million five-year revolving credit facility with third-party financial institutions terminating in May 2009. At March 31, 2006, there were no borrowings against this facility.

     Effective May 4, 2006, we entered into an amendment to our $1.5 billion five-year revolving credit agreement, expanding the size of our credit facility to $2.0 billion and extending the termination date to May 2011. The MPC revolving credit facility has been terminated.

     As a condition of the closing agreements for our acquisition of Ashland’s minority interest in MPC, we are required to maintain MPC on a stand-alone basis financially for a two-year period. During this period of time, capital contributions into MPC are prohibited and MPC is prohibited from incurring additional debt, except for borrowings under an existing intercompany loan facility to fund the expansion project at our Detroit refinery and in the event of limited extraordinary circumstances. MPC was permitted to use its revolving credit facility only for short-term working capital requirements in a manner consistent with past practices. There are no restrictions against MPC making intercompany loans or declaring dividends to its parent. We believe MPC’s existing cash balances and cash provided from MPC’s operations will be adequate to meet its liquidity requirements.

     During the first quarter of 2006 we entered into a loan agreement which allows borrowings up to an amount of $525 million from the Norwegian export credit agency based upon the amount of qualifying purchases by Marathon of goods and services from Norwegian suppliers. The loan agreement provides for either a fixed or floating interest rate option at the time of the initial drawdown. Should we elect to borrow under the agreement, the initial drawdown can only occur in June 2007.

     As of March 31, 2006, $1.7 billion aggregate amount of common stock, preferred stock and other equity securities, debt securities, trust preferred securities or other securities, including securities convertible into or exchangeable for other equity or debt securities were available to be issued under our $2.7 billion universal shelf registration statement filed in 2002.

     Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 17 percent at March 31, 2006, compared to 11 percent at year-end 2005 as shown below. This includes $549 million of debt that is serviced by United States Steel Corporation (“United States Steel”). We continually monitor our spending levels, market conditions and related interest rates to maintain what we perceive to be reasonable debt levels.

		March 31,				December 31,
(Dollars in millions)		2006				2005
Long-term debt due within one year		$	15			$	315
Long-term debt			3,687				3,698
Total debt		$	3,702			$	4,013
Cash		$	1,269			$	2,617
Equity		$	12,165			$	11,705
Calculation:
Total debt		$	3,702			$	4,013
Minus cash			1,269				2,617
Total debt minus cash			2,433				1,396
Total debt			3,702				4,013
Plus equity			12,165				11,705
Minus cash			1,269				2,617
Total debt plus equity minus cash		$	14,598			$	13,101
Cash-adjusted debt-to-capital ratio			17	%			11	%

     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. Factors that affect the availability of financing

include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies.

Stock Repurchase Program

     On January 29, 2006, our Board of Directors authorized the repurchase of up to $2 billion of common stock over a period of two years. Such purchases will be made during this period as our financial condition and market conditions warrant. Any purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. The repurchase program does not include specific price targets or timetables, and is subject to termination prior to completion. We will use cash on hand, cash generated from operations or cash from available borrowings to acquire shares. During the quarter ended March 31, 2006, we acquired approximately 3.2 million common shares, at an acquisition cost of $229 million. We expect to repurchase shares ratably through 2007 unless market or other conditions change significantly.

     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 or refining 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 March 31, 2006, our purchase obligations under crude oil, refinery feedstocks and refined product contracts increased approximately $2 billion from December 31, 2005, primarily as a result of increased contract volumes and prices. Otherwise, there have been no significant changes to our obligations to make future payments under existing contracts subsequent to December 31, 2005. 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, 2005.

Other Obligations

     An additional payment, estimated to be approximately $212 million, is payable by us during 2006 under our agreement with the National Oil Corporation of Libya to return to our operations in the Waha concessions in Libya.

Off-Balance Sheet Arrangements

     Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources; and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources. There have been no significant changes to our off-balance sheet arrangements subsequent to December 31, 2005.

Nonrecourse Indebtedness of Investees

     Certain of our investees have incurred indebtedness that we do not support through guarantees or otherwise. If we were obligated to share in this debt on a pro rata ownership basis, our share would have been approximately $313 million as of March 31, 2006. Of this amount, $189 million relates to Pilot Travel Centers LLC (“PTC”). If any of these investees default, we have no obligation to support the debt. Our partner in PTC has guaranteed $125 million of the total PTC debt.

Obligations Associated with the Separation of United States Steel

     We remain obligated (primarily or contingently) for certain debt and other financial arrangements for which United States Steel has assumed responsibility for repayment under the terms of the Separation. (See the discussion of the Separation in our 2005 Annual Report on Form 10-K.) United States Steel’s obligations to Marathon are general unsecured obligations that rank equal to United States Steel’s accounts payable and other general unsecured obligations. If United States Steel fails to satisfy these obligations, we would become responsible for repayment. Under the Financial Matters Agreement, United States Steel has all of the existing contractual rights under the leases

assumed from Marathon, including all rights related to purchase options, prepayments or the grant or release of security interests. However, United States Steel has no right to increase amounts due under or lengthen the term of any of the assumed leases, other than extensions set forth in the terms of the assumed leases.

     As of March 31, 2006, we have obligations totaling $590 million that have been assumed by United States Steel. Of the total $590 million, obligations of $549 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet (current portion — $20 million; long-term portion — $529 million). The remaining $41 million was related to off-balance sheet arrangements and contingent liabilities of United States Steel.

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 recovered in the prices of our products and services, operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil and refined products.

     Of particular significance to our refining operations are U.S. Environmental Protection Agency (“EPA”) regulations that require reduced sulfur levels starting in 2004 for gasoline and 2006 for diesel fuel. We expected our combined capital costs to achieve compliance with these rules to approximate $900 million over the period 2002 through 2006, and substantially all of those costs have been incurred as all refinery construction projects are on schedule to meet the June 1, 2006 ultra low sulfur diesel requirements.

     During 2001, MPC entered into a New Source Review consent decree and settlement of alleged Clean Air Act (“CAA”) and other violations with the EPA covering all of MPC’s refineries. The settlement committed MPC to specific control technologies and implementation schedules for environmental expenditures and improvements to MPC’s refineries over approximately an eight-year period. The consent decree was amended twice in 2005. The total one-time expenditures for these environmental projects are expected to be approximately $420 million over the eight-year period, with about $285 million incurred through March 31, 2006. The impact of the settlement on ongoing operating expenses is expected to be immaterial. In addition, MPC has nearly completed certain agreed upon supplemental environmental projects as part of this settlement of an enforcement action for alleged CAA violations, at a cost of $9 million. We believe this settlement will provide MPC with increased permitting and operating flexibility while achieving significant emission reductions.

     The oil industry across the U.K. continental shelf is making reductions in the amount of oil in its produced water discharges pursuant to the Department of Trade and Industry initiative under the Oil Pollution Prevention and Control Regulations (“OSPAR”) of 2005. In compliance with these regulations, we expect to spend an estimated $12 million in capital costs on the OSPAR project for Brae field to make the required reductions of oil in its produced water discharges.

     There have been no other significant changes to our environmental matters subsequent to December 31, 2005.

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.

Accounting Standards Not Yet Adopted

     In March 2006, the FASB issued SFAS No. 156, “Accounting for Servicing of Financial Assets – An Amendment of FASB Statement No. 140.” This statement amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” with respect to the accounting for separately recognized servicing assets and servicing liabilities. Adoption of SFAS No. 156 is required as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. Marathon does not expect adoption of this statement to have a significant effect on its consolidated results of operations, financial position or cash flows.

     In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments – An Amendment of FASB Statements No. 133 and 140.” SFAS No. 155 simplifies the accounting for certain hybrid financial instruments, eliminates the interim FASB guidance which provides that beneficial interests in securitized financial

assets are not subject to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and eliminates the restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. Marathon is currently studying the provisions of this Statement to determine the impact on its consolidated financial statements.

     In September 2005, the FASB ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The issue defines when a purchase and a sale of inventory with the same party that operates in the same line of business is recorded at fair value or considered a single non-monetary transaction subject to the fair value exception of APB Opinion No. 29. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw materials, work-in-process, or finished goods. In general, two or more transactions with the same party are treated as one if they are entered into in contemplation of each other. The rules apply to new arrangements entered into in reporting periods beginning after March 15, 2006. The accounting for certain of the transactions that Marathon considers as matching buy/sell transactions will be affected by this consensus and therefore, upon adoption, these transactions will no longer be recorded on a gross basis. Management does not believe any impact on net income would be material. There will be no impact on cash flows from operations as a result of adoption.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

Management Opinion Concerning Derivative Instruments

     Management has authorized the use of futures, forwards, swaps and options to manage exposure to market fluctuations in commodity prices, interest rates and foreign currency exchange rates.

     We use commodity-based derivatives to manage price risk related to the purchase, production or sale of crude oil, natural gas and refined products. To a lesser extent, we are exposed to the risk of price fluctuations on natural gas liquids and petroleum feedstocks used as raw materials, and purchases of ethanol.

     Our strategy has generally been to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. We use a variety of derivative instruments, including option combinations, as part of the overall risk management program to manage commodity price risk in our different businesses. As market conditions change, we evaluate our risk management program and could enter into strategies that assume market risk whereby cash settlement of commodity-based derivatives will be based on market prices.

     Our E&P segment primarily uses commodity derivative instruments selectively to protect against price decreases on portions of our future production when deemed advantageous to do so. We also use derivatives to protect the value of natural gas purchased and injected into storage in support of production operations. We use commodity derivative instruments to mitigate the price risk associated with the purchase and subsequent resale of natural gas on purchased volumes and anticipated sales volumes.

     Our RM&T segment uses commodity derivative instruments:

•

to mitigate the price risk:

	o		between the time foreign and domestic crude oil and other feedstock purchases for refinery supply are priced and when they are actually refined into salable petroleum products,
	o		associated with anticipated natural gas purchases for refinery use,
	o		associated with freight on crude oil, feedstocks and refined product deliveries, and
	o		on fixed price contracts for ethanol purchases;

	•		to protect the value of excess refined product, crude oil and liquefied petroleum gas inventories;
	•		to protect margins associated with future fixed price sales of refined products to non-retail customers;
	•		to protect against decreases in future crack spreads;
	•		to take advantage of trading opportunities identified in the commodity markets.

     We use financial derivative instruments in each of our segments to manage foreign currency exchange rate exposure on foreign currency denominated capital expenditures, operating expenses and foreign tax payments.

     We use financial derivative instruments to manage interest rate risk exposures. As we enter into these derivatives, assessments are made as to the qualification of each transaction for hedge accounting.

     We believe that our use of derivative instruments, along with risk assessment procedures and internal controls, does not expose us to material risk. However, the use of derivative instruments could materially affect our results of operations in particular quarterly or annual periods. We believe that the use of these instruments will not have a material adverse effect on our financial position or liquidity.

Commodity Price Risk

     Sensitivity analyses of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent changes in commodity prices for open derivative commodity instruments as of March 31, 2006 are provided in the following table:

		Incremental Decrease in IFO Assuming a
		Hypothetical Price Change of (a):
(Dollars in millions)		10%								25%
Commodity Derivative Instruments: (b)(c)
Crude oil (d)		$	32				(e)			$	86				(e)
Natural gas (d)			67				(e)				167				(e)
Refined products (d)			2				(e)				9				(e)

(a)		We remain at risk for possible changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying hedged item. Effects of these offsets are not reflected in the sensitivity analyses. Amounts reflect hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at March 31, 2006. Included in the natural gas impact shown above are $77 million and $191 million related to the long-term U.K. natural gas contracts for hypothetical price changes of 10 percent and 25 percent, respectively. We evaluate our portfolio of derivative commodity instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed continuously and master netting agreements are used when practical. Changes to the portfolio after March 31, 2006, would cause future IFO effects to differ from those presented in the table.
(b)		The number of net open contracts for the E&P segment varied throughout first quarter 2006, from a low of 925 contracts near the beginning of March to a high of 1,634 contracts in mid-January, and averaged 1,266 for the quarter. The number of net open contracts for the RM&T segment varied throughout first quarter 2006, from a low of 3,867 contracts during mid-February to a high of 14,908 contracts at the beginning of January, and averaged 8,625 for the quarter. The derivative commodity instruments used and hedging positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.
(c)		The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated. Gains and losses on options are based on changes in intrinsic value only.
(d)		The direction of the price change used in calculating the sensitivity amount for each commodity reflects that which would result in the largest incremental decrease in IFO when applied to the commodity derivative instruments used to hedge that commodity.
(e)		Price increase.

E&P Segment

     Derivative gains of $15 million were included in the E&P segment for the first quarter of 2006 and losses of $4 million for the first quarter of 2005. The results of activities primarily associated with the marketing of our equity natural gas production, which had been presented as part of the Integrated Gas segment prior to 2006, are now included in the E&P segment.

     Excluded from the E&P segment results were gains of $78 million and losses of $57 million for the first quarters of 2006 and 2005 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.

     At March 31, 2006, we had no open derivative commodity contracts related to our oil and natural gas production, and therefore we remain exposed to market prices of commodities. We continue to evaluate the commodity price risks related to our production and may enter into derivative commodity instruments when it is deemed advantageous. As a particular but not exclusive example, we may elect to use derivative commodity instruments to achieve minimum price levels on some portion of our production to support capital or acquisition funding requirements.

RM&T Segment

     We do not attempt to qualify commodity derivative instruments used in our RM&T operations for hedge accounting. As a result, we recognize in income all changes in the fair value of derivatives used in our RM&T operations. Pre-tax derivative gains and losses included in RM&T segment income for the first quarters of 2006 and 2005 are summarized in the following table:

		First Quarter Ended March 31,
(Dollars in millions)		2006				2005
Strategy:
Mitigate price risk		$	4			$	(65	)
Protect carrying values of excess inventories			(16	)			(48	)
Protect margin on fixed price sales			4				14
Protect crack spread values			(3	)			(73	)
Subtotal, non-trading activities			(11	)			(172	)
Trading activities			5				(31	)
Total net derivative losses		$	(6	)		$	(203	)

     Derivatives used in non-trading activities have an underlying physical commodity transaction. Derivative losses occur when market prices increase, and generally are offset by gains on the underlying physical commodity transactions. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying physical commodity transactions.

Other Commodity Related Risks

     We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. For example, New York Mercantile Exchange (“NYMEX”) contracts for natural gas are priced at Louisiana’s Henry Hub, while the underlying quantities of natural gas may be produced and sold in the western United States at prices that do not move in strict correlation with NYMEX prices. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased exposure to basis risk. These regional price differences could yield favorable or unfavorable results. Over-the-counter transactions are being used to manage exposure to a portion of basis risk.

     We are impacted by liquidity risk, caused by timing delays in liquidating contract positions due to a potential inability to identify a counterparty willing to accept an offsetting position. Due to the large number of active participants, liquidity risk exposure is relatively low for exchange-traded transactions.

Interest Rate Risk

     We are impacted by interest rate fluctuations which affect the fair value of certain financial instruments. A sensitivity analysis of the projected incremental effect of a hypothetical 10 percent decrease in interest rates as of March 31, 2006 is provided in the following table:

						Incremental Increase in
(Dollars in millions)		Fair Value (b)				Fair Value (c)
Financial assets (liabilities):(a)
Interest rate swap agreements		$	(36	)		$	13
Long-term debt, including that due within one year (d)			(3,924	)			(152	)

(a)		Fair values of cash and cash equivalents, receivables, notes payable, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
(b)		Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.
(c)		Assumes a 10 percent decrease in the March 31, 2006 effective swap rate or a 10 percent decrease in the weighted average yield to maturity of our long-term debt at March 31, 2006, as appropriate.
(d)		See below for sensitivity analysis.

     At March 31, 2006, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to effects of interest rate fluctuations. This sensitivity is illustrated by the $152 million increase in the fair value of long-term debt assuming a hypothetical 10 percent decrease in interest rates. However, our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio

would unfavorably affect our results of operations and cash flows only if we would elect to repurchase or otherwise retire all or a portion of its fixed-rate debt portfolio at prices above carrying value.

     We manage our exposure to interest rate movements by utilizing financial derivative instruments. The primary objective of this program is to reduce our overall cost of borrowing by managing the fixed and floating interest rate mix of the debt portfolio. We have entered into several interest rate swap agreements, designated as fair value hedges, which effectively resulted in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates. There have been no unexpected changes to the positions subsequent to December 31, 2005.

Foreign Currency Exchange Rate Risk

     We manage our exposure to foreign currency exchange rates by utilizing forward and option contracts. The primary objective of this program is to reduce our exposure to movements in the foreign currency markets by locking in foreign currency rates. The aggregate effect on foreign exchange contracts of a hypothetical 10 percent change to quarter-end forward exchange rates would be approximately $5 million. There have been no significant changes to our exposure to foreign exchange rates subsequent to December 31, 2005.

Credit Risk

     We are exposed to significant credit risk from United States Steel arising from the Separation. That exposure is discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations – Obligations Associated with the Separation of United States Steel.

Safe Harbor

     These quantitative and qualitative disclosures about market risk include forward-looking statements with respect to management’s opinion about risks associated with the use of derivative instruments. These statements are based on certain assumptions with respect to market prices and industry supply of and demand for crude oil, natural gas, refined products and other feedstocks. If these assumptions prove to be inaccurate, future outcomes with respect to our hedging programs may differ materially from those discussed in the forward-looking 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-14 and 15d-14 under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of Marathon’s 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 March 31, 2006, there were no changes in our internal controls over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal controls over financial reporting.

     Marathon reviews and modifies its financial and operational controls on an ongoing basis to ensure that those controls are adequate to address changes in its business as it evolves. Marathon believes that its existing financial and operational controls and procedures are adequate.

MARATHON OIL CORPORATION

		First Quarter Ended March 31,
(Dollars in millions, except as noted)		2006				2005
SEGMENT INCOME:
Exploration and Production
United States		$	245			$	177
International			232				157
E&P Segment			477				334
Refining, Marketing and Transportation(a)			319				74
Integrated Gas			8				22
Segment Income			804				430
Items not allocated to segments, net of income taxes:
Gain (loss) on long-term U.K. natural gas contracts			45				(33	)
Corporate and other unallocated items			(65	)			(73	)
Net income		$	784			$	324
CAPITAL EXPENDITURES:
Exploration and Production		$	384			$	294
Refining, Marketing and Transportation(a)			104				136
Integrated Gas(b)			94				125
Corporate			17				1
Total		$	599			$	556
EXPLORATION EXPENSE:
United States		$	28			$	17
International			43				17
Total		$	71			$	34
E&P OPERATING STATISTICS
Net Liquid Hydrocarbon Sales (mbpd)
United States			80				72
Europe			30				31
Africa			72				36
Other International			29				24
Total International			131				91
Worldwide			211				163
Net Natural Gas Sales (mmcfd)(c)(d)
United States			561				570
Europe			347				372
Africa			88				83
Total International			435				455
Worldwide			996				1,025
Total Sales (mboepd)			377				334

(a)		RM&T segment income for the first quarter of 2005 is net of $76 million pretax minority interest in MPC. RM&T capital expenditures include MPC at 100 percent.
(b)		Includes Equatorial Guinea LNG Holdings at 100 percent.
(c)		Amounts reflect sales after royalties, except for Ireland where amounts are before royalties.
(d)		Includes natural gas acquired for injection and subsequent resale of 40.6 mmcfd and 20.5 mmcfd in the first quarters of 2006 and 2005. Effective July 1, 2005, the methodology for allocating sales volumes between natural gas produced from the Brae complex and third-party natural gas production was modified, resulting in an increase in volumes representing natural gas acquired for injection and subsequent resale.

MARATHON OIL CORPORATION

		First Quarter Ended March 31,
		2006				2005
E&P OPERATING STATISTICS (continued)
Average Realizations (e)
Liquid Hydrocarbons ($  per bbl)
United States		$	49.30			$	38.47
Europe			62.14				45.34
Africa			51.35				43.23
Other International			37.39				24.79
Total International			50.68				39.10
Worldwide		$	50.16			$	38.82
Natural Gas ($  per mcf)
United States		$	6.66			$	4.95
Europe			7.66				5.05
Africa			0.25				0.24
Total International			6.16				4.17
Worldwide		$	6.44			$	4.60
RM&T OPERATING STATISTICS
Refinery Runs (mbpd):
Crude oil refined			898				922
Other charge and blend stocks			249				172
Total			1,147				1,094
Refined Product Yields (mbpd):
Gasoline			645				576
Distillates			290				292
Propane			20				19
Feedstocks and special products			108				116
Heavy fuel oil			24				33
Asphalt			75				72
Total			1,162				1,108
Refined Products Sales Volumes (mbpd)(f)			1,417				1,370
Matching buy/sell volumes included in refined product sales volumes (mbpd)			83				80
Refining and Wholesale Marketing Gross Margin (per gallon)(g)		$	0.1137			$	0.0685
Number of SSA Retail Outlets			1,635				1,659
SSA Gasoline and Distillate Sales (millions of gallons)			776				745
SSA Gasoline and Distillate Gross Margin (per gallon)		$	0.1055			$	0.1058
SSA Merchandise Sales		$	610			$	560
SSA Merchandise Gross Margin		$	148			$	143