MARATHON OIL CORPORATION

Form 10-Q

Quarter Ended ~~September 30, 2005~~March 31, 2006

INDEX


			Page
PART I -— FINANCIAL INFORMATION

	Item 1.	Financial Statements:

		Consolidated Statements of Income ~~(Unaudited)~~		3

		Consolidated Balance Sheets ~~(Unaudited)~~		4

		Consolidated Statements of Cash Flows ~~(Unaudited)~~		5

		Selected Notes to Consolidated Financial Statements ~~(Unaudited)~~		6

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15

	Item 3.	Quantitative and Qualitative Disclosures ~~about~~About Market Risk		25

	Item 4.	Controls and Procedures		28

		Supplemental Statistics ~~(Unaudited)~~		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). OnEffective September 1, 2005, ~~subsequent to the acquisition discussed on page 7,~~ 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

Consolidated Statements of Income (Unaudited)


	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

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

(Dollars in millions, except per share data)

2005

2004

2005

2004

Revenues and other income:

Sales and other operating revenues (including consumer excise taxes)

$
13,345

$
9,701

$
35,271

$
27,935

Revenues from matching buy/sell transactions

3,433

2,263

9,807

6,714

Sales to related parties

396

285

1,047

766

Income from equity method investments

69

38

154

108

Net gains on disposal of assets

12

17

46

25

Gain on ownership change in Marathon Petroleum Company LLC

—

1

—

2

Other income (loss) – net

(7
)
11

34

51

Total revenues and other income

17,248

12,316

46,359

35,601

Costs and expenses:

Cost of revenues (excluding items shown below)

10,833

7,699

27,790

21,676

Purchases related to matching buy/sell transactions

3,038

2,197

9,312

6,588

Purchases from related parties

44

58

163

152

Consumer excise taxes

1,217

1,137

3,511

3,327

Depreciation, depletion and amortization

331

296

993

896

Selling, general and administrative expenses

325

261

853

763

Other taxes

128

80

352

242

Exploration expenses

64

46

135

108

Total costs and expenses

15,980

11,774

43,109

33,752

Income from operations

1,268

542

3,250

1,849

Net interest and other financing costs

32

40

99

129

Minority interests in income (loss) of:

Marathon Petroleum Company LLC

—

148

384

385

Equatorial Guinea LNG Holdings Limited

(3
)
(1
)
(4
)
(5
)
Income from continuing operations before income taxes

1,239

355

2,771

1,340

Provision for income taxes

469

133

1,004

512

Income from continuing operations

770

222

1,767

828

Discontinued operations

—

—

—

4

Net income

$
770

$
222

$
1,767

$
832

~~Income Per Share (Unaudited)~~

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

2005

2004

2005

2004

Basic:

Income from continuing operations

$
2.11

$
0.64

$
5.01

$
2.48

Net income

$
2.11

$
0.64

$
5.01

$
2.49

Diluted:

Income from continuing operations

$
2.09

$
0.64

$
4.97

$
2.47

Net income

$
2.09

$
0.64

$
4.97

$
2.48

Dividends paid per share

$
0.33

$
0.25

$
0.89

$
0.75

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

MARATHON OIL CORPORATION

Consolidated Balance Sheets (Unaudited)


	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

(Dollars in millions, except per share data)

September 30,
2005

December 31,
2004

Assets

Current assets:

Cash and cash equivalents

$
1,043

$
3,369

Receivables, less allowance for doubtful accounts of $3 and $6

3,808

3,146

Receivables from United States Steel

21

15

Receivables from related parties

102

74

Inventories

3,338

1,995

Other current assets

211

267

Total current assets

8,523

8,866

Investments and long-term receivables, less allowance for doubtful accounts of $11 and $10

1,830

1,546

Receivables from United States Steel

576

587

Property, plant and equipment, less accumulated depreciation, depletion and amortization of $12,060 and $12,426

13,704

11,810

Prepaid pensions

102

128

Goodwill

950

252

Intangibles

184

118

Other assets

116

116

Total assets

$
25,985

$
23,423

Liabilities

Current liabilities:

Commercial paper payable

$
285

$
—

Accounts payable

5,194

4,430

Payables to related parties

52

44

Payables to United States Steel

6

—

Payroll and benefits payable

279

274

Accrued taxes

576

397

Deferred income taxes

496

—

Accrued interest

52

92

Long-term debt due within one year

316

16

Total current liabilities

7,256

5,253

Long-term debt

3,728

4,057

Deferred income taxes

1,777

1,553

Employee benefits obligations

1,204

989

Asset retirement obligations

505

477

Payables to United States Steel

5

5

Deferred credits and other liabilities

451

288

Total liabilities

14,926

12,622

Minority interest in Marathon Petroleum Company LLC

—

2,559

Minority interests in Equatorial Guinea LNG Holdings Limited

417

131

Commitments and contingencies

Stockholders’ Equity

Common stock:

Common stock issued – 366,705,131 shares at September 30, 2005 and 346,727,029 shares at December 31, 2004 (par value $1 per share, 550,000,000 shares authorized)

367

347

Common stock held in treasury – 225,778 shares at September 30, 2005 and 29,569 shares at December 31, 2004

(9
)
(1
)
Additional paid-in capital

5,092

4,028

Retained earnings

5,261

3,810

Accumulated other comprehensive loss

(56
)
(64
)
Unearned compensation

(13
)
(9
)
Total stockholders’ equity

10,642

8,111

Total liabilities and stockholders’ equity

$
25,985

$
23,423

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

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows (Unaudited)

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

Nine Months Ended
September 30,

(Dollars in millions)

2005

2004

Increase (decrease) in cash and cash equivalents

Operating activities

Net income

$
1,767

$
832

Adjustments to reconcile net income to net cash provided from operating activities:

Income from discontinued operations

—

(4
)
Deferred income taxes

(83
)
(26
)
Minority interests in income of subsidiaries

380

380

Depreciation, depletion and amortization

993

896

Pension and other postretirement benefits - net

21

30

Exploratory dry well costs

66

44

Net gains on disposal of assets

(46
)
(25
)
Changes in the fair value of long-term natural gas contracts in the United Kingdom

306

210

Changes in working capital:

Current receivables

(1,577
)
(441
)
Inventories

(457
)
(372
)
Current accounts payable and accrued expenses

727

554

All other - net

(134
)
(101
)

Net cash provided from operating activities

1,963

1,977

Investing activities

Capital expenditures

(2,015
)
(1,377
)
Acquisition

(506
)
—

Disposal of assets

99

47

Proceeds from sale of minority interests in Equatorial Guinea LNG Holdings Limited

163

—

Restricted cash
- deposits

(27
)
(25
)

- withdrawals

19

6

Investments - loans and advances

(40
)
(152
)
All other - net

6

3

Net cash used in investing activities

(2,301
)
(1,498
)

Financing activities

Payment of debt assumed in acquisition

(1,920
)
—

Commercial paper and revolving credit arrangements - net

285

—

Debt issuance costs

—

(5
)
Other debt repayments

(7
)
(257
)
Issuance of common stock

77

1,036

Dividends paid

(314
)
(251
)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited

175

95

Distributions to minority shareholder of Marathon Petroleum Company LLC

(272
)
–

Net cash provided from (used in) financing activities

(1,976
)
618

Effect of exchange rate changes on cash

(12
)
(1
)
Net increase (decrease) in cash and cash equivalents

(2,326
)
1,096

Cash and cash equivalents at beginning of period

3,369

1,396

Cash and cash equivalents at end of period

$
1,043

$
2,492

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

MARATHON OIL CORPORATION
Notes to Consolidated Financial Statements (Unaudited)
1.~~Basis of Presentation~~
These consolidated financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for a fair presentation of the results for the periods presented. 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 2005 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”) 2004 Annual Report on Form 10-K.
2.~~New Accounting Standards~~
Effective January 1, 2005, Marathon adopted FASB Staff Position (“FSP”) No. FAS 19-1, “Accounting for Suspended Well Costs,” which amended the guidance for suspended exploratory well costs in Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” SFAS No. 19 requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. When a classification of proved reserves cannot yet be made, FSP No. FAS 19-1 allows exploratory well costs to continue to be capitalized when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. Marathon’s accounting policy for suspended exploratory well costs was in accordance with FSP No. FAS 19-1 prior to its adoption. FSP No. FAS 19-1 also requires certain disclosures to be made regarding capitalized exploratory well costs which were included in the footnotes to Marathon’s consolidated financial statements in its 2004 Annual Report on Form 10-K.
In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets – an amendment of APB Opinion No. 29.” This amendment eliminates the APB Opinion No. 29 exception for fair value recognition of nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance. Marathon adopted SFAS No. 153 on a prospective basis as of July 1, 2005.
3.~~Information about United States Steel~~
~~The Separation –~~ On December 31, 2001, in a tax-free distribution to holders of Marathon’s USX—U. S. Steel Group class of common stock (“Steel Stock”), Marathon exchanged the common stock of its wholly owned subsidiary United States Steel Corporation (“United States Steel”) for all outstanding shares of Steel Stock on a one-for-one basis (the “Separation”).
~~Amounts Receivable from or Payable to United States Steel Arising from the Separation –~~ Marathon remains primarily obligated for certain financings for which United States Steel has assumed responsibility for repayment under the terms of the Separation. When United States Steel makes payments on the principal of these financings, both the receivable from United States Steel and the obligation are reduced.
~~Amounts receivable from and payable to United States Steel included in the consolidated balance sheet were as follows:~~

September 30,

December 31,

(In millions)

2005

2004

Receivables related to debt and other obligations for which United States Steel has assumed responsibility for repayment:

Current

$
21

$
15

Noncurrent

576

587

Current income tax settlement and related interest payable

$
6

$
—

Noncurrent reimbursements payable under nonqualified employee benefit plans

5

5

Marathon remains primarily obligated for $46 million of operating lease obligations assumed by United States Steel, of which $37 million has been assumed by third parties that purchased plants and operations divested by United States Steel.
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.
6

4.~~Acquisition~~
On June 30, 2005, Marathon acquired the 38 percent ownership interest in Marathon Ashland Petroleum LLC (“MAP”) previously held by Ashland Inc. (“Ashland”). In addition, Marathon acquired a portion of Ashland’s Valvoline Instant Oil Change business, its maleic anhydride business, its interest in LOOP LLC, which owns and operates the only U.S. deepwater oil port, and its interest in LOCAP LLC, which owns a crude oil pipeline. As a result of the transactions (the “Acquisition”), MAP is now wholly owned by Marathon and its name was changed to Marathon Petroleum Company LLC (“MPC”) effective September 1, 2005. The Acquisition was accounted for under the purchase method of accounting ~~and, as such, Marathon’s results of operations include the results of the acquired businesses from June 30, 2005. The total consideration, including debt assumed, is as follows:~~
(In millions)

Amount

Cash (a)

$
487

MPC accounts receivable (a)

913

Marathon common stock (b)

955

Estimated additional consideration related to tax matters (c)

44

Transaction-related costs

10

Purchase price

$
2,409

Assumption of debt (d)

1,920

Total consideration including debt assumption(e)

$
4,329

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.
~~(a)~~The MAP Limited Liability Company Agreement was amended to eliminate the requirement for MPC to make quarterly cash distributions to Marathon and Ashland between the date the principal transaction agreements were signed and the closing of the Acquisition. Cash and MPC accounts receivable above include $509 million representing Ashland’s 38 percent of MPC’s estimated distributable cash as of June 30, 2005.
~~(b)~~Ashland shareholders received 17.539 million shares valued at $54.45 per share, which was Marathon’s average common stock price over the trading days between June 23 and June 29, 2005. The exchange ratio was designed to provide an aggregate number of Marathon shares worth $915 million based on Marathon’s average common stock price for each of the 20 consecutive trading days ending with the third complete trading day prior to June 30, 2005.
~~(c)Includes $9 million paid during the quarter ended September 30, 2005, for estimated tax obligations of Ashland under Internal Revenue Service Code Section 355(e).~~
~~(d)Assumed debt was repaid on July 1, 2005.~~
~~(e)~~Marathon is entitled to the tax deductions for Ashland’s future payments of certain contingent liabilities related to businesses previously owned by Ashland. However, pursuant to the terms of the Tax Matters Agreement, Marathon has agreed to reimburse Ashland for a portion of these future payments. This contingent consideration will be included in the purchase price as such payments are made to Ashland.
~~The primary reasons for the Acquisition and the principal factors that contributed to a purchase price that resulted in the recognition of goodwill are:~~
•Marathon believes the outlook for the refining and marketing business is attractive in MPC’s core areas of operation. Complete ownership of MPC provides Marathon the opportunity to leverage MPC’s access to premium U.S. markets where Marathon expects the levels of demand to remain high for the foreseeable future;
•~~The Acquisition increases Marathon’s participation in the downstream business without the risks commonly associated with integrating a newly acquired business;~~
•~~MPC provides Marathon with an increased source of cash flow which Marathon believes enhances the geographical balance in its overall risk portfolio;~~
•~~Marathon anticipates the transaction will be accretive to income per share;~~
•The Acquisition eliminated the timing and valuation uncertainties associated with the exercise of the Put/Call, Registration Rights and Standstill Agreement entered into with the formation of MPC in 1998, as well as the associated premium and discount; and
•~~The Acquisition eliminated the possibility that a misalignment of Ashland’s and Marathon’s interests, as co-owners of MPC, could adversely affect MPC’s future growth and financial performance.~~
7

The allocation of the purchase price to specific assets and liabilities was based primarily on a third-party appraisal of the fair value of the acquired assets. The allocation of the purchase price is preliminary, pending the completion of that third-party valuation. The following table summarizes the preliminary purchase price allocation to the fair values of the assets acquired and liabilities assumed as of June 30, 2005:
(In millions)

Current assets:

Cash and cash equivalents

$
518

Receivables

1,080

Inventories

1,866

Other current assets

28

Total current assets acquired

3,492

Investments and long-term receivables

482

Property, plant and equipment

2,691

Goodwill

694

Intangibles

109

Other assets

8

Total assets acquired

$
7,476

Current liabilities:

Notes payable

$
1,920

Deferred income taxes

669

Other current liabilities

1,700

Total current liabilities assumed

4,289

Long-term debt

16

Deferred income taxes

246

Employee benefits obligations

483

Other liabilities

33

Total liabilities assumed

$
5,067

Net assets acquired

$
2,409

~~The preliminary valuations and lives of acquired intangible assets are as follows:~~
(In millions)

Lives

Amount

Retail marketing tradenames

Various

$
52

Refinery permits and plans

15 years

26

Marketing brand agreements

5-10 years

13

Refining technology

5-15 years

12

Other

Various

6

Total

$
109

The goodwill arising from the preliminary allocation was $694 million, which was assigned to the refining, marketing and transportation segment. None of the goodwill is deductible for tax purposes. The goodwill decreased $109 million from the initial estimated purchase price allocation as of June 30, 2005 primarily as a result of an $80 million reduction in the estimated additional consideration related to tax matters.
The purchase price allocated to equity method investments is $230 million higher than the underlying net assets of the investees. This excess will be amortized over the expected useful life of the underlying assets except for goodwill related to the equity investments.
The following unaudited pro forma results of operations are as if the Acquisition had been consummated at the beginning of each period presented. The pro forma data is based on historical information and does not reflect the actual results that would have occurred nor is it indicative of future results of operations.

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

(In millions, except per share data)

2005

2004

2005

2004

Revenues and other income

$
17,248

$
12,326

$
46,405

$
35,656

Net income

$
770

$
294

$
1,976

$
1,025

Net income per share:

Basic

$
2.11

$
0.81

$
5.42

$
2.92

Diluted

$
2.09

$
0.81

$
5.38

$
2.91

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.
8

5.~~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.

Third Quarter Ended September 30,

2005

2004

(Dollars in millions, except per share data)

Basic

Diluted

Basic

Diluted

Net income

$
770

$
770

$
222

$
222

Shares of common stock outstanding (in thousands):

Average number of common shares outstanding

365,137

365,137

345,037

345,037

Effect of dilutive securities – stock options

—

3,427

—

1,932

Average common shares including dilutive effect

365,137

368,564

345,037

346,969

Net income per share

$
2.11

$
2.09

$
0.64

$
0.64

Nine Months Ended September 30,

2005

2004

(Dollars in millions, except per share data)

Basic

Diluted

Basic

Diluted

Income from continuing operations

$
1,767

$
1,767

$
828

$
828

Income from discontinued operations

—

—

4

4

Net income

$
1,767

$
1,767

$
832

$
832

Shares of common stock outstanding (in thousands):

Average number of common shares outstanding

352,807

352,807

333,456

333,456

Effect of dilutive securities – stock options

—

2,919

—

1,713

Average common shares including dilutive effect

352,807

355,726

333,456

335,169

Per share:

Income from continuing operations

$
5.01

$
4.97

$
2.48

$
2.47

Income from discontinued operations

$
—

$
—

$
0.01

$
0.01

Net income

$
5.01

$
4.97

$
2.49

$
2.48

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.
9

6.~~Stock-Based Compensation Plans~~
~~The following presents the effect on net income and net income per share if the fair value method had been applied to all outstanding awards in each period:~~

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

(In millions, except per share data)

2005

2004

2005

2004

Net income:

As reported

$
770

$
222

$
1,767

$
832

Add: Stock-based compensation expense included in reported net income, net of related tax effects

28

19

69

43

Deduct: Total stock-based compensation expense determined under fair value method for all awards, net of related tax effects

(28
)
(15
)
(69
)
(31
)
Pro forma net income

$
770

$
226

$
1,767

$
844

Basic net income per share:

As reported

$
2.11

$
0.64

$
5.01

$
2.49

Pro forma

$
2.11

$
0.65

$
5.01

$
2.53

Diluted net income per share:

As reported

$
2.09

$
0.64

$
4.97

$
2.48

Pro forma

$
2.09

$
0.65

$
4.97

$
2.52

Marathon records compensation cost over the stated vesting period for stock options that are subject to specific vesting conditions and specify (i) that an employee vests in the award upon becoming “retirement eligible” or (ii) that the employee will continue to vest in the award after retirement without providing any additional service. Upon adoption of SFAS No. 123 (Revised 2004), “Share-Based Payment,” such compensation cost will be 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. The compensation cost determined under these two approaches did not differ materially for the periods presented above.
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

10

7.~~Segment Information~~
Marathon’s operations consist of three operating segments: 1) Exploration and Production (“E&P”) - - explores for and produces 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 natural gas and products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis.
~~The following presents information by operating segment:~~
(In millions)

E&P

RM&T

IG

Total
Segments

Third Quarter 2005

Revenues:

Customer

$
1,400

$
14,989

$
471

$
16,860

Intersegment(a)

104

78

46

228

Related parties

3

393

—

396

Segment revenues

1,507

15,460

517

17,484

Elimination of intersegment revenues

(104
)
(78
)
(46
)
(228
)
Loss on long-term U.K. gas contracts

(82
)
—

—

(82
)
Total revenues

$
1,321

$
15,382

$
471

$
17,174

Segment income

$
627

$
814

$
(6
)
$
1,435

Income from equity method investments

15

38

16

69

Depreciation, depletion and amortization(b)

198

123

2

323

Capital expenditures(c)

387

201

205

793

Third Quarter 2004

Revenues:

Customer

$
1,110

$
10,578

$
405

$
12,093

Intersegment (a)

99

38

42

179

Related parties

2

283

—

285

Segment revenues

1,211

10,899

447

12,557

Elimination of intersegment revenues

(99
)
(38
)
(42
)
(179
)
Loss on long-term U.K. gas contracts

(129
)
—

—

(129
)
Total revenues

$
983

$
10,861

$
405

$
12,249

Segment income

$
351

$
391

$
18

$
760

Income from equity method investments

8

17

13

38

Depreciation, depletion and amortization(b)

180

105

2

287

Capital expenditures(c)

249

146

58

453

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 are included in administrative expenses in the reconciliation below.~~
~~(c)Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities.~~
^(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.
11

(In millions)

E&P

RM&T

IG

Total
Segments

Nine Months 2005

Revenues:

Customer

$
4,139

$
39,939

$
1,306

$
45,384

Intersegment(a)

291

161

134

586

Related parties

8

1,039

—

1,047

Segment revenues

4,438

41,139

1,440

47,017

Elimination of intersegment revenues

(291
)
(161
)
(134
)
(586
)
Loss on long-term U.K. gas contracts

(306
)
—

—

(306
)
Total revenues

$
3,841

$
40,978

$
1,306

$
46,125

Segment income

$
1,958

$
1,847

$
12

$
3,817

Income from equity method investments

34

71

49

154

Depreciation, depletion and amortization(b)

631

332

6

969

Capital expenditures(c)

1,000

498

513

2,011

Nine Months 2004

Revenues:

Customer

$
3,421

$
30,262

$
1,176

$
34,859

Intersegment(a)

261

95

114

470

Related parties

9

757

—

766

Segment revenues

3,691

31,114

1,290

36,095

Elimination of intersegment revenues

(261
)
(95
)
(114
)
(470
)
Loss on long-term U.K. gas contracts

(210
)
—

—

(210
)
Total revenues

$
3,220

$
31,019

$
1,176

$
35,415

Segment income

$
1,253

$
1,017

$
25

$
2,295

Income from equity method investments

17

48

43

108

Depreciation, depletion and amortization(b)

560

307

6

873

Capital expenditures(c)

601

419

346

1,366

~~(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 are included in administrative expenses 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 income from operations as reported in Marathon’s consolidated statements of income:~~

Third Quarter Ended
September 30,

(In millions)

2005

2004

Segment income

$
1,435

$
760

Items not allocated to segments:

Administrative expenses

(108
)
(90
)
Loss on long-term U.K. gas contracts

(82
)
(129
)
Gain on ownership change in MPC

—

1

Gain on sale of minority interests in Equatorial Guinea LNG Holdings Limited

23

—

Total income from operations

$
1,268

$
542

Nine Months Ended
September 30,

(In millions)

2005

2004

Segment income

$
3,817

$
2,295

Items not allocated to segments:

Administrative expenses

(284
)
(238
)
Loss on long-term U.K. gas contracts

(306
)
(210
)
Gain on ownership change in MPC

—

2

Gain on sale of minority interests in Equatorial Guinea LNG Holdings Limited

23

—

Total income from operations

$
3,250

$
1,849

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.
12

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

Pension Benefits

Other Benefits

Third Quarter Ended September 30,

(In millions)

2005

2004

2005

2004

Service cost

$
31

$
24

$
5

$
4

Interest cost

30

26

10

8

Expected return on plan assets

(24
)
(23
)
—

—

Amortization
– net transition gain

(1
)
(1
)
—

—

– prior service costs (credits)

1

1

(3
)
(2
)

– actuarial loss

12

12

2

—

Multi-employer and other plans

1

—

1

1

Settlement and curtailment losses (gains) (a)

—

19

—

(9
)
Net periodic benefit cost(b)

$
50

$
58

$
15

$
2

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
~~(a)Includes $10 million in costs related to business transformation programs for the third quarter of 2004.~~
~~(b)~~Includes MPC’s net periodic pension cost of $34 million and $29 million and other benefits cost of $9 million and $6 million for the third quarter of 2005 and 2004. Includes international net periodic pension cost of $5 million and $6 million for the third quarter of 2005 and 2004.

Pension Benefits

Other Benefits

Nine Months Ended September 30,

(In millions)

2005

2004

2005

2004

Service cost

$
88

$
76

$
14

$
14

Interest cost

88

80

29

32

Expected return on plan assets

(70
)
(69
)
—

—

Amortization
– net transition gain

(3
)
(3
)
—

—

– prior service costs (credits)

3

3

(9
)
(10
)

– actuarial loss

42

38

7

8

Multi-employer and other plans

2

1

2

2

Settlement and curtailment losses (gains) (c)

—

29

—

(9
)
Net periodic benefit cost (d)

$
150

$
155

$
43

$
37

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 ) —

~~(c)Includes $13 million in costs related to business tranformation programs for the first nine months of 2004.~~
~~(d)~~Includes MPC’s net periodic pension cost of $102 million and $88 million and other benefits cost of $26 million and $25 million for the first nine months of 2005 and 2004. Includes international net periodic pension cost of $16 million and $17 million for the first nine months of 2005 and 2004.
During the nine months ended September 30, 2005, MPC contributed $127 million to its qualified pension plan and Marathon contributed $16 million to its international pension plans. Marathon expects to contribute an additional $15 million to its international pension plans during the remainder of 2005. In addition, during the nine months ended September 30, 2005, contributions made from the general assets of Marathon to cover current benefit payments related to unfunded pension and other postretirement benefit plans were $2 million and $24 million.
On June 30, 2005, as a result of the Acquisition, MPC’s pension and other postretirement benefit plan obligations were remeasured using current discount rates and plan assumptions. The discount rate was decreased to 5.25 percent from 5.75 percent. As part of the application of the purchase method of accounting, MPC recognized 38 percent of its unrecognized net transition gain, prior service costs and actuarial losses related to its pension and other postretirement benefit plans. As a result, obligations related to the pension and other postretirement benefit plans increased by $263 million and $28 million.
In addition, certain employees of the maleic anhydride business were granted credit for prior service and extended pension and other postretirement benefits under the MPC plans which increased MPC’s obligations by $5 million for both the pension and other postretirement benefit plans. There was not a material impact to future net periodic benefit cost for the remainder of 2005.
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.
13

9.~~Income Taxes~~
The provision for income taxes for interim periods is based on Marathon’s best estimate of the effective tax rate expected to be applicable for the current fiscal year plus any adjustments arising from a change in the estimated amount of taxes related to prior periods.
In the second quarter of 2005, the state of Ohio enacted legislation which phases out Ohio’s income-based franchise taxes over a five-year period. Marathon’s provision for income taxes for the first nine months of 2005 includes a $15 million benefit related to the reversal of deferred income taxes as a result of this change in tax law. The state of Ohio replaced the income-based franchise tax with a commercial activity tax based on gross receipts which will be phased in over five years. The commercial activity tax will be reported in costs and expenses.
In the first quarter of 2005, the state of Kentucky enacted legislation which causes limited liability companies to be subject to Kentucky’s corporation income tax. In the first nine months of 2005, Marathon’s provision for income taxes includes $13 million related to the effects of this Kentucky income tax on deferred tax assets and liabilities as of January 1, 2005. The unfavorable effect on net income (after minority interest) was $6 million.
Also beginning in the first quarter of 2005, Marathon’s effective tax rate reflects the estimated impact of a special deduction for qualified domestic production expected to be taken as a result of the American Jobs Creation Act of 2004. This deduction will be treated as a permanent difference. Based on Marathon’s best estimate of taxable income for 2005, the deduction will reduce the effective tax rate by approximately one-half percent.
~~10.~~~~Comprehensive Income~~
~~The following presents Marathon’s comprehensive income for the periods shown:~~

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

(In millions)

2005

2004

2005

2004

Net income

$
770

$
222

$
1,767

$
832

Other comprehensive income (loss), net of tax

Minimum pension liability adjustments

—

—

24

—

Change in fair value of derivative instruments

(1
)
(5
)
(16
)
(26
)
Total comprehensive income

$
769

$
217

$
1,775

$
806

During the third quarter and first nine months of 2004, $2 million of losses related to derivative instruments, net of tax, were reclassified into net income as it was no longer probable the related forecasted transactions would occur.
~~11.~~~~Inventories~~
~~Inventories are carried at lower of cost or market. Cost of inventories of crude oil and refined products is determined primarily under the last-in, first-out (“LIFO”) method.~~
(In millions)

September 30,
2005

December 31,
2004

Liquid hydrocarbons and natural gas

$
1,340

$
676

Refined products and merchandise

1,862

1,192

Supplies and sundry items

136

127

Total (at cost)

$
3,338

$
1,995

~~12.~~~~Suspended Exploratory Well Costs~~
Marathon’s suspended exploratory well costs at September 30, 2005 were $344 million, an increase of $5 million from December 31, 2004, due to drilling activities in several countries offset by transfers to proved properties and dry well expense. During the first nine months of 2005, there were no impairments of exploratory well costs that had been capitalized for a period of greater than one year after the completion of drilling at December 31, 2004.
During the quarter ended September 30, 2005, $22 million of exploratory well costs related to the Annapolis project offshore Nova Scotia were written off. Sufficient progress toward an economically viable project had not been made since completion of drilling in this prospect in the third quarter of 2004.
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.
14

~~13.~~~~Debt~~
At September 30, 2005, Marathon had no borrowings against its $1.5 billion long-term revolving credit facility and had $285 million of commercial paper outstanding under its U.S. commercial paper program that is backed by the long-term revolving credit facility. Certain banks provide Marathon with uncommitted short-term lines of credit totaling $200 million. At September 30, 2005, there were no borrowings against these facilities.   Additionally, as part of the Acquisition on June 30, 2005 discussed in Note 4, Marathon assumed $1.920 billion in debt which was repaid on July 1, 2005.
~~MPC has a $500 million long-term revolving credit facility that terminates in May 2009. At September 30, 2005, there were no borrowings against this facility.~~
In the event of a change in control of Marathon, debt obligations totaling $1.574 billion at September 30, 2005 may be declared immediately due and payable. In such event, Marathon may also be required to either repurchase certain equipment at United States Steel’s Fairfield Works for $82 million or provide a letter of credit to secure the remaining obligation.
~~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 is structured to allow MPC to periodically sell a participating interest in pools of eligible accounts receivable. If any receivables are sold under the facility, MPC will not guarantee the transferred receivables and will have no obligations upon default. During the term of the agreement MPC is obligated to pay a facility fee of 0.12%. As of September 30, 2005 no receivables had been sold under this agreement.
~~15.~~~~Supplemental Cash Flow Information~~

Nine Months Ended
September 30,

(In millions)

2005

2004

Net cash provided from operating activities included:

Interest and other financing costs paid (net of amount capitalized)

$
167

$
198

Income taxes paid to taxing authorities

917

539

Commercial paper and revolving credit arrangements - net:

Commercial paper
– issued

$
3,863

$
—

– repayments

(3,578
)
—

Credit agreements
– borrowings

10

—

– repayments

(10
)
—

Ashland credit agreements
– borrowings

—

653

– repayments

—

(653
)
Total

$
285

$
—

Noncash investing and financing activities:

Asset retirement costs capitalized

$
12

$
17

Debt payments assumed by United States Steel

8

13

Disposal of assets:

Asset retirement obligations assumed by buyer

3

—

Acquisitions:

Debt and other liabilities assumed

4,162

—

Common stock issued to seller

955

—

Receivables transferred to seller

913

—

15

~~16.~~~~Sale of Minority Interests in EGHoldings~~
In connection with the formation of Equatorial Guinea LNG Holdings Limited (“EGHoldings”), Compania Nacional de Petroleos de Guinea Ecuatorial (“GEPetrol”) was given certain contractual rights that gave GEPetrol the option to purchase and resell a 13 percent interest in EGHoldings held by Marathon to a third party. On July 25, 2005, GEPetrol exercised these rights and reimbursed Marathon for its actual costs incurred up to the date of closing, plus an additional specified rate of return. Marathon and GEPetrol entered into agreements under which Mitsui & Co., Ltd. (“Mitsui”) and a subsidiary of Marubeni Corporation (“Marubeni”) acquired 8.5 percent and 6.5 percent interests, respectively, in EGHoldings. As part of these agreements, Marathon sold a 2 percent interest in EGHoldings to Mitsui for its actual costs incurred up to the date of closing, plus a specified rate of return, as well as a premium and future consideration based upon the performance of EGHoldings. Following the transaction, Marathon holds a 60 percent interest in EGHoldings, with GEPetrol holding a 25 percent interest and Mitsui and Marubeni holding the remaining interests.
During the quarter ended September 30, 2005, Marathon received net proceeds of $163 million in connection with the transactions and recorded a gain of $23 million, which is included in other income (loss) – net.
~~17.~~~~Contingencies and Commitments~~
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 matters 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.
~~Environmental matters~~ – Marathon is subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance. At September 30, 2005 and December 31, 2004, accrued liabilities for remediation totaled $109 million and $110 million. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed. Receivables for recoverable costs from certain states, under programs to assist companies in cleanup efforts related to underground storage tanks at retail marketing outlets, were $69 million at September 30, 2005, and $65 million at December 31, 2004.
~~Contract commitments~~ ~~– At September 30, 2005, Marathon’s contract commitments to acquire property, plant and equipment and long-term investments totaled $1.026 billion.~~
~~Other Contingencies~~ – Marathon is a defendant along with many other refining companies in over forty cases in eleven states alleging methyl tertiary-butyl ether (‘‘MTBE’’) contamination in groundwater. The plaintiffs generally are water providers or governmental authorities and they allege that refiners, manufacturers and sellers of gasoline containing MTBE are liable for manufacturing a defective product and that owners and operators of retail gasoline sites have allowed MTBE to be discharged into the groundwater. Several of these lawsuits allege contamination that is outside of Marathon’s marketing area. A few of the cases seek approval as class actions. Many of the cases seek punitive damages or treble damages under a variety of statutes and theories. Marathon stopped producing MTBE at its refineries in October 2002. The potential impact of these recent cases and future potential similar cases is uncertain.
16

~~18.~~~~Accounting Standards Not Yet Adopted~~
In December 2004, the FASB issued 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 will be 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 will be remeasured each reporting period. In 2003, Marathon adopted the fair value method for grants made, modified or settled on or after January 1, 2003. Accordingly, Marathon does not expect the adoption of SFAS No. 123(R) to have a material effect on its consolidated results of operations, financial position or cash flows. The statement provided for an effective date of July 1, 2005, for Marathon. However, in April 2005, the Securities and Exchange Commission adopted a rule that, for Marathon, defers the effective date until January 1, 2006. Marathon plans to adopt the provisions of this statement January 1, 2006.
In November 2004, the FASB issued 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. Marathon is required to implement this statement in the first quarter of 2006. Marathon does not expect the adoption of SFAS No. 151 to have a material effect on its consolidated results of operations, financial position or cash flows.
In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143.” This interpretation clarifies that an entity is required to recognize a liability for a legal obligation to perform asset retirement activities when the retirement is conditional on a future event if the liability’s fair value can be reasonably estimated. If the liability’s fair value cannot be reasonably estimated, then the entity must disclose (a) a description of the obligation, (b) the fact that a liability has not been recognized because the fair value cannot be reasonably estimated, and (c) the reasons why the fair value cannot be reasonably estimated. FIN No. 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. Marathon is required to implement this interpretation no later than December 31, 2005 and is currently studying its provisions to determine the impact, if any, on its consolidated financial statements.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” SFAS No. 154 requires companies to recognize (i) voluntary changes in accounting principle and (ii) 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. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.
In September 2005, the FASB ratified the consensus reached by the Emerging Issues Task Force regarding 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 nonmonetary 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. Marathon is currently studying the provisions of this consensus to determine the impact on its consolidated financial statements.
17

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;~~products primarily in the Midwest, the upper Great Plains and southeastern United States; and worldwide marketing and transportation of ~~natural gas and~~ products manufactured from natural ~~gas.~~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 discussion of the Consolidated~~ Statements, ~~of Income should be read in conjunction with~~ the Supplemental Statistics ~~provided~~and our 2005 Annual Report on ~~page 33.~~
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 ~~Marathon.~~our business. These statements typically contain words such as ~~‘‘anticipates,’’ ‘‘believes,’’ ‘‘estimates,’’ ‘‘expects,’’ ‘‘targets,’’~~“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 ~~businesses,~~business, see ~~the information preceding Part I~~Item 1A. Risk Factors in our ~~2004~~2005 Annual Report on Form ~~10-K and subsequent filings.~~
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 ~~MPC~~the Refining, Marketing and Transportation segment include amounts related to the 38 percent interest held by Ashland prior to ~~the Acquisition, and amounts for EGHoldings include the 25 percent interest held by GEPetrol and the cumulative 15 percent interest held by Mitsui and Marubeni subsequent to July 25,~~June 30, 2005.
~~Overview and Outlook~~
~~We acquired the 38~~
     Marathon holds a 60 percent interest in ~~MPC~~Equatorial Guinea LNG Holdings Limited. The remaining interests are held by ~~Ashland Inc. on June 30, 2005. For additional information on~~a company controlled by the ~~Acquisition, see Note 4~~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 ~~Consolidated Financial Statements. Third quarter 2005 results benefited from full ownership of MPC. We believe~~minority interests.
Overview and Outlook
Exploration and Production (“E&P”)
     Production available for sale during the outlook for the refining and marketing business is attractive in our core areas of operation and expect the levels of demand to remain high for the foreseeable future. This acquisition increases our participation in the downstream business without the risks commonly associated with integrating a newly acquired business.
~~During the third~~first quarter of 2005, our U.S. Gulf Coast operations were significantly impacted by Hurricanes Katrina and Rita. Operationally, our oil and natural gas production facilities in the Gulf of Mexico sustained only minimal damage from these storms, and we have nearly returned to our pre-storm production levels in the Gulf of Mexico. Our refining and transportation operations also sustained relatively minor damage and were able to resume operations within days after the storms, providing much needed transportation fuels to the markets we serve.
~~While these hurricanes disrupted our operations, resulting in a reduction in our third quarter upstream sales of approximately 20,000~~2006 averaged 418,600 barrels of oil equivalent per day (“boepd”) and a loss of approximately 40,000 barrels per day (“bpd”) of refinery throughput, we still had sound operating and financial performances during the quarter. The consistent performance of both our upstream and downstream businesses allowed us to capture the value of continued high commodity prices and strong refining margins.
~~Exploration and Production~~
~~Crude oil~~. Reported liquid hydrocarbon and natural gas sales during the quarter averaged ~~291,500~~376,800 boepd. ~~Production~~This period’s variance between production available for sale ~~during the third quarter of 2005 averaged 321,000 boepd. The variance between~~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 ~~quarter is primarily a result of the timing of international crude oil liftings, primarily in the United Kingdom and Equatorial Guinea.~~
While our third quarter production results were negatively impacted by hurricanes in the Gulf of Mexico, other portions of our business continued to generate production increases, particularly in Equatorial Guinea and Russia. In Equatorial Guinea, we realized the benefits of strong condensate production and the full ramp-up of the recently completed liquefied petroleum gas (“LPG”) expansion project. During the third quarter, total liquids production available for sale in Equatorial Guinea averaged 45,000 net bpd. In addition, we continued development activities in the East Kamennoye field in Russia where we have an ongoing drilling program. These activities have driven total Russian production available for sale from an average of 14,000 net bpd during third quarter of 2004 to 28,000 net bpd during third quarterend of 2005.
18

~~Our cost of storm-related repairs in the Gulf of Mexico is not expected~~ During 2006, we will work with our partners to ~~be significant. Work continues~~define growth plans for this major asset.
     We continue to ~~restore~~advance our remaining operated and outside-operated production, with current Gulf of Mexico production at more than 95 percent of pre-storm levels of approximately 60,000 boepd. The restart of remaining oil and gas production is primarily dependent upon restoration of production from the outside-operated Ursa platform. Despite the negative effects of hurricanes on third quarter production levels, we estimate 2005 average daily production available for sale to be 340,000 to 350,000 boepd, excluding the impact of any acquisitions or dispositions. Daily production available for sale for the fourth quarter is estimated to be 350,000 to 370,000 boepd.
During the third quarter, we continued our exploration success offshore Angola with the Astraea and Hebe discoveries on Block 31. In addition, we have participated in an appraisal well on the Gengibre discovery on Block 32. Results of this well will be released upon partner and government approvals. We hold a 10 percent interest in outside-operated Block 31 and a 30 percent interest in outside-operated Block 32.
Marathon is currently participating in an appraisal well on the Plutao discovery in Angola Block 31, an exploration well on the Mostarda Prospect in Angola Block 32, a deep shelf exploration well on the Aquarius prospect in the Gulf of Mexico, an exploration well on the Davan prospect in the United Kingdom, and an appraisal well on the Gudrun discovery offshore Norway.
major E&P projects. In Norway, the ~~Alvheim/Vilje development~~Alvheim project is 2953 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 ~~2007.~~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
15
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 ~~possibility of developing Blocks 31 and 32 offshore Angola, the~~ development of the Alvheim field, the Neptune development, the Gudrun prospect and ~~Vilje fields and estimated costs of storm-related repairs.~~anticipated future drilling activity in the Bakken Shale resource play. Some factors that could potentially affect ~~this~~these forward-looking ~~information~~statements include pricing, supply and demand for petroleum products, ~~the~~ 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. Other factors that could affect the development of Blocks 31 and 32 offshore Angola include presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. Actual costs of storm-related repairs could be different than estimates as new information about the extent of damage inflicted by the storms becomes available. 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”)
~~Our~~
     In the first quarter 2006, our RM&T ~~segment~~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 ~~higher~~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 ~~third~~first quarter ~~due to~~2006 versus 6.85 cents per gallon in the impact that Hurricanes Katrina and Rita had on refined product margins. Our Garyville, Louisiana and Texas City, Texas refineries returned to operation safely with a minimum amount of downtime. These refineries sustained minimal damage during these storms and were able to be brought back on-line within days after the hurricanes, allowing us to meet the demand for transportation fuels during this period of reduced supply. The repair cost associated with these hurricanes was not significant.
~~While spot market gasoline and distillate prices peaked at all time highs~~first quarter 2005. In addition, during the ~~third quarter our RM&T prices and realizations were constrained by competitive pricing at the wholesale and retail levels.~~
~~Refinery crude runs during the third~~first quarter of ~~2005 averaged 979,600 bpd, with~~2006, our total ~~throughput averaging 1,194,800 bpd. This record~~refinery throughput was ~~achieved despite~~approximately five percent higher than the ~~loss of approximately 40,000 bpd of refinery capacity due~~same quarter in 2005. We continue to ~~the hurricanes. In addition to the temporary complete shut-down of the Garyville and Texas City refineries, we experienced minor reductions in throughputs at some of~~expect that our ~~Midwest refineries due to the temporary closure of crude oil pipelines originating in the U.S. Gulf Coast after Hurricane Katrina.~~
~~We expect our~~2006 average crude oil throughput will exceed our record throughput for 2005. Also during the ~~total year 2005~~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 ~~exceed~~comply with the ~~crude oil throughput record set in 2004.~~
Federal Environmental Protection Agency regulations which require ultra low sulfur diesel fuel production beginning June 1, 2006.
Speedway SuperAmerica LLC ~~(“SSA”) realized increased same-store~~continued to realize strong same store merchandise sales with an increase of approximately 1110.2 percent, while same store gasoline sales volume increased 3.3 percent when compared to the ~~third~~first quarter of ~~2004. In addition, SSA also increased its same store gasoline sales volume during the third quarter by approximately 5 percent compared to the same quarter last year.~~
Our $300 million, 26,000 bpd Detroit, Michigan refinery crude oil throughput expansion and Tier II low sulfur fuels project is in the final stages of completion. The refinery was shut down on September 29, 2005 to accommodate the installation and integration of key project components and other related work. The refinery is expected to restart in
19
2005.

mid-November 2005 with a total crude processing capacity of 100,000 bpd. The expansion also will enable the refinery to meet the Federal Tier II low-sulfur fuels regulations which become fully effective in 2006.
We plan to pursue an expansion of our 245,000 bpd Garyville, Louisiana, refinery. The project, estimated to cost approximately $2.2 billion, is expected to increase the refinery’s crude throughput capacity by 180,000 bpd to 425,000 bpd, with completion possibly as early as the fourth quarter of 2009. The initial phase of the expansion will include front-end engineering and design (“FEED”) work that could lead to the start of construction in 2007. Anticipated project investments include the installation of a new crude distillation unit, hydrocracker, reformer, kerosene hydrotreater, delayed coker, additional sulfur recovery capacity and other infrastructure investments. The new facilities will incorporate the latest safety and environmental control technologies. The proposed refinery configuration also will be designed to provide maximum feedstock flexibility, enabling us to process more heavy sour crude oils.
The above discussion includes forward-looking statements with respect to ~~refinery throughputs, the Detroit capital project and the planned expansion~~projections of ~~the Garyville refinery. Some factors~~crude oil throughput that could ~~potentially cause~~be affected by planned and unplanned refinery maintenance projects, the ~~actual results from the Detroit construction project to be different than expected include availability~~levels of ~~materials and labor, unforeseen hazards such as weather conditions,~~refining margins and other ~~risks customarily associated with construction projects. Some factors that could affect refinery throughputs include unexpected downtime due to~~ operating problems, weather conditions, and labor issues. Some factors that could affect the Garyville expansion include satisfactory results of the FEED work, Marathon board and necessary regulatory approvals, crude oil supply and transportation logistics, necessary permits, a continued favorable investment climate, availability of materials and labor, unforeseen hazards such as weather conditions, and other risks customarily associated with construction projects.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 ~~Equatorial Guinea LNG train 1 project made~~integrated gas activities during the first quarter 2006 were marked by continued progress ~~during~~in constructing the ~~quarter and remains on-track to begin first shipment of~~ LNG plant in ~~2007.~~Equatorial Guinea. The project ~~was 58~~is approximately 73 percent complete on an engineering, procurement and construction basis ~~and expenditures totaled $1 billion of the total gross estimated project cost of $1.4 billion~~ as of ~~September 30, 2005. Also, the Equatorial Guinea~~March 31, 2006. Construction remains on schedule for first shipments of LNG ~~project partners continue to explore the feasibility of adding a second LNG train in an effort to create a regional gas hub that would commercialize stranded gas from various sources~~ in the ~~surrounding Gulf~~third quarter of ~~Guinea region.~~
We sold minority interests totaling 15 percent in EGHoldings and recorded a gain of $23 million. Following the closing of the transaction on July 25, 2005, we now hold a 60 percent interest in this consolidated subsidiary.
2007.
The above discussion contains forward-looking statements with respect to the estimated construction ~~cost~~ and startup dates of a LNG ~~liquefaction plant and related facilities and the possible expansion thereof. Factors that~~project which could ~~affect the estimated construction cost and startup dates of the LNG liquefaction plant and related facilities include, without limitation,~~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. In addition to these factors, other factors that could affect the possible expansion of the current LNG project and the development of additional LNG capacity through additional projects include partner approvals, access to sufficient gas volumes through exploration or commercial negotiations with other resource owners and access to sufficient regasification capacity. 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.
16
20

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
Revenuesfor the ~~third quarter~~first quarters of 2006 and ~~first nine months of~~ 2005 ~~and 2004~~ are summarized by segment in the following table:

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

(In millions)

2005

2004

2005

2004

E&P

$
1,507

$
1,211

$
4,438

$
3,691

RM&T

15,460

10,899

41,139

31,114

IG

517

447

1,440

1,290

Segment revenues

17,484

12,557

47,017

36,095

Elimination of intersegment revenues

(228
)
(179
)
(586
)
(470
)
Loss on long-term U.K. gas contracts

(82
)
(129
)
(306
)
(210
)
Total revenues

$
17,174

$
12,249

$
46,125

$
35,415

Items included in both revenues and costs and expenses:

Consumer excise taxes on petroleum products and merchandise

$
1,217

$
1,137

$
3,511

$
3,327

Matching crude oil, gas and refined product buy/sell transactions settled in cash:

E&P

$
30

$
45

$
100

$
127

RM&T

3,403

2,218

9,707

6,587

Total buy/sell transactions

$
3,433

$
2,263

$
9,807

$
6,714

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 revenuesincreased by ~~$296~~$681 million in the ~~third~~first quarter of ~~2005~~2006 from the comparable prior-year period. ~~For the first nine months of 2005, revenues increased by $747 million from the prior-year period. These increases were~~The increase was primarily due to ~~higher worldwide liquid hydrocarbon and natural gas prices and international~~increased net liquid hydrocarbon sales volumes ~~partially offset by lower domestic~~and higher prices for both liquid hydrocarbons and natural gas ~~and~~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. Derivative losses totaled $9 million and $11 million~~volumes benefited from a full quarter of production in the ~~third~~first quarter ~~and~~of 2006 from the Petronius field in the Gulf of Mexico that was down during the first ~~nine months~~quarter of 2005 compared to losses of $75 million and $128 million in the third quarter and first nine months of 2004. Matching buy/sell transactions decreased by $15 million and $27 million in the third quarter and first nine months of 2005 from the comparable prior-year periods due to ~~decreased crude oil buy/sell transactions, partially offset by higher domestic liquid hydrocarbon prices.~~
hurricane damage.
Excluded from ~~the~~ E&P segment revenues ~~were losses~~are a gain of ~~$82 million and $306~~$78 million for the ~~third~~first quarter of 2006 and ~~the first nine months~~a loss of ~~2005 and losses of $129 million and $210~~$57 million for the ~~third~~first quarter ~~and the first nine months~~ of ~~2004~~2005 on long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments.
RM&T segment revenuesincreased by ~~$4.561~~$2.816 billion, including an increase from matching buy/sell transactions of $422 million, in the ~~third~~first quarter of ~~2005~~2006 from the comparable ~~prior-year period. For the first nine months of 2005, revenues increased by $10.025 billion from the~~ prior-year period. The increases primarily reflected higher refined product and crude oil prices ~~and~~as well as increased refined product ~~sales~~ volumes, partially offset by ~~decreased~~lower crude oil ~~sales~~ volumes.   Matching buy/sell transaction revenues increased by $1.185 billion and $3.120 billion in the third quarter and first nine months of 2005 from the comparable prior-year periods primarily due to increased crude oil prices and volumes and increased refined product prices, partially offset by decreased refined product sales volumes.
~~IG segment revenues~~ increased by $70 million in the third quarter of 2005 from the comparable prior-year period. For the first nine months of 2005, revenues increased by $150 million from the comparable prior-year period. These increases primarily reflected higher natural gas marketing prices. Derivative losses totaled $13 million and $9 million in the third quarter and the first nine months of 2005, compared to gains of $4 million and $14 million in the third quarter and first nine months of 2004.
For additional information on segment results, see ~~“Results of Operations by Segment” on page 23.~~
Segment Income.
~~Cost of revenues~~Income from equity method investmentsfor 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~~2005.
Cost of revenuesfor the first quarter 2006 increased by ~~$3.134 billion from the comparable prior-year period. For the first nine months of 2005, cost of revenues increased by $6.114~~$2.077 billion from the comparable prior-year period. The increases are primarily in the RM&T segment ~~primarily reflected~~and resulted mainly from higher acquisition costs for crude oil, other refinery charge and blend stocks, and refined ~~products and~~products. Additionally, we experienced higher manufacturing ~~expenses. This was partially offset~~expenses, primarily a result of higher purchased energy and maintenance costs.
17
Depreciation, depletion and amortizationfor the first quarter of 2006, increased by ~~decreases in E&P~~$92 million compared to the same period of 2005. RM&T segment depreciation expense increased primarily as a result of ~~lower crude oil marketing activity.~~
21

~~Purchases~~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 ~~matching buy/sell transactions~~ ~~for~~ the ~~third quarter~~Camden Hills field in the Gulf of Mexico and ~~first nine months of 2005 increased by $841 million and $2.724 billion~~the associated Canyon Express pipeline. Natural gas production from the comparable prior-year periods. The increases are primarily due to increased crude oil and refined product prices and increased crude oil purchase volumes, partially offset by decreased refined product purchase volumes. Differences between revenues from matching buy/sell transactions and purchases related to matching buy/sell transactions forCamden Hills field ended during the ~~third~~first quarter ~~and first nine months of 2005 are primarily due to timing differences between the delivery and receipt of certain matching transaction volumes. There is no effect on income~~2006 as a result ~~these timing differences.~~
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 expensesfor the ~~third~~first quarter ~~and the first nine months of 2005~~2006 increased by $64 million and $90 million from the comparable prior-year periods. The increase in the third quarter of 2005 was primarily due to increased stock-based compensation expense, employee benefit expenses and other employee related costs as well as contributions to hurricane relief efforts. The increase in the first nine months of 2005 was primarily a result of increased stock-based compensation expense partially offset by prior year severance and pension plan curtailment charges and start-up costs related to EGHoldings.
~~Exploration expenses~~ ~~for the third quarter and the first nine months of 2005 increased by $18 million and~~ $27 million compared to the ~~same periods~~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 ~~2004. During~~Equatorial Guinea and increased costs for outside professional services, partially offset by lower stock-based compensation expense.
Exploration expenseswere $71 million in the first quarter ~~ended September 30, 2005, $22~~of 2006 compared to $34 million in the first quarter of ~~exploratory well~~2005. Exploration expenses related to dry wells in the first quarter of 2006 totaled $30 million and primarily included costs related to the ~~Annapolis project offshore Nova Scotia were written off. Sufficient progress toward an economically viable project had not been made since completion of drilling in this prospect~~Davan well in the ~~third quarter of 2004. The subsea wellhead remains in place and could be tied back into a development in the future. We continue to evaluate further drilling in this area.~~
~~Net interest and other financing costs~~ ~~for the third quarter~~U.K. and the ~~first nine months of 2005 decreased by $8 million and $30 million, compared to the same periods~~Soulandaka well in 2004. The decrease in the third quarter is primarily due to increased capitalized interest partially offset by a decrease in interest income. The decrease in the first nine months of 2005 is primarily a result of increased interest income on investments and capitalized interest, partially offset by increased interest on potential tax deficiencies and higher foreign exchange losses.
Gabon.
Minority interest in income of MPCdecreased ~~$148 million and $1~~$70 million in the ~~third~~first quarter ~~and the first nine months~~ of ~~2005~~2006 from the comparable ~~prior-year periods~~2005 period due to the completion of ~~the~~our acquisition of ~~Ashland’s~~Ashland Inc.’s 38 percent interest in MPC on June 30, 2005.
Provision for income taxesin 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 %

18
Segment Results
Segment incomefor 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 incomein 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 incomein 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 ~~and~~of 2005.
     Our international average realized liquid hydrocarbon price was $50.68 per bbl in the first ~~nine months~~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.
19
RM&T segment incomein the first quarter of 2006 increased by ~~$336 million and $492~~$245 million from the ~~comparable prior-year periods primarily due to increases~~first quarter of ~~$884 million and $1.431 billion~~2005. Segment income in ~~income before income taxes.~~
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 state of Kentucky enacted legislation which causes limited liability companies to be subject to Kentucky’s corporation income tax. Our provision for income taxes for the first nine months of 2005 includes $13 millionpretax earnings reduction related to the ~~effects of this Kentucky income tax on deferred tax assets and liabilities as of January 1, 2005. The unfavorable effect on net income (after~~ minority ~~interest)~~interest was $6$76 million. In the second quarter of 2005, the state of Ohio enacted legislation which phases out Ohio’s income-based franchise taxes over a five-year period. Our provision for income taxes in the first nine months of 2005 includes a $15 million benefit related to the reversal of deferred income taxes as a result of this change in tax law. The state of Ohio replaced the income-based franchise tax with a commercial activity tax based on gross receipts which will be phased in over five years. The commercial activity tax will be reported in costs and expenses.
The effective tax rate for the first nine months of 2005 was 36.2 percent compared to 38.2 percent for the comparable period in 2004. The decrease in the rate is primarily related to the effects of foreign operations and the legislation discussed above.
~~Net income~~ ~~for the third quarter and the first nine months of 2005 increased by $548 million and $935 million from the comparable prior-year periods, primarily reflecting the elimination~~A key driver of the ~~minority interest~~increase in ~~our downstream business and the factors discussed above.~~
22

~~Results of Operations by Segment~~
~~Income from operations~~ ~~for the third quarter and the first nine months of 2005 and 2004 is summarized in the following table:~~

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

(In millions)

2005

2004

2005

2004

E&P

Domestic

$
397

$
244

$
1,096

$
835

International

230

107

862

418

E&P segment income

627

351

1,958

1,253

RM&T

814

391

1,847

1,017

IG

(6
)
18

12

25

Segment income

1,435

760

3,817

2,295

Items not allocated to segments:

Administrative expenses

(108
)
(90
)
(284
)
(238
)
Loss on long-term U.K. gas contracts

(82
)
(129
)
(306
)
(210
)
Gain on ownership change in MPC

—

1

—

2

Gain on sale of minority interests in EGHoldings

23

—

23

—

Income from operations

$
1,268

$
542

$
3,250

$
1,849

~~Domestic E&P~~RM&T pretax income in the third quarter of 2005 increased by $153 million from the third quarter of 2004. Income in the first nine months of 2005 increased by $261 million from the same period in 2004. The increases were due to higher liquid hydrocarbon and natural gas prices partially offset by lower sales volumes. These lower volumes resulted primarily from weather-related downtime in the Gulf of Mexico and natural field declines in the Permian Basin. The first nine months of 2005 included business interruption insurance recoveries of $53 million related to Hurricane Ivan storm-related claims. Derivative losses totaled $9 million and $11 million in the third quarter and the first nine months of 2005, compared to losses of $58 million and $98 million in the third quarter and first nine months of 2004.
~~Our domestic average realized liquid hydrocarbon price excluding derivative activity~~ was $52.38 and $44.24 per barrel (“bbl”) in the third quarter and first nine months of 2005, compared with $35.56 and $32.23 per bbl in the comparable prior-year periods. Domestic average gas prices were $6.56 and $5.76 per thousand cubic feet (“mcf”) excluding derivative activity in the third quarter and first nine months of 2005, compared with $4.76 and $4.83 per mcf in the corresponding 2004 periods.
Domestic net liquid hydrocarbon sales volumes decreased to 75.9 thousand barrels per day (“mbpd”) in the first nine months of 2005, down 12 percent from the 2004 comparable period, as a result of lower production primarily as a result of storm-related downtime in the Gulf of Mexico and natural field declines in the Permian Basin. Domestic net natural gas sales volumes averaged 570.4 million cubic feet per day (“mmcfd”) in the first nine months of 2005, down 12 percent from the 2004 comparable period as a result of lower production in the Permian Basin and Camden Hills in the Gulf of Mexico due to natural field declines and downtime associated with Hurricane Ivan.
International E&P income in the third quarter of 2005 increased by $123 million from the third quarter of 2004. Income in the first nine months of 2005 increased by $444 million from the same period in 2004. The increases were primarily a result of higher product prices and liquid hydrocarbon sales volumes, partially offset by higher production taxes in Russia, dry well expenses and lower natural gas production. Derivative losses totaled $17 million and $30 million in the third quarter and the first nine months of 2004. There was no derivative activity in 2005.
Our international average realized liquid hydrocarbon price excluding derivative activity was $48.24 and $44.42 per bbl in the third quarter and the first nine months of 2005, compared with $37.07 and $31.78 per bbl in the 2004 comparable periods. International average gas prices were $3.12 and $3.62 per mcf excluding derivative activity in the third quarter and the first nine months of 2005, compared with $2.79 and $3.15 per mcf in the corresponding 2004 periods.
International net liquid hydrocarbon sales volumes increased to 103.8 mbpd in the first nine months of 2005, up 20 percent from the 2004 comparable period, as a result of increased production in Equatorial Guinea and Russia. International net natural gas sales volumes averaged 337.1 mmcfd in the first nine months of 2005, down 5 percent from the 2004 comparable period, as a result of reduced U.K. spot gas sales.
23

RM&T segment income in the third quarter of 2005 increased by $423 million from the third quarter of 2004. Income in the first nine months of 2005 increased by $830 million from the same period in 2004. The increases were due to higherour refining and wholesale marketing ~~margins. The higher refined product margins in the third quarter were due primarily to the impacts of Hurricanes Katrina and Rita. The refining and wholesale marketing~~gross margin, ~~in the third quarter and the first nine months of 2005~~which averaged ~~17.7 and 13.7~~11.37 cents per gallon ~~versus~~in the ~~2004 comparable period levels~~first quarter of ~~9.0 and 8.5~~2006 compared to 6.85 cents per ~~gallon. We also benefited from wider crack spreads and~~gallon in the first quarter of 2005. This margin improvement reflected favorable sweet/sour crude ~~differentials.~~
~~Losses from derivative activity~~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 ~~margin~~gross margin) were ~~$271 million and $410~~$11 million in the ~~third~~first quarter ~~and the first nine months~~ of ~~2005~~2006 as compared to ~~$67 million and $270~~losses of $172 million in the ~~same periods~~first quarter of ~~2004. Generally,~~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 ~~derivatives included in~~crack spread derivative contracts primarily related to No. 2 high sulfur fuel oil crack spreads that expired over the ~~refining and wholesale marketing margin are offset by~~remainder of 2005. Derivative gains ~~on the underlying physical transactions.~~
~~Additionally, losses from derivative~~related to trading ~~opportunities~~activities were ~~$42 million and $76~~$5 million in the ~~third~~first quarter ~~and the first nine months~~ of ~~2005~~2006 as compared to ~~gains~~losses of ~~$2 million and $14~~$31 million in the comparable prior-year ~~periods.~~
period. See Quantitative and Qualitative Disclosures About Market Risk — RM&T Segment for further details of derivative results.
The ~~IG segment had a loss of $6 million~~9 percentage point decrease in the ~~third~~effective income tax rate from 48 percent in the first quarter of 2005 ~~compared~~ to ~~income of $18 million in the third quarter of 2004. Income~~39 percent in the first ~~nine months~~quarter of ~~2005 decreased by $13 million from the same period in 2004. The decrease in the third quarter was~~2006 is primarily the result of ~~mark-to-market changes~~ the effect of the 2005 Kentucky tax increase on deferred tax balances at the beginning of that quarter.
IG segment incomein the ~~fair value~~first quarter of ~~derivatives used to support gas marketing activities. The methanol operations~~2006 decreased by $14 million from the first quarter of 2005 primarily as a result of a $10 million increase in ~~Equatorial Guinea have been operating at~~the provision for income taxes. This increase is primarily a ~~98 percent on-stream factor~~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 ~~posted index prices~~Liquidity
Cash Flows
Net cash provided from operating activitiestotaled $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 activitiestotaled $987 million in the first quarter of 2006. Capital expenditures were $599 million compared with $556 million for ~~methanol have remained strong.~~
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 activitieswas $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 ~~October~~April 26, ~~2005,~~2006, our Board of Directors ~~(the “Board”)~~ declared a dividend of 3340 cents per share, payable ~~December~~June 12, ~~2005,~~2006, to stockholders of record at the close of business on ~~November 16, 2005.~~
~~Cash Flows~~
~~Net cash provided from operating activities~~ May 17, 2006. This was ~~$1.963 billion~~a seven cent, or 21 percent, increase in the first nine months of 2005, compared with $1.977 billion in the first nine months of 2004. The $14 million decrease reflects working capital changes, primarily due to the $913 million in receivables which were transferred to Ashland on June 30, 2005, as a part of the Acquisition and higher inventories in the current period, partially offset by higher net income in the first nine months of 2005.
~~Capital expenditures~~ in the first nine months of 2005 totaled $2.015 billion compared with $1.377 billion in the same period of 2004. The $638 million increase mainly reflected increased spending in the E&P segment related to the Alvheim development offshore Norway and increased spending in the IG segment related to continuing construction of our ~~natural gas liquefaction plant in Equatorial Guinea. For information regarding capital expenditures by segment, refer to the Supplemental Statistics.~~
quarterly dividend.
~~Acquisition~~ ~~included cash payments of $506 million for the first nine months of 2005 for the Acquisition. For additional information on the Acquisition, see Note 4 to the Consolidated Financial Statements.~~
~~Net cash used in financing activities~~ was $1.976 billion in the first nine months of 2005, compared with net cash provided from financing activities of $618 million in the first nine months 2004. The change was due to the repayment of $1.920 billion of debt assumed as a part of the Acquisition in 2005 and to the issuance of 34,500,000 shares of common stock on March 31, 2004, resulting in net proceeds of $1.004 billion in 2004. These effects were partially offset by a net $285 million of commercial paper borrowings in the first nine months of 2005 and the repayment on maturity of $250 million of 7.2% notes in the first quarter of 2004. The first nine months of 2005 included contributions of $175 million from the minority shareholders of EGHoldings and $272 million of distributions to the minority shareholder of MPC prior to the Acquisition.
Derivative Instruments
See ~~“Quantitative~~Quantitative and Qualitative Disclosures About Market ~~Risk”~~Risk for a discussion of derivative instruments and associated market risk.
24

Liquidity and Capital Resources
Our main sources of liquidity and capital resources are internally generated cash flow from operations, committed and uncommitted credit facilities, ~~an uncommitted accounts receivables sales facility,~~ 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
20
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 ~~2005,~~ 2006, 2007 and ~~2007,~~2008, and any amounts that may ultimately be paid in connection with contingencies.
~~We have~~
     During the first quarter 2006, we had a committed $1.5 billion five-year revolving credit facility ~~that terminates~~with third-party financial institutions terminating in May 2009. At ~~September 30, 2005,~~March 31, 2006, there were no borrowings against this ~~facility. At September 30, 2005,~~facility and we had ~~$285 million in~~no commercial paper outstanding under the U.S. commercial paper program ~~that is~~ backed by the five-year revolving credit facility. ~~Additionally, we have other uncommitted short-term lines of credit totaling $200 million, of which no amounts were drawn at September 30, 2005.~~
     During the first quarter 2006, MPC ~~has~~had a committed $500 million five-year revolving credit facility with third-party financial institutions ~~that terminates~~terminating in May 2009. At ~~September 30, 2005,~~March 31, 2006, there were no borrowings against this facility.   ~~On July 1, 2005, MPC originated~~
     Effective May 4, 2006, we entered into an ~~uncommitted $200 million accounts receivable sale facility. This~~amendment to our $1.5 billion five-year revolving credit agreement, expanding the size of our credit facility ~~allows MPC~~ to ~~sell interests in certain of its receivables~~$2.0 billion and extending the termination date to a third-party financial institution on a non-recourse basis. If any receivables are sold under the facility, MPC will not guarantee the transferred receivables and will have no obligations upon default. There have been no receivables sold as of the filing of this report.
May 2011. The ~~Marathon and~~ MPC revolving credit ~~facilities each require a representation at an initial borrowing that there~~facility has been ~~no change~~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 ~~respective borrower’s consolidated financial position or operations, considered as a whole, that would materially and adversely affect such borrower’s ability~~event of limited extraordinary circumstances. MPC was permitted to ~~perform its obligations under~~use its revolving credit ~~facility.~~
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 ~~September 30, 2005, there was~~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 ~~the~~our $2.7 billion universal shelf registration statement filed ~~with the Securities and Exchange Commission~~ in 2002. On June 30, 2005, we issued $955 million of common stock to Ashland shareholders through a separate registration statement filed with the Securities and Exchange Commission which was declared effective May 20, 2005.
Our cash-adjusted debt-to-capital ratio ~~(total-debt-minus-cash~~(total debt-minus-cash to ~~total-debt-plus-equity-minus-cash)~~total debt-plus-equity-minus-cash) was 2417 percent at ~~September 30, 2005,~~March 31, 2006, compared to 811 percent at year-end ~~2004~~2005 as shown below. This includes ~~$587~~$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.
(Dollars in millions)

September 30,
2005

December 31,
2004

Commercial paper

$
285

$
—

Long-term debt due within one year

316

16

Long-term debt

3,728

4,057

Total debt

$
4,329

$
4,073

Cash

$
1,043

$
3,369

Equity

$
10,642

$
8,111

Calculation

Total debt

$
4,329

$
4,073

Minus cash

1,043

3,369

Total debt minus cash

3,286

704

Total debt

4,329

4,073

Plus equity

10,642

8,111

Minus cash

1,043

3,369

Total debt plus equity minus cash

$
13,928

$
8,815

Cash-adjusted debt-to-capital ratio

24
%
8
%
25

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 %

As a condition of the closing agreements for the Acquisition, we are required to maintain MPC on a stand-alone basis financially for a two-year period. During this period of time, we are precluded from making capital contributions into MPC and MPC is prohibited from incurring additional debt, except for borrowings under an existing intercompany loan facility to fund an expansion project at MPC’s Detroit refinery and in the event of limited extraordinary circumstances. MPC may only use its revolving credit facility for short-term working capital requirements in a manner consistent with past practices. MPC may use its accounts receivable sale facility to maintain an adequate level of liquidity to manage its operations. We believe these facilities and cash provided from MPC’s operations will be adequate to meet its liquidity requirements.
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
21
include our performance (as ~~determined~~measured by various ~~measures,~~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
~~Subsequent to~~
     As of March 31, 2006, our purchase obligations under crude oil, refinery feedstocks and refined product contracts increased approximately $2 billion from December 31, ~~2004,~~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.~~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, ~~2004.~~
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, ~~2004.~~
2005.
Nonrecourse Indebtedness of Investees
Certain of our ~~equity~~ 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 ~~$269~~approximately $313 million as of ~~September 30, 2005.~~March 31, 2006. Of this amount, ~~$144~~$189 million relates to Pilot Travel Centers LLC (“PTC”). If any of these ~~equity~~ investees default, we have no obligation to support the debt. Our partner in PTC has guaranteed ~~$157~~$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
22
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 ~~September 30, 2005,~~March 31, 2006, we have obligations totaling ~~$643~~$590 million that have been assumed by United States Steel. Of the total ~~$643~~$590 million, obligations of ~~$597~~$549 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet (current portion ~~- $21~~— $20 million; long-term portion ~~- $576~~— $529 million). The remaining ~~$46~~$41 million was related to ~~operating lease obligations~~off-balance sheet arrangements and contingent liabilities of United States Steel.
26

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.
~~Tier II gasoline and on-road diesel fuel rules~~
     Of particular significance to our refining operations are U.S. Environmental Protection Agency (“EPA”) regulations that require ~~substantially~~ reduced sulfur levels starting in 2004 for gasoline and 2006 for diesel ~~starting in 2004 and 2006.~~fuel. We ~~expect the~~expected our combined capital costs to achieve compliance with ~~the gasoline and diesel regulations~~these rules to ~~be approximately~~approximate $900 million over the period ~~between~~ 2002 ~~and~~through 2006, and ~~includes~~substantially all of those costs ~~that could be~~have been incurred as ~~part of other~~all refinery upgrade projects. This is a forward-looking statement. Costs incurred through September 30, 2005, were approximately $740 million. Some factors (among others) that could potentially affect gasoline andconstruction projects are on schedule to meet the June 1, 2006 ultra low sulfur diesel ~~fuel compliance costs include completion of project detailed engineering, construction and start-up activities.~~
requirements.
During 2001, weMPC entered into a New Source Review consent decree and settlement of alleged Clean Air Act ~~(‘‘CAA’’~~(“CAA”) and other violations with the ~~U. S. Environmental Protection Agency~~EPA covering all of ~~our~~MPC’s refineries. The settlement committed usMPC to specific control technologies and implementation schedules for environmental expenditures and improvements to ~~our~~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 ~~estimated~~expected to be approximately ~~$380~~$420 million over the eight-year period, with about ~~$255~~$285 million incurred through ~~September 30, 2005.~~March 31, 2006. The impact of the settlement on ongoing operating expenses is expected to be immaterial. In addition, ~~we have~~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.~~During~~
     The oil industry across the ~~second quarter~~U.K. continental shelf is making reductions in the amount of ~~2005, the court approved a first amendment~~oil in its produced water discharges pursuant to the ~~consent decree pertaining~~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 ~~Texas City Refinery which allows greater operational flexibility~~OSPAR project for Brae field to make the ~~refinery during periods~~required reductions of amine shortages, while we otherwise agreed to pollution-reducing measures at that refinery. We will also contribute at least $100,000 as a supplemental environmental project to install diesel retrofit technologies on sanitation trucks owned by Texas City, Texas. The consent decree requires us to publicly state that this is part of a settlement of an enforcement action for alleged CAA violations.
oil in its produced water discharges.
There have been no other significant changes to our environmental matters subsequent to December 31, ~~2004. Changes in accrued liabilities for remediation and receivables for recoverable costs since December 31, 2004 are described in Note 17 to the Consolidated Financial Statements.~~
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
23
~~Other Matters~~
~~We suspended operations in Sudan in 1985, but continue~~
assets are not subject to ~~hold~~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 ~~interest in an exploration~~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 ~~production sharing agreement. We have derived no economic benefit from our Sudan interests. We have~~Sales of Inventory with the Same Counterparty.” The issue defines when a purchase and ~~will continue to abide by all U.S. sanctions related to Sudan and will not resume any activity regarding our interests there until such time as it is permitted under U.S. law.~~
~~We discovered~~a sale of inventory with the ~~Ash Shaer and Cherrife gas fields in Syria~~same party that operates in the ~~1980’s. We submitted four plans~~same line of ~~development~~business is recorded at fair value or considered a single non-monetary transaction subject to the ~~Syrian Petroleum Company~~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 ~~1990’s, but none were approved. The Syrian government subsequently claimed that the production sharing contract for these fields had expired. We have been involved in an ongoing dispute~~form of raw materials, work-in-process, or finished goods. In general, two or more transactions with the ~~Syrian Petroleum Company~~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 ~~Syrian government over our interest in~~therefore, upon adoption, these ~~fields, and are currently discussing~~transactions will no longer be recorded on a ~~settlement under which a new production sharing contract~~gross basis. Management does not believe any impact on net income would be ~~executed, and we would have the right to sell all or~~material. There will be no impact on cash flows from operations as a ~~significant portion~~result of ~~our interest to a third party. We have and will continue to comply with all U.S. sanctions related to Syria.~~adoption.
24
~~We are continuing to work with our partners and the Libyan government to finalize the terms of the group’s reentry agreement. We also opened an office in Tripoli during the second quarter of 2005.~~
27

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 on petroleum feedstocks used as raw ~~materials.~~
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.
~~Our RM&T segment uses commodity derivative instruments to:~~
•      ~~mitigate the price risk 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,~~
•      ~~manage the price risk associated with anticipated natural gas purchases for refinery use,~~
•      ~~protect the value of excess refined product, crude oil and LPG inventories,~~
•      ~~lock in margins associated with future fixed price sales of refined products to non-retail customers,~~
•      ~~protect against decreases in future crack spreads,~~
•      ~~mitigate price risk associated with freight on crude, feedstocks, and refined product deliveries, and~~
•      ~~take advantage of trading opportunities identified in the commodity markets.~~
Our IG segment is exposed to market risk associated with the purchase and subsequent resale of natural gas. We use commodity derivative instruments to mitigate the price risk on purchased volumes and anticipated sales volumes.
We use financial derivative instruments to manage interest rate ~~and foreign currency exchange 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.
25
28

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 ~~September 30, 2005~~March 31, 2006 are provided in the following table:

Incremental Decrease in
Income from Operations
Assuming a Hypothetical
Price Change of: (a)

(In millions)

10%

25%

Commodity Derivative Instruments:(b)(c)

Natural gas(d)

$
69
(e)
$
172
(e)
Refined products(d)

6
(e)
18
(e)

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)~~
^(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 ~~market value~~E&P segment for the first quarter of ~~derivative instruments; however, such risk should be mitigated by price changes~~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 ~~underlying hedged item. Effects~~E&P segment.
     Excluded from the E&P segment results were gains 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 September 30, 2005. The hypothetical price changes of 10 percent and 25 percent would result in incremental decreases in income from operations of $79$78 million and ~~$198~~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 and these amounts are included above in the impact for natural gas. We evaluate our portfolio of commodity derivative instruments on an ongoing basis and add or revise strategies to reflect anticipated market conditions and changes in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review, including the use of master netting agreements to the extent practical. Changes to the portfolio after September 30, 2005, would cause future income from operations effects to differ from those presented in the table.
~~(b)~~Net open contracts for the combined E&P and IG segments varied throughout the third quarter of 2005, from a low of 1,243 contracts at August 28 to a high of 1,717 contracts at September 30, and averaged 1,462 for the quarter. The number of net open contracts for the RM&T segment varied throughout the third quarter of 2005, from a low of 11,734 contracts at August 8 to a high of 26,554 contracts at July 20, and averaged 20,093 for the quarter. The commodity derivative 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 income from operations when applied to the commodity derivative instruments used to hedge that commodity.
~~(e)Price increase.~~
~~E&P Segment~~
instruments.
At ~~September 30, 2005,~~March 31, 2006, we had no open ~~equity~~derivative commodity contracts related to our oil and natural gas production, ~~derivative contracts.~~and therefore we remain exposed to market prices of commodities. We continue to evaluate the commodity price ~~risk of~~risks related to our ~~equity~~ production ~~on an ongoing basis~~ and may enter into derivative commodity ~~derivative~~ 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.
26
Derivative losses included in the E&P segment were $11 million and $128 million for the first nine months of 2005 and 2004. Additionally, losses of $3 million from discontinued cash flow hedges are included in segment results for the first nine months of 2004. The discontinued cash flow hedge amounts were reclassified from accumulated other comprehensive loss as it was no longer probable that the original forecasted transactions would occur. There were no reclassifications during the first nine months of 2005.
Excluded from the E&P segment results were losses of $306 million and $210 million for the first nine months of 2005 and 2004 on long-term gas contracts in the United Kingdom that are accounted for as derivative instruments.
29

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~~operations. Pre-tax derivative gains and losses included in RM&T segment income ~~although most~~for the first quarters of ~~these derivatives~~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. ~~Generally, derivative~~Derivative losses occur when market prices increase, ~~which~~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. ~~Derivative gains or losses included in RM&T segment income for~~ ~~the first nine months of 2005 and 2004 are summarized in the following table:~~

Nine Months Ended
September 30,

(In millions)

2005

2004

Strategy:

Mitigate price risk

$
(119
)
$
(88
)
Protect carrying values of excess inventories

(233
)
(111
)
Protect margin on fixed price sales

23

10

Protect crack spread values

(81
)
(81
)
Trading activities

(76
)
14

Total net derivative losses

$
(486
)
$
(256
)
~~IG Segment~~
We have used derivative instruments to convert the fixed price of a long-term gas sales contract to market prices. The underlying physical contract is for a specified annual quantity of gas and matures in 2008. Similarly, we use derivative instruments to convert shorter term (typically less than a year) fixed price contracts to market prices in our ongoing natural gas marketing and transportation activity; to hedge purchased gas injected into storage for subsequent resale; and to lock in margins for gas purchased and subsequently resold.   IG segment income included derivative losses of $9 million and derivative gains of $14 million for the first nine months of 2005 and 2004.
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.
30

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 ~~September 30, 2005~~ March 31, 2006 is provided in the following table:
(In millions)

Fair
Value (b)

Incremental
Increase in
Fair Value (c)

Financial assets (liabilities)(a):

Interest rate swap agreements

$
(28
)
$
13

Long-term debt(d)(e)

$
(4,556
)
$
(156
)

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, commercial paper, 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)~~     For long-term debt, this assumes a 10 percent decrease in the weighted average yield to maturity of Marathon’s long-term debt at September 30, 2005. For interest rate swap agreements, this assumes a 10 percent decrease in the effective swap rate at September 30, 2005.
~~(d)~~    ~~See below for sensitivity analysis.~~
~~(e)~~     ~~Includes amounts due within one year and the effects of interest rate swaps.~~
^(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 ~~September 30, 2005,~~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 ~~$156~~$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
27
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 ~~our~~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. ~~The following table summarizes, by individual debt instrument,~~There have been no unexpected changes to the ~~interest rate swap activity as of~~ ~~September 30, 2005:~~
Floating Rate to be Paid

Fixed Rate to
be Received

Notional
Amount

Swap
Maturity

Fair Value

Six Month LIBOR +4.226%

6.650
%
$
300 million

2006

$
(2
)million
Six Month LIBOR +1.935%

5.375
%
$
450 million

2007

$
(8
)million
Six Month LIBOR +3.285%

6.850
%
$
400 million

2008

$
(10
)million
Six Month LIBOR +2.142%

6.125
%
$
200 million

2012

$
(8
)million
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, generally with terms of 365 days or less.~~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. ~~At September 30, 2005, the following currency derivatives were outstanding. All contracts currently qualify for hedge accounting unless noted.~~
Financial Instruments

Period

Notional Amount

All-in-Rate(a)

Fair Value(b)

Foreign Currency Rate Swaps:

Euro

October 2005 – December 2005

$
28 million

1.312
(c)
$
(2
)million
Norwegian kroner

October 2005 – December 2005

$
70 million

6.363
(d)
$
(2
)million
Foreign Currency Rate Options:

Euro

January 2006 – June 2006

$
88 million

1.295
(c)(e)
$
1
million
Norwegian kroner

January 2006 – February 2006

$
62 million

6.150
(d)(e)
$
—
million
~~(a)The rate at which the derivative instruments will be settled.~~
~~(b)Fair value was based on market prices.~~
~~(c)U.S. dollar to foreign currency.~~
~~(d)Foreign currency to U.S. dollar.~~
~~(e)Represents the strike price at which the foreign currency can be purchased.~~
The aggregate effect on foreign exchange ~~forward and option~~ contracts of a hypothetical 10 percent change to quarter-end forward exchange rates would be approximately ~~$10~~$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~~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 ~~Rules~~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 ~~September 30, 2005,~~March 31, 2006, there were no changes in our internal controls over financial reporting that have materially affected, or ~~are~~were reasonably likely to materially affect, our internal controls over financial reporting.
~~We review~~
     Marathon reviews and ~~modify our~~modifies its financial and operational controls on an ongoing basis to ensure that those controls are adequate to address changes in ~~our~~its business as it evolves. ~~We believe~~Marathon believes that ~~our~~its existing financial and operational controls and procedures are adequate.
28
32

MARATHON OIL CORPORATION
Supplemental Statistics – (Unaudited)

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.
29

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

(Dollars in millions, except as noted)

2005

2004

2005

2004

INCOME FROM OPERATIONS

Exploration and Production

United States

$
397

$
244

$
1,096

$
835

International

230

107

862

418

E&P segment income

627

351

1,958

1,253

Refining, Marketing and Transportation(a)

814

391

1,847

1,017

Integrated Gas(b)

(6
)
18

12

25

Segment income

1,435

760

3,817

2,295

Items not allocated to segments:

Administrative expenses

(108
)
(90
)
(284
)
(238
)
Loss on U.K. long-term gas contracts

(82
)
(129
)
(306
)
(210
)
Gain on ownership change - MPC

—

1

—

2

Gain on sale of minority interests in EGHoldings

23

—

23

—

Income from operations

$
1,268

$
542

$
3,250

$
1,849

CAPITAL EXPENDITURES

Exploration and Production

$
387

$
249

$
1,000

$
601

Refining, Marketing and Transportation

201

146

498

419

Integrated Gas(b)

205

58

513

346

Corporate

1

5

4

11

Total

$
794

$
458

$
2,015

$
1,377

EXPLORATION EXPENSE

United States

$
18

$
15

$
60

$
47

International

46

31

75

61

Total

$
64

$
46

$
135

$
108

OPERATING STATISTICS

Net Liquid Hydrocarbon Sales (mbpd)(c)

United States

70.7

80.7

75.9

86.6

Europe

11.3

31.4

30.4

39.1

West Africa

48.0

29.2

48.3

31.3

Other international

27.0

15.3

25.1

15.8

Total international

86.3

75.9

103.8

86.2

Worldwide

157.0

156.6

179.7

172.8

Net Natural Gas Sales (mmcfd)(c)(d)

United States

561.8

598.0

570.4

646.6

Europe

158.7

225.8

244.4

278.9

West Africa

86.3

77.4

92.7

74.9

Total international

245.0

303.2

337.1

353.8

Worldwide

806.8

901.2

907.5

1,000.4

Total production (mboepd)

291.5

306.8

331.0

339.5

33

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

2005

2004

2005

2004

Average Sales Prices (excluding derivative gains and losses)

Liquid Hydrocarbons ($ per bbl)

United States

$
52.38

$
35.56

$
44.24

$
32.23

Europe

61.44

41.37

49.73

35.12

West Africa

50.45

38.82

47.03

33.11

Other international

38.78

24.89

32.98

20.88

Total international

48.24

37.07

44.42

31.78

Worldwide

50.10

36.29

44.34

32.00

Natural Gas ($ per mcf)

United States

$
6.56

$
4.76

$
5.76

$
4.83

Europe

4.69

3.66

4.90

3.92

West Africa

0.25

0.25

0.25

0.25

Total international

3.12

2.79

3.62

3.15

Worldwide

5.52

4.10

4.96

4.23

Average Sales Prices (including derivative gains and losses)

Liquid Hydrocarbons ($ per bbl)

United States

$
52.38

$
28.58

$
44.24

$
28.58

Europe

61.44

35.37

49.73

32.31

West Africa

50.45

38.82

47.03

33.11

Other international

38.78

24.89

32.98

20.84

Total international

48.24

34.59

44.42

30.49

Worldwide

50.10

31.49

44.34

29.53

Natural Gas ($ per mcf)

United States

$
6.37

$
4.65

$
5.68

$
4.77

Europe(e)

4.69

3.66

4.90

3.92

West Africa

0.25

0.25

0.25

0.25

Total international

3.12

2.79

3.62

3.15

Worldwide

5.38

4.02

4.92

4.19

34
MARATHON OIL CORPORATION
Supplemental Statistics (Unaudited)

Third Quarter Ended
September 30,

Nine Months Ended
September 30,

(Dollars in millions, except as noted)

2005

2004

2005

2004

Refinery Runs (mbpd):

Crude oil refined

979.6

977.1

971.4

926.6

Other charge and blend stocks

215.2

146.3

187.2

161.4

Total

1,194.8

1,123.4

1,158.6

1,088.0

Refined Product Yields (mbpd):

Gasoline

658.1

610.3

623.7

595.2

Distillates

325.4

311.7

314.9

290.0

Propane

22.3

22.6

21.6

21.7

Feedstocks and special products

88.8

88.6

100.8

97.3

Heavy fuel oil

21.0

19.3

24.4

22.1

Asphalt

90.2

85.5

86.6

75.8

Total

1,205.8

1,138.0

1,172.0

1,102.1

Refined Products Sales Volumes (mbpd)(f)

1,466.8

1,436.2

1,438.2

1,394.7

Matching buy/sell volumes included in refined product sales volumes (mbpd)

66.4

83.5

77.8

79.1

Refining and Wholesale Marketing Margin(g)(h)

$
0.1774

$
0.0900

$
0.1369

$
0.0849

Number of SSA Retail Outlets

1,638

1,685

SSA Gasoline and Distillate Sales(i)

825

794

2,392

2,358

SSA Gasoline and Distillate Gross Margin(g)

$
0.1232

$
0.1185

$
0.1170

$
0.1175

SSA Merchandise Sales

$
689

$
632

$
1,894

$
1,754

SSA Merchandise Gross Margin

$
162

$
154

$
468

$
426

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

^(e) Excludes all derivative gains and losses, including the effects of long-term U.K. natural gas contracts that are accounted for as derivatives. There were no equity production hedges in the first quarters of 2006 and 2005.
^(f) Total average daily volumes of all refined product sales to wholesale, branded and retail (SSA) customers.
^(g) Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation.
~~(a)~~         RM&T segment income includes Ashland’s 38 percent interest in MPC of $149 million in the third quarter of 2004, and $390 million and $389 million for the first nine months of 2005 and 2004, respectively.30
~~(b)~~         ~~Includes EGHoldings at 100 percent.~~
~~(c)~~          ~~Amounts reflect sales after royalties, except for Ireland where amounts are before royalties.~~
~~(d)~~         Includes gas acquired for injection and subsequent resale of 58.9, and 14.4 mmcfd for the third quarter of 2005 and 2004 and 34.1 and 19.9 mmcfd for the first nine months of 2005 and 2004. Effective July 1, 2005, the methodology for allocating sales volumes between gas produced from the Brae complex and third-party gas production was modified, resulting in an increase in volumes representing gas acquired for injection and subsequent resale.
~~(e)~~          ~~Excludes the effects of the U.K. long-term gas contracts that are accounted for as derivatives.~~
~~(f)~~           ~~Total average daily volumes of all refined product sales to wholesale, branded and retail (SSA) customers.~~
~~(g)~~          ~~Dollars per gallon.~~
~~(h)~~         ~~Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation.~~
~~(i)~~             ~~Millions of gallons.~~
35

Part II -– OTHER INFORMATION
Item 1. Legal Proceedings
U.S. EPA Litigation
     In April 2006, the Montana Board of Environmental ~~Proceedings~~
~~The Ohio Attorney General, on behalf~~Review (“MBER”) amended its water quality regulations for produced water from coal bed methane production. These regulations build upon water quality standards adopted by MBER and approved by the U.S. EPA in 2003. MBER’s regulations could require certain Wyoming coal bed methane operations to do higher cost water treatment or injection of produced water, or may delay or prevent obtaining necessary permits to discharge produced water flowing from Wyoming into Montana. Due to Marathon’s evolving plans for coal bed methane development in Wyoming, and the potential effects of the ~~Ohio Environmental Protection Agency, has notified SSA~~Montana regulations, Marathon and another operator filed a petition on April 25, 2006 with the U.S. District Court for the District of Wyoming to review the EPA’s original approval of Montana’s water quality standards on the grounds that this approval was arbitrary and capricious, and therefore unlawful.
Item 1A. Risk Factors
     Marathon is subject to various risks and uncertainties in the course of its ~~intention to bring an enforcement action for alleged wastewater violations at three~~business. See the discussion of ~~its locations~~such risks and uncertainties under Item 1A. Risk Factors in ~~Ohio. SSA personnel~~Marathon’s 2005 Annual Report on Form 10-K. There have been no material changes from the risk factors previously disclosed in ~~discussions with Ohio officials in an attempt to resolve this matter.~~
that Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about purchases of equity securities that are registered by Marathon pursuant to Section 12 of the Exchange Act by Marathon and its affiliated purchaser during the third quarter of 2005:
ISSUER PURCHASES OF EQUITY SECURITIES

(c)

Period

(a)
Total Number of
Shares Purchased(1)(2)

(b)
Average Price Paid
per Share

Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs

(d)
Maximum Number of
Shares that May Yet
Be Purchased Under
the Plans or Programs

07/01/05 – 07/31/05

7,564

$
53.46

N/A

N/A

08/01/05 – 08/31/05

1,765

$
59.75

N/A

N/A

09/01/05 – 09/30/05

23,146
(3)
$
67.97

N/A

N/A

3^rd Quarter 2005

32,475

$
64.14

N/A

N/A

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

01/01/06 – 01/31/06 81,100 $ 76.82 — $ 2,000,000,000
02/01/06 – 02/28/06 413,804 $ 71.14 413,800 $ 1,970,563,160
03/01/06 – 03/31/06 2,788,847 ^(c) $ 72.96 2,737,800 $ 1,770,839,546
Total 3,283,751 $ 72.83 3,151,600
~~(1)6,982 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements in the third quarter of 2005.~~
~~(2)~~Under the terms of the Acquisition, Marathon paid Ashland shareholders cash in lieu of issuing fractional shares of Marathon’s common stock to which such holder would otherwise be entitled. The number of fractional shares Marathon acquired due to Acquisition
^(a) 112,791 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.
^(b) Under the terms of the transaction whereby Marathon acquired the minority interest in MPC and other businesses from Ashland Inc., Marathon paid Ashland Inc. shareholders cash in lieu of issuing fractional shares of Marathon’s common stock to which such holders would otherwise be entitled. Marathon acquired 6 shares due to acquisition share exchanges and Ashland Inc. share transfers pending at the closing of the transaction.
^(c) 19,354 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Stock needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon.
^(d) 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 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.
31
Item 4. Submission of Matters to a Vote of Security Holders
     The annual meeting of stockholders was held on April 26, 2006. In connection with the meeting, proxies were solicited pursuant to the Securities Exchange Act of 1934. The following are the voting results on proposals considered and voted upon at the ~~time~~meeting, all of ~~closing of the Acquisition~~which were ~~5,875, 19, and 8 for the months of July, August and September, respectively.~~described in Marathon’s 2006 Proxy Statement.
1. Votes regarding the persons elected to serve as Class I directors for a term expiring in 2009 were as follows:

NOMINEE VOTES FOR VOTES WITHHELD
Clarence P. Cazalot, Jr. 306,764,458 15,827,069
David A. Daberko 303,433,496 19,158,031
William L. Davis 310,566,832 12,024,695
Continuing as Class II directors for a term expiring in 2007 are Charles F. Bolden, Jr., Charles R. Lee, Dennis H. Reilley and Thomas J. Usher. Continuing as Class III directors for a term expiring in 2008 are Shirley Ann Jackson, Philip Lader, Seth E. Schofield and Douglas C. Yearley.
2. PricewaterhouseCoopers LLP was ratified as the independent auditors for 2006. The voting results were as follows:

VOTES FOR VOTES AGAINST VOTES ABSTAINED
315,237,067 4,911,915 2,416,550
3. The Board of Directors proposal to amend the Restated Certificate of Incorporation to declassify the Board of Directors was approved. The voting results were as follows:

VOTES FOR VOTES AGAINST VOTES ABSTAINED
316,615,678 3,100,505 2,838,147
4. The Board of Directors proposal to amend the Restated Certificate of Incorporation to revise the purpose clause, eliminate the Series A Junior Preferred Stock and make other technical changes was approved. The voting results were as follows:

VOTES FOR VOTES AGAINST VOTES ABSTAINED
318,561,637 1,089,662 2,903,498
5. The stockholder proposal to elect directors by a majority vote was approved. The proposal requested that the Board of Directors initiate the appropriate process to amend the Company’s governance documents (certificate of incorporation or bylaws) to provide that a director nominee shall be elected by the affirmative vote of the majority of votes cast at an annual meeting of shareholders. The voting results were as follows:

VOTES VOTES VOTES BROKER
FOR AGAINST ABSTAINED NON-VOTES
191,576,749 91,294,280 3,975,143 35,745,355
6. The stockholder proposal for a simple majority vote of shareholders was approved. The proposal recommended that the Board of Directors take each step necessary for a simple majority vote to apply on each issue that can be subject to shareholder vote to the greatest extent possible. The voting results were as follows:

VOTES VOTES VOTES BROKER
FOR AGAINST ABSTAINED NON-VOTES
236,460,419 47,119,626 3,265,194 35,746,288
32
~~(3)~~19,591 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Plan”) by the administrator of the Plan during the third quarter of 2005. Shares needed to meet the requirements of the Plan are either purchased in the open market or issued directly by Marathon.
Item 6. Exhibits
3.1 (a) Restated Certificate of Incorporation of Marathon Oil Corporation
3.1 (b) Certificate of Amendment of Restated Certificate of Incorporation of Marathon Oil Corporation
3.2 By-Laws of Marathon Oil Corporation (incorporated by reference to Exhibit 3.2 to Marathon Oil Corporation’s Form 8-K, filed on April 28, 2006)
4.1 Amendment No. 1 dated as of May 4, 2006 to the Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents, and JPMorgan Chase Bank, N.A, as Administrative Agent
12.1 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
12.2 Computation of Ratio of Earnings to Fixed Charges
31.1 Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
31.2 Certification of Senior Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2 Certification of Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350
33
~~(a)~~         ~~EXHIBITS~~
~~10.1~~            ~~Summary of non-employee director compensation effective January 1, 2006 (incorporated by reference to Form 8-K filed October 31, 2005)~~
~~10.2~~            ~~Summary of Gary R. Heminger’s compensation and performance criteria (incorporated by reference to Form 8-K filed July 1, 2005)~~
~~12.1~~            ~~Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends~~
~~12.2~~            ~~Computation of Ratio of Earnings to Fixed Charges~~
~~31.1~~            ~~Certification of President and Chief Executive Officer pursuant to Exchange Act Rules 13a-14 and 15d-14, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~
~~31.2~~            ~~Certification of Senior Vice President and Chief Financial Officer pursuant to Exchange Act Rules 13a-14 and 15d-14, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002~~
~~32.1~~            ~~Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002~~
~~32.2~~            ~~Certification of Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002~~
36
SIGNATURES

~~SIGNATURE~~
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned ~~chief accounting officer~~ thereunto duly authorized.
MARATHON OIL CORPORATION
By: Michael K. Stewart
~~By:~~
~~/s/ A. G. Adkins~~
~~A. G. Adkins~~
Michael K. Stewart
Vice President, ~~–Accounting~~Accounting and Controller
May 8, 2006
34
Index to Exhibits
3.1 (a) Restated Certificate of Incorporation of Marathon Oil Corporation
~~November~~
3.1 (b) Certificate of Amendment of Restated Certificate of Incorporation of Marathon Oil Corporation
3.2 By-Laws of Marathon Oil Corporation (incorporated by reference to Exhibit 3.2 to Marathon Oil Corporation’s Form 8-K, filed on April 28, 2006)
4.1 Amendment No. 1 dated as of May 4, ~~2005~~
2006 to the Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents, and JPMorgan Chase Bank, N.A, as Administrative Agent
12.1 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
12.2 Computation of Ratio of Earnings to Fixed Charges
31.1 Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
31.2 Certification of Senior Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
32.1 Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2 Certification of Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350

37

~~Delaware~~		~~25-0996816~~
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)~~

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


o
		~~For the Quarterly Period Ended September 30, 2005~~

		OR

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


Large accelerated filerþ		Accelerated filero		Non-accelerated filero

	Third Quarter Ended September 30,						Nine Months Ended September 30,
(Dollars in millions, except per share data)	2005			2004			2005			2004
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	13,345		$	9,701		$	35,271		$	27,935
Revenues from matching buy/sell transactions	3,433			2,263			9,807			6,714
Sales to related parties	396			285			1,047			766
Income from equity method investments	69			38			154			108
Net gains on disposal of assets	12			17			46			25
Gain on ownership change in Marathon Petroleum Company LLC	—			1			—			2
Other income (loss) – net	(7		)	11			34			51
Total revenues and other income	17,248			12,316			46,359			35,601

Costs and expenses:
Cost of revenues (excluding items shown below)	10,833			7,699			27,790			21,676
Purchases related to matching buy/sell transactions	3,038			2,197			9,312			6,588
Purchases from related parties	44			58			163			152
Consumer excise taxes	1,217			1,137			3,511			3,327
Depreciation, depletion and amortization	331			296			993			896
Selling, general and administrative expenses	325			261			853			763
Other taxes	128			80			352			242
Exploration expenses	64			46			135			108
Total costs and expenses	15,980			11,774			43,109			33,752
Income from operations	1,268			542			3,250			1,849
Net interest and other financing costs	32			40			99			129
Minority interests in income (loss) of:
Marathon Petroleum Company LLC	—			148			384			385
Equatorial Guinea LNG Holdings Limited	(3		)	(1		)	(4		)	(5		)
Income from continuing operations before income taxes	1,239			355			2,771			1,340
Provision for income taxes	469			133			1,004			512
Income from continuing operations	770			222			1,767			828
Discontinued operations	—			—			—			4
Net income	$	770		$	222		$	1,767		$	832

(Dollars in millions, except per share data)	September 30, 2005			December 31, 2004
Assets
Current assets:
Cash and cash equivalents	$	1,043		$	3,369
Receivables, less allowance for doubtful accounts of $3 and $6	3,808			3,146
Receivables from United States Steel	21			15
Receivables from related parties	102			74
Inventories	3,338			1,995
Other current assets	211			267
Total current assets	8,523			8,866
Investments and long-term receivables, less allowance for doubtful accounts of $11 and $10	1,830			1,546
Receivables from United States Steel	576			587
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $12,060 and $12,426	13,704			11,810
Prepaid pensions	102			128
Goodwill	950			252
Intangibles	184			118
Other assets	116			116
Total assets	$	25,985		$	23,423

Liabilities
Current liabilities:
Commercial paper payable	$	285		$	—
Accounts payable	5,194			4,430
Payables to related parties	52			44
Payables to United States Steel	6			—
Payroll and benefits payable	279			274
Accrued taxes	576			397
Deferred income taxes	496			—
Accrued interest	52			92
Long-term debt due within one year	316			16
Total current liabilities	7,256			5,253
Long-term debt	3,728			4,057
Deferred income taxes	1,777			1,553
Employee benefits obligations	1,204			989
Asset retirement obligations	505			477
Payables to United States Steel	5			5
Deferred credits and other liabilities	451			288
Total liabilities	14,926			12,622
Minority interest in Marathon Petroleum Company LLC	—			2,559
Minority interests in Equatorial Guinea LNG Holdings Limited	417			131
Commitments and contingencies
Stockholders’ Equity
Common stock:
Common stock issued – 366,705,131 shares at September 30, 2005 and 346,727,029 shares at December 31, 2004 (par value $1 per share, 550,000,000 shares authorized)	367			347
Common stock held in treasury – 225,778 shares at September 30, 2005 and 29,569 shares at December 31, 2004	(9		)	(1		)
Additional paid-in capital	5,092			4,028
Retained earnings	5,261			3,810
Accumulated other comprehensive loss	(56		)	(64		)
Unearned compensation	(13		)	(9		)
Total stockholders’ equity	10,642			8,111
Total liabilities and stockholders’ equity	$	25,985		$	23,423


	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

		Nine Months Ended September 30,
(Dollars in millions)		2005			2004
*Increase (decrease) in cash and cash equivalents*

Operating activities
Net income		$	1,767		$	832
Adjustments to reconcile net income to net cash provided from operating activities:
Income from discontinued operations		—			(4		)
Deferred income taxes		(83		)	(26		)
Minority interests in income of subsidiaries		380			380
Depreciation, depletion and amortization		993			896
Pension and other postretirement benefits - net		21			30
Exploratory dry well costs		66			44
Net gains on disposal of assets		(46		)	(25		)
Changes in the fair value of long-term natural gas contracts in the United Kingdom		306			210
Changes in working capital:
Current receivables		(1,577		)	(441		)
Inventories		(457		)	(372		)
Current accounts payable and accrued expenses		727			554
All other - net		(134		)	(101		)

Net cash provided from operating activities		1,963			1,977

Investing activities
Capital expenditures		(2,015		)	(1,377		)
Acquisition		(506		)	—
Disposal of assets		99			47
Proceeds from sale of minority interests in Equatorial Guinea LNG Holdings Limited		163			—
Restricted cash	- deposits	(27		)	(25		)
	- withdrawals	19			6
Investments - loans and advances		(40		)	(152		)
All other - net		6			3
Net cash used in investing activities		(2,301		)	(1,498		)

Financing activities
Payment of debt assumed in acquisition		(1,920		)	—
Commercial paper and revolving credit arrangements - net		285			—
Debt issuance costs		—			(5		)
Other debt repayments		(7		)	(257		)
Issuance of common stock		77			1,036
Dividends paid		(314		)	(251		)
Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited		175			95
Distributions to minority shareholder of Marathon Petroleum Company LLC		(272		)	–
Net cash provided from (used in) financing activities		(1,976		)	618
Effect of exchange rate changes on cash		(12		)	(1		)
Net increase (decrease) in cash and cash equivalents		(2,326		)	1,096
Cash and cash equivalents at beginning of period		3,369			1,396
Cash and cash equivalents at end of period		$	1,043		$	2,492

	September 30,		December 31,
(In millions)	2005		2004
Receivables related to debt and other obligations for which United States Steel has assumed responsibility for repayment:
Current	$	21	$	15
Noncurrent	576		587

Current income tax settlement and related interest payable	$	6	$	—
Noncurrent reimbursements payable under nonqualified employee benefit plans	5		5

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.

(In millions)	Amount
Cash (a)	$	487
MPC accounts receivable (a)	913
Marathon common stock (b)	955
Estimated additional consideration related to tax matters (c)	44
Transaction-related costs	10
Purchase price	$	2,409
Assumption of debt (d)	1,920
Total consideration including debt assumption(e)	$	4,329

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.

(In millions)	Lives	Amount
Retail marketing tradenames	Various	$	52
Refinery permits and plans	15 years	26
Marketing brand agreements	5-10 years	13
Refining technology	5-15 years	12
Other	Various	6
Total		$	109

	Third Quarter Ended September 30,				Nine Months Ended September 30,
(In millions, except per share data)	2005		2004		2005		2004
Revenues and other income	$	17,248	$	12,326	$	46,405	$	35,656
Net income	$	770	$	294	$	1,976	$	1,025
Net income per share:
Basic	$	2.11	$	0.81	$	5.42	$	2.92
Diluted	$	2.09	$	0.81	$	5.38	$	2.91

		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.

	Third Quarter Ended September 30,
	2005				2004
(Dollars in millions, except per share data)	Basic		Diluted		Basic		Diluted
Net income	$	770	$	770	$	222	$	222
Shares of common stock outstanding (in thousands):
Average number of common shares outstanding	365,137		365,137		345,037		345,037
Effect of dilutive securities – stock options	—		3,427		—		1,932
Average common shares including dilutive effect	365,137		368,564		345,037		346,969

Net income per share	$	2.11	$	2.09	$	0.64	$	0.64

	Nine Months Ended September 30,
	2005				2004
(Dollars in millions, except per share data)	Basic		Diluted		Basic		Diluted
Income from continuing operations	$	1,767	$	1,767	$	828	$	828
Income from discontinued operations	—		—		4		4
Net income	$	1,767	$	1,767	$	832	$	832
Shares of common stock outstanding (in thousands):
Average number of common shares outstanding	352,807		352,807		333,456		333,456
Effect of dilutive securities – stock options	—		2,919		—		1,713
Average common shares including dilutive effect	352,807		355,726		333,456		335,169

Per share:
Income from continuing operations	$	5.01	$	4.97	$	2.48	$	2.47
Income from discontinued operations	$	—	$	—	$	0.01	$	0.01
Net income	$	5.01	$	4.97	$	2.49	$	2.48


	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

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.

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.


										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

(In millions)	E&P			RM&T			IG			Total Segments
Third Quarter 2005
Revenues:
Customer	$	1,400		$	14,989		$	471		$	16,860
Intersegment(a)	104			78			46			228
Related parties	3			393			—			396
Segment revenues	1,507			15,460			517			17,484
Elimination of intersegment revenues	(104		)	(78		)	(46		)	(228		)
Loss on long-term U.K. gas contracts	(82		)	—			—			(82		)
Total revenues	$	1,321		$	15,382		$	471		$	17,174

Segment income	$	627		$	814		$	(6	)	$	1,435
Income from equity method investments	15			38			16			69
Depreciation, depletion and amortization(b)	198			123			2			323
Capital expenditures(c)	387			201			205			793

Third Quarter 2004
Revenues:
Customer	$	1,110		$	10,578		$	405		$	12,093
Intersegment (a)	99			38			42			179
Related parties	2			283			—			285
Segment revenues	1,211			10,899			447			12,557
Elimination of intersegment revenues	(99		)	(38		)	(42		)	(179		)
Loss on long-term U.K. gas contracts	(129		)	—			—			(129		)
Total revenues	$	983		$	10,861		$	405		$	12,249

Segment income	$	351		$	391		$	18		$	760
Income from equity method investments	8			17			13			38
Depreciation, depletion and amortization(b)	180			105			2			287
Capital expenditures(c)	249			146			58			453


^(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.

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

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:

8.		Comprehensive Income

		The following sets forth Marathon’s comprehensive income for the periods indicated: