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| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) |
o | ||
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| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) |
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Delaware | 25-0996816 | |
(State of Incorporation) | (I.R.S. Employer Identification No.) | |
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Yes ý Noo
Large accelerated filerþ | Accelerated filero | Non-accelerated filero |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yeso No No þ
There were 366,479,353362,436,024 shares of Marathon Oil Corporation common stock outstanding as of SeptemberApril 30, 2005.2006.
2
MARATHON OIL CORPORATION
First Quarter Ended March 31, | ||||||||
(Dollars in millions, except per share data) | 2006 | 2005 | ||||||
Revenues and other income: | ||||||||
Sales and other operating revenues (including consumer excise taxes) | $ | 12,998 | $ | 9,840 | ||||
Revenues from matching buy/sell transactions | 3,206 | 2,809 | ||||||
Sales to related parties | 312 | 283 | ||||||
Income from equity method investments | 92 | 40 | ||||||
Net gains on disposal of assets | 11 | 11 | ||||||
Other income | 19 | 27 | ||||||
Total revenues and other income | 16,638 | 13,010 | ||||||
Costs and expenses: | ||||||||
Cost of revenues (excludes items below) | 9,769 | 7,692 | ||||||
Purchases related to matching buy/sell transactions | 3,233 | 2,832 | ||||||
Purchases from related parties | 51 | 56 | ||||||
Consumer excise taxes | 1,165 | 1,084 | ||||||
Depreciation, depletion and amortization | 415 | 323 | ||||||
Selling, general and administrative expenses | 287 | 260 | ||||||
Other taxes | 149 | 105 | ||||||
Exploration expenses | 71 | 34 | ||||||
Total costs and expenses | 15,140 | 12,386 | ||||||
Income from operations | 1,498 | 624 | ||||||
Net interest and other financing costs | 24 | 32 | ||||||
Minority interests in income (loss) of: | ||||||||
Marathon Petroleum Company LLC | — | 70 | ||||||
Equatorial Guinea LNG Holdings Limited | (3 | ) | (1 | ) | ||||
Income before income taxes | 1,477 | 523 | ||||||
Provision for income taxes | 693 | 199 | ||||||
Net income | $ | 784 | $ | 324 | ||||
Per share information: | ||||||||
Net income per share — basic | $ | 2.15 | $ | 0.94 | ||||
Net income per share — diluted | $ | 2.13 | $ | 0.93 | ||||
Dividends paid per share | $ | 0.33 | $ | 0.28 | ||||
|
| Third Quarter Ended |
| Nine Months Ended |
| ||||||||
(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 |
| Nine Months Ended |
| ||||||||
|
| 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.
3
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, |
| December 31, |
| ||
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.
4
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 |
| |||||
(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.
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 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 |
| Nine Months Ended |
| ||||||||
(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 |
| Nine Months Ended |
| ||||||||
(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 |
| ||||
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 |
| ||||
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 |
| ||||
(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 |
| ||||
(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 |
| Nine Months Ended |
| ||||||||
(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, |
| December 31, |
| ||
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 |
| ||||||
(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
Form 10-K.
10-K.
Overview and Outlook
We acquired the 38
During the thirdfirst 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 20,0002006 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 291,500376,800 boepd. ProductionThis period’s variance between production available for sale during the third quarter of 2005 averaged 321,000 boepd. The variance betweenand actual sales volumes is primarily attributable to the timing of liquid hydrocarbon liftings from our operations in Libya, Equatorial Guinea and the U.K.
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 continuesdefine growth plans for this major asset.
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 developmentAlvheim 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.
15
Our
While spot market gasoline and distillate prices peaked at all time highsfirst 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 thirdfirst quarter of 2005 averaged 979,600 bpd, with2006, our total throughput averaging 1,194,800 bpd. This recordrefinery throughput was achieved despiteapproximately five percent higher than the loss of approximately 40,000 bpd of refinery capacity duesame 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 ofexpect 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 our2006 average crude oil throughput will exceed our record throughput for 2005. Also during the total year 2005first 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 exceedcomply 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.
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
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 expansionprojections of the Garyville refinery. Some factorscrude oil throughput that could potentially causebe affected by planned and unplanned refinery maintenance projects, the actual results from the Detroit construction project to be different than expected include availabilitylevels 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.
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.
16
20
|
| Third Quarter Ended |
| Nine Months Ended |
| ||||||||
(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 | ||||
hurricane damage.
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.
Segment Income.
17
21
Purchasesthe 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 quarterCamden Hills field in the Gulf of Mexico and first nine months of 2005 increased by $841 million and $2.724 billionthe 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 thirdfirst 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 income2006 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.
Exploration expenses for the third quarter and the first nine months of 2005 increased by $18 million and $27 million compared to the same periodsfirst 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. DuringEquatorial Guinea and increased costs for outside professional services, partially offset by lower stock-based compensation expense.
Net interest and other financing costs for the third quarterU.K. and the first nine months of 2005 decreased by $8 million and $30 million, compared to the same periodsSoulandaka 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.
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
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 | ||||
19
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 eliminationA key driver of the minority interestincrease 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 |
| Nine Months Ended |
| ||||||||
(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&PRM&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 marketinggross margin, in the third quarter and the first nine months of 2005which averaged 17.7 and 13.711.37 cents per gallon versusin the 2004 comparable period levelsfirst quarter of 9.0 and 8.52006 compared to 6.85 cents per gallon. We also benefited from wider crack spreads andgallon in the first quarter of 2005. This margin improvement reflected favorable sweet/sour crude differentials.
Losses from derivative activityoil differentials in the first quarter of 2006 and was consistent with the relevant indicators (crack spreads) in the Midwest (Chicago) and Gulf Coast markets.
Additionally, losses from derivativerelated to trading opportunitiesactivities were $42 million and $76$5 million in the thirdfirst quarter and the first nine months of 20052006 as compared to gainslosses 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 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.
Cash Flows
Net cash provided from operating activities May 17, 2006. This was $1.963 billiona 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.
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
24
Liquidity and Capital Resources
20
We have
May 2011. The Marathon and MPC revolving credit facilities each require a representation at an initial borrowing that therefacility has been no changeterminated.
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.
(Dollars in millions) |
| September 30, |
| December 31, |
| ||
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
Subsequent to
2005.
2005.
22
26
Environmental Matters
Tier II gasoline and on-road diesel fuel rules
requirements.
oil in its produced water discharges.
2005.
23
Other Matters
We suspended operations in Sudan in 1985, but continue
We discovereda sale of inventory with the Ash Shaer and Cherrife gas fields in Syriasame party that operates in the 1980’s. We submitted four planssame line of developmentbusiness is recorded at fair value or considered a single non-monetary transaction subject to the Syrian Petroleum Companyfair 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 disputeform of raw materials, work-in-process, or finished goods. In general, two or more transactions with the Syrian Petroleum Companysame 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 intherefore, upon adoption, these fields, and are currently discussingtransactions will no longer be recorded on a settlement under which a new production sharing contractgross basis. Management does not believe any impact on net income would be executed, and we would have the right to sell all ormaterial. There will be no impact on cash flows from operations as a significant portionresult 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
materials, and purchases of ethanol.
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. |
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.
25
28
|
| Incremental Decrease in |
| ||||
(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) | ||||||||||||
instruments. 26(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. market valueE&P segment for the first quarter of derivative instruments; however, such risk should be mitigated by price changes2006 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. EffectsE&P segment.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 $198losses 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 SegmentSeptember 30, 2005,March 31, 2006, we had no open equityderivative 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 ofrisks 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.
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
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 | ) | ||
|
| Nine Months Ended |
| ||||
(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.
30
Interest Rate Risk
(In millions) |
| Fair |
| Incremental |
| ||
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. |
27
Floating Rate to be Paid |
| Fixed Rate to |
| Notional |
| Swap |
| 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.
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 review
28
32
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 |
| Nine Months Ended |
| ||||||||
(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 |
| Nine Months Ended |
| ||||||||
|
| 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
|
| Third Quarter Ended |
| Nine Months Ended |
| ||||||||
(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
The Ohio Attorney General, on behalfReview (“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 SSAMontana 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.
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:
|
|
|
|
|
| (c) |
|
|
| |
Period |
| (a) |
| (b) |
| Total Number of |
| (d) |
| |
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 |
|
3rd 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.
31(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.
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.
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
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 | |||||
|
| |||||
| Michael K. Stewart | |||||
Vice President, |
34
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, | |
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