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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended March 31, 2005

OR

For the transition period from                      to                     

Commission file number 1-10578

VINTAGE PETROLEUM, INC.

(Exact name of registrant as specified in charter)

(918) 592-0101

(Registrant’s telephone number, including area code)

NOT APPLICABLE

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x    No ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes x    No ¨

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

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VINTAGE PETROLEUM, INC.

FORM 10-Q

THREE MONTHS ENDED MARCH 31, 2005

TABLE OF CONTENTS

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PART I

FINANCIAL INFORMATION

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ITEM 1. FINANCIAL STATEMENTS

VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In thousands, except shares

and per share amounts)

(Unaudited)

ASSETS

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Continued)

(In thousands, except shares

and per share amounts)

(Unaudited)

LIABILITIES AND STOCKHOLDERS’ EQUITY

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Continued)

(In thousands, except per share amounts)

(Unaudited)

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (LOSS)

FOR THE THREE MONTHS ENDED MARCH 31, 2005

(In thousands, except treasury shares and per share amounts)

(Unaudited)

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands, except per share amounts)

(Unaudited)

See notes to unaudited consolidated financial statements.

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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2005 and 2004

The accompanying financial statements are unaudited. The consolidated financial statements include the accounts of Vintage Petroleum, Inc. and its wholly- and majority-owned subsidiaries and its proportionately consolidated general partner interest in a joint venture engaged in exploration and production activities (collectively, the “Company”). All significant intercompany accounts and transactions have been eliminated in consolidation. Management believes that all material adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation have been made. Certain 2004 amounts have been reclassified to conform with the 2005 presentation, including reclassifications required for presentation of the discontinued operations discussed in Note 8. These reclassifications had no effect on the Company’s net income or stockholders’ equity.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

These financial statements and notes should be read in conjunction with the 2004 audited financial statements and related notes included in the Company’s 2004 Annual Report on Form 10-K, Item 8. Financial Statements and Supplementary Data.

Oil and Gas Properties and Unproved Property Impairments

Under the successful efforts method of accounting, the Company capitalizes all costs related to property acquisitions and successful exploratory wells, all development costs and the costs of support equipment and facilities. Certain costs of exploratory wells are capitalized pending determination that proved reserves have been found. Such determination may be dependent upon the results of planned additional wells and the cost of required capital expenditures to produce the reserves found. All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive; other exploration costs, including geological and geophysical costs incurred in exploration activities, are expensed as incurred. The Company recognizes gains or losses on the sale of properties on a field basis.

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Unproved leasehold costs are capitalized and reviewed periodically for impairment. Individual unproved properties whose acquisition costs are significant are assessed for impairment on a property-by-property basis, considering factors such as future drilling and exploitation plans and lease terms. For unproved properties whose acquisition costs are not individually significant, the amount of those properties’ impairment is determined by amortizing the properties in groups on the basis of the Company’s experience in similar situations and other information such as the primary lease terms, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. Costs related to impaired prospects are charged to expense and included in “exploration costs” in the accompanying statements of operations. The Company recorded unproved oil and gas property impairments of $1.4 million and $36,000 for the three months ended March 31, 2005 and 2004, respectively, excluding the Company’s discontinued operations (see Note 8). Additional impairment expense could result if oil and gas prices decline in the future or if downward reserve revisions are recorded on nearby properties, as it may not be economic to develop some of these unproved properties. Leasehold impairments related to the Company’s discontinued Canadian operations were $1.3 million for the three months ended March 31, 2004.

As of March 31, 2005, the Company had total unproved oil and gas property costs of approximately $29.9 million, consisting of undeveloped leasehold costs of $16.2 million and unevaluated exploratory drilling costs of $13.7 million. Approximately $13.7 million of the total unevaluated costs are associated with the Company’s exploratory drilling program in Yemen and the remaining $16.2 million of unevaluated costs are associated with the Company’s exploration activities in the U.S.

Costs of development dry holes and proved leaseholds are amortized on the unit-of-production method using proved reserves on a field basis. The depreciation of capitalized production equipment, drilling costs and asset retirement obligations is based on the unit-of-production method using proved developed reserves on a field basis.

Exploration Drilling Costs

Costs of drilling exploratory wells are capitalized as part of the Company’s unproved costs pending management’s determination of whether the wells have found proved reserves. Management makes this determination as soon as possible after completion of drilling considering the guidance provided in Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies (“SFAS 19”). SFAS 19 provides that such costs should not be carried as an asset for more than one year following completion of drilling unless the well has found oil and gas reserves in an area requiring a major capital expenditure before production could begin. In that case, the costs of such exploration well continue to be carried as an asset pending determination of whether proved reserves have been found only as long as the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and drilling of the additional exploratory wells is under way or firmly planned for the near future. If both those conditions are not met, the well costs are charged to expense. Management performs this evaluation on a quarterly basis.

As of March 31, 2005, the Company had the following exploration wells capitalized and reported as unevaluated costs (in thousands):

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As of March 31, 2005, the Company had one exploration well in Yemen on which the drilling was completed for more than one year with a total cost of approximately $6.6 million. Management believes that this well has found sufficient reserves to justify its completion and such well requires a major capital expenditure before production can begin. During 2004, the Company drilled another well in this area as part of the development with plans to continue development and evaluation of this area during 2005. Depending on the results of such activity, the costs capitalized for the completed wells may be charged to expense during 2005. The Company had no exploration wells capitalized in areas requiring a major capital expenditure before production could begin where additional drilling efforts are not underway or firmly planned and had no exploration wells capitalized in areas not requiring a major capital expenditure where more than one year has elapsed since completion of drilling.

On April 4, 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position No 19-1, Accounting for Suspended Well Costs (“FSP 19-1”). FSP 19-1 amends SFAS 19 to provide that in those situations where exploration drilling has been completed and oil and gas reserves have been found, but such reserves cannot be classified as proved when drilling is complete, the drilling costs may be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either of the criteria is not met, the well is assumed to be impaired and the costs charged to expense. Any well which has not found reserves is charged to expense. FSP 19-1 is effective for the first reporting period beginning after April 4, 2005, which will be the three months ended September 30, 2005, for the Company. Management believes that no adjustment would have been required as of the beginning of and for the three months ended March 31, 2005 and 2004, from the application of FSP 19-1.

For the three months ended March 31, 2005, the changes in unevaluated capitalized exploratory drilling costs were as follows (in thousands):

Impairments of Proved Oil and Gas Properties

The Company reviews its proved oil and gas properties for impairment on a field basis. For each field, an impairment provision is recorded whenever events or circumstances indicate that the carrying value of those properties may not be recoverable from estimated future net revenues. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and risk-adjusted probable and possible oil and gas reserves over the economic life of the reserves, based on the Company’s expectations of future oil and gas prices and costs, consistent with price and cost assumptions used for acquisition evaluations. In the first quarter of 2004, the Company recorded an impairment of $3.9 million related to one proved oil and gas property in the U.S. No impairment provision related to the proved oil and gas properties was required in the first three months of 2005.

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Development Seismic Costs

The Company capitalizes delineation seismic costs incurred to select development drilling locations within a productive oil and gas field as development costs. Exploration seismic costs are expensed as incurred. The Company did not capitalize any delineation seismic costs in the three months ended March 31, 2005.

Asset Retirement Obligations

The Company records the discounted fair value of its asset retirement obligations as a liability at the time an asset is placed in service. The asset retirement obligations consist primarily of costs associated with the plugging and abandonment of oil and gas wells, site reclamation and facilities dismantlement. However, future abandonment liabilities are also recorded for other assets such as pipelines, processing plants and compressors. A corresponding amount is capitalized as part of the related property’s carrying amount. The discounted capitalized asset retirement cost is amortized to expense through the depreciation calculation over the estimated useful life of the asset based on proved developed reserves. The liability accretes over time with a charge to accretion expense. At March 31, 2005, there were no assets legally restricted for purposes of settling asset retirement obligations. Of the liability for asset retirement obligations balance at March 31, 2005, approximately $2.4 million is classified as current and is included in “other payables and accrued liabilities” in the accompanying balance sheet.

The Company recorded the following activity related to its asset retirement liability for the three months ended March 31, 2005 (in thousands):

Other Payables and Accrued Liabilities

As of March 31, 2005, “other payables and accrued liabilities” includes $17.3 million of accrued oil and gas capital expenditures.

Derivative Financial Instruments

The Company periodically uses hedges to reduce the impact of oil and natural gas price fluctuations and generally attempts to qualify such derivatives as cash flow hedges for accounting purposes. The Company accounts for its hedging activities under the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (as amended, “SFAS 133”). SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The Company defines fair value as the amount it would receive or pay to settle the derivative at period-end. SFAS 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations. Companies must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.

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For derivative instruments that qualify as cash flow hedges, the effective portion of the gain or loss on a derivative instrument is reported as a component of other comprehensive income and reclassified into sales revenue in the same period or periods during which the hedged forecasted transaction affects earnings. The effective portion is determined by comparing the cumulative change in fair value of the derivative to the cumulative change in the expected cash flows of the item being hedged. To the extent the cumulative change in the derivative exceeds the cumulative change in the expected cash flows, the excess is recognized currently in earnings as non-operating income or expense. If the cumulative change in the expected cash flows exceeds the change in fair value of the derivative, the difference is ignored. Changes in the fair value and settlements of derivative financial instruments that do not qualify, or ceased to qualify, for accounting treatment as hedges, if any, are recognized currently as non-operating income or expense. The cash flows from derivative financial instruments that do not qualify for hedge accounting are included in investing activities in the consolidated statements of cash flows.

Derivative losses included in income from continuing operations consist of the following (in thousands):

Revenue Recognition

A portion of the Company’s domestic oil sales in Argentina were previously subject to a domestic price cap agreement, relating to deliveries occurring between February 26, 2003, and April 30, 2004. Under the agreement, if the $28.50 price cap is less than the West Texas Intermediate posted price as quoted on the Platt’s Crude Oil Marketwire at the time of sale, the Company is entitled to charge the oil purchasers for such difference only when the West Texas Intermediate posted price is less than the $28.50 price cap in future periods. The Company does not record any revenue under such price cap agreement until such time as the billed amounts are actually received. As of March 31, 2005, the Company had an unbilled potential recovery of approximately $7.5 million under this agreement, excluding interest. During the three months ended March 31, 2005 and 2004, the Company did not record any revenues under this agreement.

Oil inventories held in storage facilities are valued at cost, which is lower than market value. Such inventories totaled $3.8 million at March 31, 2005 and are included in “prepaids and other current assets” in the accompanying consolidated balance sheet.

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General and Administrative Expense

The Company receives fees for the operation of jointly-owned oil and gas properties and records such reimbursements as reductions of general and administrative expense. Such fees totaled approximately $0.7 million and $0.6 million for the first quarter of 2005 and 2004, respectively. These amounts exclude reimbursements related to the Company’s discontinued operations in Canada.

Stock Compensation

The Company has two fixed stock-based compensation plans which reserve shares of common stock for issuance to key employees and directors. Prior to 2003, the Company accounted for these plans under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Compensation expense for restricted stock awards is recorded over the vesting periods of the awards. No stock compensation expense related to stock options granted prior to 2003 has been recognized, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the grant date.

Effective January 1, 2003, the Company adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (“SFAS 123”). The Company adopted these provisions prospectively and applied them to all employee and director awards granted, modified, or settled after January 1, 2003. Stock option awards under the Company’s plans generally vest over three years, therefore, the cost related to stock compensation included in the determination of net income for the first three months of 2005 and 2004 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS 123. The following table illustrates the effect on net income and income per share if the fair value based method had been applied to all outstanding and unvested awards in each period (in thousands, except per share amounts):

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. The Company did not grant any stock options in 2004 or in the first three months of 2005.

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Production and Ad Valorem Taxes

Included in production and ad valorem taxes are the following items (in thousands):

Income Per Share

Basic income per common share was computed by dividing net income by the weighted average number of shares outstanding during the period. Diluted income per common share for all periods presented was computed assuming the exercise of all dilutive options, as determined by applying the treasury stock method, and assuming the vesting of all restricted stock rights.

The following table reconciles the weighted average common shares outstanding used in the calculations of basic and diluted income per share (in thousands):

All of the outstanding options to purchase shares of the Company’s common stock were included in the dilution calculation for the three months ended March 31, 2005, because the assumed exercise of each of the options was dilutive. Certain options to purchase shares of the Company’s common stock have been excluded from the dilution calculation for the three months ended March 31, 2004, because the assumed exercise of these options was anti-dilutive. These anti-dilutive options will dilute basic earnings per share in the future, if exercised, and may impact diluted earnings per share in the future depending on the market price of the Company’s common stock. The following information relates to the anti-dilutive options as of March 31, 2004:

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Comprehensive Income (Loss)

Comprehensive income (loss) consists of the following (in thousands):

The foreign currency translation adjustments shown previously relate entirely to the translation of the financial statements of the Company’s previously-owned Canadian subsidiary from its functional currency (the Canadian dollar) to the Company’s reporting currency (the U.S. dollar).

The changes in the value of derivative financial instruments, net of tax, consist of the following (in thousands):

The balance in accumulated other comprehensive income at both March 31, 2005, and December 31, 2004, relates entirely to changes in the value of derivative financial instruments.

Statements of Cash Flows

During the three months ended March 31, 2005 and 2004, the Company made cash payments for interest totaling approximately $0.4 million, and $2.4 million, respectively. The Company made cash payments for U.S. income taxes of $1.0 million in the three months ended March 31, 2005. The Company had no cash payments for U.S. income taxes in the three months ended March 31, 2004. The Company made cash payments for income taxes of $12.4 million and $9.0 million in Argentina during the first three months of 2005 and 2004, respectively.

Approximately $141.7 million of the Company’s cash at March 31, 2005, is related to the Company’s foreign operations and substantially all is held in U.S. banks.

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Long-term debt at March 31, 2005, and December 31, 2004, consisted of the following (in thousands):

In February 2004, the Company advanced funds under its revolving credit facility to redeem the entire $150 million principal balance of its 9 3/4% senior subordinated notes due 2009. As a result, the Company was required to expense certain associated deferred financing costs. This $2.6 million non-cash charge and a $7.3 million cash charge for the call premium resulted in a one-time charge of approximately $9.9 million ($6.0 million net of tax).

The Company had $18.0 million and $6.9 million of accrued interest payable related to its long-term debt at March 31, 2005, and December 31, 2004, included in “other payables and accrued liabilities” in the accompanying balance sheets.

In March 2004, the Company entered into a separation agreement with a former executive under which the Company extended the period in which the former executive may exercise each outstanding vested stock option granted to him under the Company’s 1990 Stock Plan to the end of the term of such option. Pursuant to the terms of the restricted stock award agreements for the shares of restricted stock granted to the Company’s former executive under the Company’s 1990 Stock Plan, such shares vested in full as of the date of his termination of employment. As a result, the Company recorded non-cash stock compensation expense of approximately $2.2 million in the first quarter of 2004.

The Company declared cash dividends of $0.05 and $0.045 per share for the three months ended March 31, 2005 and 2004, respectively.

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The Company had approximately $4.5 million in letters of credit outstanding at March 31, 2005. These letters of credit relate primarily to bonding requirements of various state regulatory agencies in the U.S. for oil and gas operations. The Company’s availability under its revolving credit facility is reduced by the outstanding letters of credit.

The Company has entered into certain firm gas transportation and compression agreements in Bolivia whereby the Company has committed to have a third party transport and compress certain volumes of the Company’s gas at established government-regulated fees. While these fees are not fixed, they are government-regulated and therefore, the Company believes the risk of significant fluctuations is minimal. The Company entered into these arrangements to ensure its access to gas markets and currently expects to produce sufficient volumes to utilize all of the contracted transportation and compression capacity under these arrangements. The Company paid $0.3 million and $0.7 million under these agreements in the three months ended March 31, 2005 and 2004, respectively. Based on the current fee level, these commitments total approximately $0.9 million for the remainder of 2005, $1.3 million in 2006 and $0.3 million in each of the years 2007, 2008 and 2009.

The Company has future minimum long-term electric power purchase commitments in Argentina of $2.7 million for the remainder of 2005, $3.6 million in 2006 and $4.9 million in 2007. The Company paid $0.8 million and $0.4 million for electric power purchases under these agreements in the three months ended March 31, 2005 and 2004, respectively.

The Company has also entered into “deliver-or-pay” arrangements where it has committed to deliver certain volumes of gas to third parties in Bolivia and Argentina for a specified period of time. These volumes will be sold at market prices. If the required volumes are not delivered, the Company must pay for the undelivered volumes at the then-current market price. Similar to the firm transportation and compression agreements, the Company entered into these arrangements to ensure its access to gas markets and the Company currently expects to produce sufficient volumes to satisfy all of its deliver-or-pay obligations. The volumes contracted under the agreement in Bolivia are 5.3 Bcf for the remainder of 2005, 7.0 Bcf in 2006, 6.0 Bcf in 2007, 6.9 Bcf in 2008 and 6.9 Bcf in 2009. The volumes contracted under the agreement in Argentina are 7.7 Bcf for the remainder of 2005, 5.3 Bcf in 2006, 3.6 Bcf in 2007 and 4.0 Bcf in 2008. The Company made no payments under these agreements in 2005 and 2004.

The Company periodically uses derivative financial instruments to reduce the impact of oil and gas price fluctuations on its operating results and cash flows and generally attempts to qualify such derivatives as hedges for accounting purposes. During the third and fourth quarter of 2004, a substantial portion of the Company’s derivative financial instruments ceased to qualify for hedge accounting due to significant oil price fluctuations. The Company continued to monitor the correlation between the changes in NYMEX crude oil index prices and the changes in U.S. crude oil postings and, as of March 1, 2005, the Company determined that the correlation indicates that its existing oil price swap agreements would again be highly effective in achieving offsetting changes in the cash flows of the physical transactions. Accordingly, the Company redesignated all of its oil price swap contracts as cash flow hedges and resumed hedge accounting for these contracts as of March 1, 2005. As of March 1, 2005, and through March 31, 2005, all of the Company’s derivative financial instruments qualified as hedges for accounting purposes.

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During the first quarter of 2004, the Company participated in oil price swap agreements covering 1.4 million barrels of its oil production at a weighted average NYMEX reference price of $29.77 per barrel. During the first quarter of 2005, the Company participated in oil price swap agreements covering 1.2 million barrels of its oil production at a weighted average NYMEX reference price of $37.77 per barrel, gas price swap agreements covering 1.2 million MMBtu of its gas production at a weighted average NYMEX reference price of $6.65 per MMBtu and gas price collar agreements covering 2.7 million MMBtu of its gas production with NYMEX floor reference prices of $6.00 per MMBtu and NYMEX cap reference prices ranging from $6.80 to $9.21 per MMBtu. In conjunction with each of the 2005 U.S. gas price swap and collar agreements, the Company entered into basis swap agreements covering identical periods of time and volumes. These basis swaps establish a differential between the NYMEX reference price and the various delivery points at levels that are comparable to the historical differentials received by the Company.

The Company has not entered into any new oil or gas price swap agreements or collars since December 31, 2004. The Company continues to monitor oil and gas prices and may enter into additional derivative transactions in the future.

The Company records the fair value of its commodity swap agreements as a current or long-term asset or liability based on the period in which the forecasted transaction will occur. The fair value of the derivative financial instrument obligation at March 31, 2005, consisted of a current liability of $96.3 million and an other long-term liability of $29.6 million.

A reconciliation of the U.S. federal statutory income tax rate to the effective tax rate for continuing operations is as follows:

The impact of foreign operations is primarily the result of lower tax depreciation, depletion and amortization in Argentina due to the inability to utilize inflation accounting for tax purposes. Earnings of the Company’s foreign subsidiaries are subject to foreign income taxes. No U.S. deferred tax liability will be recognized related to the unremitted earnings of these foreign subsidiaries, as it is the Company’s intention, generally, to reinvest such earnings permanently. At December 31, 2004, income considered to be permanently reinvested in certain foreign subsidiaries totaled approximately $425 million. The Company has paid or accrued foreign income taxes of approximately $230 million related to this income which may be available as a credit against U.S. federal income taxes on such income, if distributed. It is not practicable to estimate the amount of additional tax that might be payable on this foreign income if distributed because the amount of foreign taxes eligible for credit against U.S. federal income taxes on any such distribution will be determined based on facts and circumstances at the time of any actual distribution.

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During the three months ended March 31, 2005, the Company reversed approximately $13.1 million of contingent liabilities related to U.S. federal and state income taxes. These contingent tax liabilities related to tax benefits resulting from certain filing positions taken for which the Company initially concluded, for financial reporting purposes, that, under GAAP, it was appropriate to recognize these benefits until the filing positions taken were sustained under a tax audit. During the first quarter of 2005, federal and state auditors completed audits of the Company’s tax returns for the periods involved, with no adjustments related to these filing positions required. Therefore, the Company concluded that it was now appropriate to recognize these tax benefits for financial reporting purposes. Approximately $10.7 million of these tax benefits related to previously-discontinued operations and are reflected as “income from discontinued operations” in the accompanying consolidated statement of operations for the three months ended March 31, 2005. The remaining $2.4 million is included in the continuing operations “deferred tax benefit” in the accompanying consolidated statement of operations for the three months ended March 31, 2005.

The American Jobs Creation Act of 2004 (the “Jobs Act”) introduced a special one-time dividends-received deduction on the repatriation of certain foreign earnings to the U.S., provided certain conditions are met. If certain conditions are met, a 5.25 percent effective income tax rate would apply to eligible repatriations of certain foreign earnings. The Company is currently evaluating these provisions under the Jobs Act and is also awaiting interpretive guidance relating to these regulations from either Congress or the Treasury Department. At the current date, the Company has not determined that it will repatriate any unremitted foreign earnings under the special one-time repatriation provisions of the Jobs Act. However, the Company continues to evaluate the special one-time repatriation provisions of the Jobs Act and that evaluation could result in the Company repatriating certain unremitted foreign earnings. The amount of unremitted foreign earnings that the Company is evaluating for repatriation, including projected 2005 earnings, ranges from zero to $500 million. The Company expects to complete its evaluation of the amount of repatriation, if any, during 2005. If the Company was to repatriate certain unremitted foreign earnings under the special one-time repatriation provisions of the Jobs Act in the range noted in the preceding sentence, the income tax effects of such repatriation could range from zero to approximately $26 million.

On November 30, 2004, the Company completed the sale of its operations in Canada. The Company received $274.7 million in cash and recorded a gain of approximately $167.8 million ($198.5 million including income tax benefit).

In accordance with the rules established by Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Company’s operations in Canada are accounted for as discontinued operations in the accompanying consolidated financial statements.

Following is summarized financial information for the Company’s operations in Canada for the three months ended March 31, 2004, (in thousands):

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As discussed in Note 7, in the three months ended March 31, 2005, the Company reversed approximately $10.7 million of contingent U.S. federal and state income tax liabilities related to its previously-discontinued operations in Trinidad.

The Company applies Statement of Financial Accounting Standards No. 131, Disclosures About Segments of an Enterprise and Related Information. The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the exploration and production segment are derived from the production and sale of crude oil, condensate, natural gas liquids and natural gas. The gas marketing segment generates a margin through the purchase and resale of both Company-produced and third party-produced gas volumes. The Company evaluates the performance of its operating segments based on operating income.

Intersegment sales are priced in accordance with terms of existing contracts and current market conditions. Capital investments include expensed exploratory costs. Amounts below the “operating income” line on the statements of operations are not allocated to segments. General and administrative expense and stock compensation are included in the corporate segment, except for certain operating expenses related to oil and gas producing activities, which are allocated to each exploration and production segment.

Operations in the gas marketing segment are in the U.S. The Company operates in the oil and gas exploration and production industry in the U.S., Argentina, Bolivia, Yemen and Bulgaria. The financial information related to the Company’s discontinued operations in Canada has been excluded in all periods presented (see Note 8). Summarized financial information for the Company’s reportable segments for the three months ended March 31, 2005 and 2004, is shown in the following tables (in thousands):