VINTAGE PETROLEUM INC - 10-Q Quarterly Report

(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.

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 and limited partner interests in various joint ventures (collectively, the “Company”). Management believes that all material adjustments (consisting of only normal recurring adjustments) necessary for a fair presentation have been made. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain 2002 amounts have been reclassified to conform with the 2003 presentation, including reclassifications required for presentation of the discontinued operations discussed in Note 9. These reclassifications had no effect on the Company’s net income (loss) or stockholders’ equity.

As required by the implementation rules of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”), the Company restated its results of operations and cash flows for the three months ended March 31, 2002. See Note 5.

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 and 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 2002 audited financial statements and related notes included in the Company’s 2002 Annual Report on Form 10-K, “Item 8. Financial Statements and Supplementary Data”.

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 is 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, are expensed as incurred. The Company recognizes gains or losses on the sale of properties on a field basis.

Unproved leasehold costs are capitalized and reviewed periodically for impairment. Individual unproved properties whose acquisition costs are significant are assessed 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 exploration expense. Further impairment expense could result if oil and gas prices decline in the future or if downward reserve revisions are recorded, as it may not be economic to develop some of these unproved properties.

As of March 31, 2003, the Company had total unproved oil and gas property costs of approximately $88.9 million, consisting of undeveloped leasehold costs of $74.3 million, including $61.0 million in Canada, and unproved exploratory drilling costs of $14.6 million. Approximately $19.3 million of the total unproved costs are associated with the Company’s drilling program in Yemen and approximately $21.8 million of the total unproved costs are associated with undeveloped leaseholds in the Northwest Territories in Canada. Future exploration expense and earnings may be impacted to the extent that the Company’s future exploration activities are unsuccessful in discovering commercial oil and gas reserves in sufficient quantities to recover its costs.

Costs of development dry holes and proved leaseholds are amortized on the unit-of-production method based on 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.

In August 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). The Company was required to adopt this new standard beginning January 1, 2003. Through December 31, 2002, the Company accrued an estimate of future abandonment costs of wells and related facilities through its depreciation calculation and included the cumulative accrual in accumulated depreciation in accordance with the provisions of Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and industry practice. At December 31, 2002, approximately $54.6 million of accrued future abandonment costs were included in accumulated depreciation. The new standard requires that the Company record the discounted fair value of the retirement obligation as a liability at the time a well is drilled or acquired. 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 were 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. The liability accretes over time with a charge to accretion expense. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The Company adopted the new standard effective January 1, 2003, and recorded an increase in property, plant and equipment of approximately $50.3 million, a net decrease in accumulated depreciation, depletion and amortization of approximately $43.9 million, an increase in current asset retirement liabilities of approximately $4.5 million, an increase in long-term asset retirement liabilities of approximately $78.5 million, an increase in deferred tax liabilities of approximately $4.1 million and a non-cash gain as a result of the cumulative effect of change in accounting principle, net of tax, of approximately $7.1 million.

Subsequent to the implementation of SFAS No. 143, the Company recorded the following activity related to the liability (in thousands):

Of the liability for asset retirement obligations balance at March 31, 2003, approximately $4.5 million is classified as current and included in “Other payables and accrued liabilities” in the accompanying balance sheets.

Had the provisions of SFAS No. 143 been applied in the three months ended March 31, 2002, the liability for asset retirement obligations would have been $78.2 million at January 1, 2002, and $79.9 at March 31, 2002, and the Company’s net income and earnings per share would have been as follows (in thousands, except per share amounts):

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. The Company recorded no impairment provisions related to its proved oil and gas properties during the first quarter of 2003 or the first quarter of 2002.

In estimating the future net revenues at March 31, 2003, to be used for impairment testing, the Company assumed that current oil prices would return to more historical levels over a short period of time and that current gas prices would remain at the levels experienced in recent years. The Company assumed that operating costs would escalate annually beginning at current levels. Due to the volatility of oil and gas prices, it is possible that the Company’s assumptions regarding oil and gas prices may change in the future and may result in future impairment provisions.

On January 1, 2002, the Company adopted the provisions of Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS No. 144”). SFAS No. 144 creates accounting and reporting standards to establish a single accounting model, based on the framework established in Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, for long-lived assets to be disposed of by sale. The adoption of SFAS No. 144 did not have a material impact on the Company’s financial position or results of operations. See further discussion of discontinued operations in Note 9.

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the purchase of Genesis Exploration Ltd. (“Genesis”) in May 2001. On July 20, 2001, the FASB issued Statement of Financial Accounting Standards No. 141, Business Combinations (“SFAS No. 141”), and SFAS No. 142. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method of accounting. Under SFAS No. 142, goodwill is no longer subject to amortization. Rather, goodwill will be subject to at least an annual assessment for impairment by applying a fair-value based test. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

The Company’s acquisition of Genesis was accounted for using the purchase method of accounting. The Company adopted SFAS No. 141 and SFAS No. 142 effective January 1, 2002, resulting in the elimination of goodwill amortization from statements of operations in future periods. Upon adoption, the Company recorded an impairment charge of $60.5 million related to the goodwill of its Canadian operations as a cumulative effect of a change in accounting principle in its statement of operations (see Note 5). The Company will assess the Canadian operation’s goodwill as of December 31 each year and will perform interim tests for goodwill impairment should an event occur or circumstances change that would, more likely than not, indicate a possible goodwill impairment. On December 31, 2002, the Company recorded an additional impairment charge of $76.4 million as an operating expense resulting from its annual assessment. No impairment charges related to goodwill were recorded in the first quarter of 2003.

The Company periodically uses hedges to reduce the impact of oil and natural gas price fluctuations. 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 No. 133”). SFAS No. 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. SFAS No. 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.

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 present value of the expected cash flows of the item being hedged. To the extent the cumulative change in the derivative exceeds the cumulative change in the present value of expected cash flows, the excess, if any, is recognized currently in earnings. If the cumulative change in present value of the expected cash flows exceeds the change in fair value of the derivative, the difference is ignored. Changes in the fair value of derivative financial instruments that do not qualify for accounting treatment as hedges, if any, are recognized currently as “Other income (expense).” The cash flows from such agreements are included in operating activities in the consolidated statements of cash flows.

During the three months ended March 31, 2003 and 2002, the Company made cash payments for interest totaling $6.7 million and $8.6 million, respectively. Cash payments for U.S. income taxes of $5.4 million and $6.2 million were made during the first three months of 2003 and 2002, respectively. The Company made cash payments for foreign income taxes of $3.7 million, primarily in Argentina, during the first three months of 2003 and $1.6 million, primarily in Canada, during the first three months of 2002.

Basic income (loss) per common share was computed by dividing net income (loss) by the weighted average number of shares outstanding during the period. Diluted income per common share for the first three months of 2003 was computed assuming the exercise of all dilutive options, as determined by applying the treasury stock method. For the first three months of 2002, the assumed exercise for all options would have been anti-dilutive because the Company had a net loss for the period. Therefore, the amounts reported for basic and diluted loss per share were the same. Had the Company been in a net income position for this period, the Company’s diluted weighted average outstanding common shares would have been 63,532,680.

For the three month period ended March 31, 2003 and 2002, the Company had outstanding stock options for 1,125,400 and 3,138,850 additional shares of the Company’s common stock, respectively, with average exercise prices of $14.93 and $19.16, respectively, which were anti-dilutive. These shares 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 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 $1.2 million and $1.3 million for the first quarter of 2003 and 2002, respectively.

On February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002, which is reflected in lease operating expenses. The tax is limited by law to a term of no more than five years. The 20 percent tax is applied on the sales value after the tax, thus the net effect is 16.7 percent.

Foreign currency transactions and financial statements are translated in accordance with Statement of Financial Accounting Standards No. 52, Foreign Currency Translation. All of the Company’s subsidiaries use the U.S. dollar as their functional currency, except for the Company’s Canadian operating subsidiary, which uses the Canadian dollar. Adjustments arising from translation of the Canadian operating subsidiary’s financial statements are reflected in other comprehensive income (loss). Transaction gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the Company’s or its subsidiaries’ functional currency are included in the results of operations as incurred.

International investments represent, and are expected to continue to represent, a significant portion of the Company’s business. For the first three months of 2003, the Company’s operations in Argentina represented approximately 34 percent and 55 percent of the Company’s total revenues and operating income, respectively, and as of March 31, 2003, represented approximately 27 percent of the Company’s total assets.

Beginning in 1991, the Argentine peso (“peso”) was tied to the U.S. dollar at a rate of one peso to one U.S. dollar. As a result of economic instability and substantial withdrawals from the banking system, in early December 2001, the Argentine government instituted restrictions that prohibit foreign money transfers without Central Bank approval and limit cash withdrawals from bank accounts to personal transactions in small amounts with certain limited exceptions. While the legal exchange rate remained at one peso to one U.S. dollar, financial institutions were allowed to conduct only limited activity due to these controls, and currency exchange activity was effectively halted except for personal transactions in small amounts. These actions by the government in effect caused a devaluation of the peso in December 2001.

On January 6, 2002, the Argentine government abolished the one peso to one U.S. dollar legal exchange rate. On January 9, 2002, Decree 71 created a dual exchange market whereby foreign trade transactions were conducted at an official exchange rate of 1.4 pesos to one U.S. dollar and other transactions were conducted in a free floating exchange market. On February 8, 2002, Decree 260 unified the dual exchange markets and allowed the peso to float freely with the U.S. dollar. The exchange rate at March 31, 2003, was 2.98 pesos to one U.S. dollar as compared to 3.38 pesos to one U.S. dollar at December 31, 2002.

On February 3, 2002, Decree 214 required certain contracts that were previously payable in U.S. dollars to be payable in pesos. Pursuant to an emergency law passed on January 10, 2002, U.S. dollar obligations between private parties due after January 6, 2002, were to be liquidated in pesos at a negotiated rate of exchange which reflects a sharing of the impact of the devaluation. The Company’s settlements in pesos of the existing U.S. dollar-denominated agreements have been completed, thus future periods will not be impacted by this mandate. This government-mandated “equitable sharing” of the impact of the devaluation resulted in a reduction in oil revenues from domestic sales in Argentina for the first three months of 2002 of approximately $8 million, or $2.67 per Argentine barrel produced, $1.51 per total continuing operations barrel produced or $1.44 per total Company barrel produced. The reduction of the Company’s Argentine lease operating costs, which were also reduced as a result of this mandate and the positive impact of devaluation on the Company’s peso-denominated costs, essentially offset the negative impact on Argentine oil revenues.

Absent the January 10, 2002, emergency law, the devaluation of the peso would have had no effect on the U.S. dollar-denominated payables and receivables at December 31, 2001. A $0.9 million gain resulting from the involuntary conversion was recorded in January 2002. The translation of peso-denominated balances at March 31, 2003, and peso-denominated transactions during the three months ended March 31, 2003, resulted in a foreign currency exchange loss of $4.1 million.

The Company has evaluated the effect of the economic and political events in Argentina. Despite these changes, the Company believes that the facts and circumstances indicate that the U.S. dollar remains the functional currency of its Argentine operations.

The Company has two fixed stock-based compensation plans which reserve shares of common stock for issuance to key employees and directors. The Company accounts for these plans under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”) and has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”). Accordingly, no compensation cost for stock options granted 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.

On December 31, 2002, the FASB issued Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure (“SFAS No. 148”). SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition to SFAS No. 123’s fair value method of accounting for stock-based employee compensation. The Company is considering the adoption of SFAS No. 123’s fair value method of accounting for stock-based employee compensation in 2003, but has not yet made a final determination.

Had compensation cost for these plans been determined consistent with the provisions of SFAS No. 123, the Company’s stock-based compensation expense, net income (loss) and income (loss) per share would have been adjusted to the following pro forma amounts (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 weighted average assumptions used for options granted in 2003 include a dividend yield of 1.5 percent, expected volatility of approximately 46.4 percent, a risk-free interest rate of approximately 3.0 percent and expected lives of 4.5 years. The weighted average assumptions used for options granted in 2002 include a dividend yield of 1.4 percent, expected volatility of approximately 50.3 percent, a risk-free interest rate of approximately 4.4 percent and expected lives of 4.5 years.

The foreign currency translation adjustments shown above relate entirely to the translation of the financial statements of the Company’s Canadian operating subsidiary from its functional currency, the Canadian dollar, to the Company’s reporting currency, the U.S. dollar.

The changes in the value of derivatives, net of tax, consist of the following (in thousands):

The accumulated balance for each item in accumulated other comprehensive income (loss) is as follows (in thousands):

Long-term debt at March 31, 2003, and December 31, 2002, consisted of the following (in thousands):

During the first quarter of 2003, the Company advanced funds under the revolving credit facility to redeem the remainder of the 9% Notes due 2005. As a result, the Company was required to expense certain associated deferred financing costs and discounts. This $0.7 million non-cash charge and a $0.7 million cash charge for the call premium on the redemption of the remaining 9% Notes resulted in a one-time charge of approximately $1.4 million ($0.9 million net of tax). Subsequently, a portion of the proceeds from the January 2003 sale of the Company’s operations in Ecuador was used to repay the entire outstanding balance under the revolving credit facility. As a result, the unused availability under the revolving credit facility at March 31, 2003, was $290.2 million, considering outstanding letters of credit of $9.8 million.

All of the Company’s remaining outstanding debt matures in 2009 or later. The Company had $23.6 million and $11.7 million of accrued interest payable related to its long-term debt at March 31, 2003, and December 31, 2002, respectively, included in “Other payables and accrued liabilities” in the accompanying balance sheets.

On February 20, 2003, pursuant to the terms of an offer to exchange, the Company accepted for exchange options to purchase 2,118,000 shares of its common stock, representing approximately 95.1% of the 2,227,500 options that were eligible to be tendered in the offer. The options exchanged had exercise prices ranging from $19.28 to $21.81 per share. In accordance with the terms of the offer to exchange, the Company granted restricted stock and restricted stock rights representing an aggregate of 562,840 shares of its common stock in exchange for the tendered options. Restricted stock award compensation expense of approximately $5.5 million (based on the stock price on the date of grant) will be amortized over the vesting periods.

The Company declared cash dividends of $.04 and $0.035 per share for the three months ended March 31, 2003 and 2002, respectively.

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the purchase of Genesis. All of the Company’s goodwill is related to the Company’s Canadian operations, which is consistent with the Canadian segment identified in Note 10. Effective January 1, 2002, the Company adopted the provisions of SFAS No. 142. SFAS No. 142 changed the accounting for goodwill from an amortization method to an impairment assessment only method.

Under the new rule, the Company had a six-month transitional period from the effective date of the adoption to perform an initial assessment of whether there was an indication that the carrying value of goodwill was impaired. This assessment was made by comparing the fair value of the Canadian operations, as determined in accordance with SFAS No. 142, to its book value. If the fair value was less than the book value, an impairment was indicated and the Company would be required to perform a second test no later than December 31, 2002, to measure the amount of the impairment. Any initial impairment was to be taken as a cumulative effect of change in accounting principle retroactive to January 1, 2002. In future years, this assessment must be conducted at least annually and any such impairment must be recorded as a charge to operating earnings.

The Company completed its initial assessment in the second quarter of 2002 and recorded a non-cash charge of $60.5 million. Decreases in oil and gas price expectations from the May 2, 2001, acquisition of Genesis to January 1, 2002, and certain downward revisions recorded to the Company’s Canadian oil and gas reserves at December 31, 2001, were the primary factors that led to the goodwill impairment. The charge was recorded as a cumulative effect of change in accounting principle retroactive to January 1, 2002, in accordance with the provisions of SFAS No. 142. The Company performed another assessment of goodwill impairment as of December 31, 2002, and recorded an additional non-cash charge of $76.4 million as an operating expense. Certain downward revisions recorded to the Company’s Canadian oil and gas reserves in the fourth quarter of 2002 were the primary factor which led to the additional impairment.

The Company engaged an independent appraisal firm to determine the fair value of the Canadian operations as of January 1, 2002, and December 31, 2002. These fair value determinations were made principally on the basis of present value of future after tax cash flows, although other valuation methods were considered. The book value of the Canadian operations exceeded the fair value determined by the independent appraisal firm, indicating a possible impairment of goodwill. The Company then calculated the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the Canadian operations from the fair value of the Canadian operations determined in step one of the assessment. The carrying value of the goodwill exceeded this calculated implied fair value of the goodwill at January 1, 2002, and at December 31, 2002, resulting in the impairment charges.

The Company has no intangible assets other than the goodwill of its Canadian operations. This goodwill had a net book value of $22.7 million as of March 31, 2003. The changes in the carrying amount of goodwill for the three months ended March 31, 2003 and 2002, are as follows (in thousands):

As noted above, SFAS No. 142 required that the cumulative effect of change in accounting principle be recorded retroactive to January 1, 2002. The following table reflects the impact of this accounting change on selected financial data for the three months ended March 31, 2002 (in thousands, except per share data):

The Company is committed to perform a certain number of work units in the Chaco concession in Bolivia that it expects to complete by performing exploration work in 2003 at an estimated cost of $1.1 million.

The Company had approximately $9.8 million in letters of credit outstanding at March 31, 2003. These letters of credit relate primarily to various obligations for exploration activities in Canada and South America and 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 transport and compress certain volumes of 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. Based on the current fee level, these commitments total approximately $2.1 million for the remainder of 2003, $1.4 million in 2004, $0.3 million in 2005, $0.3 million in 2006, $0.3 million in 2007 and $0.6 million thereafter.

Beginning in April 2003, the Company has future minimum long-term electric power purchase commitments in Argentina of $0.9 million, $3.6 million, $3.6 million and $7.6 million for the years 2003 through 2006, respectively.

The Company periodically uses hedges to reduce the impact of oil and natural gas price fluctuations on its operating results and cash flows. The Company participated in oil hedges covering approximately 1.2 million barrels and gas hedges covering approximately 5.0 million MMBtu (millions of British thermal units) in the first three months of 2003. The impact of the oil hedges decreased its U.S. average oil price by $4.94 to $26.56 per barrel, its Canada average oil price by $0.26 to $30.88 per barrel, its average oil price from continuing operations by $1.74 to $28.20 per barrel and its overall average oil price by $1.70 to $28.17 per barrel. The impact of the gas hedges decreased its U.S. average gas price by $0.94 to $4.83 per Mcf (thousand cubic feet), decreased its Canada average gas price by $0.75 to $4.58 per Mcf and decreased its overall average gas price by $0.66 to $3.88 per Mcf.

At March 31, 2003, the Company was a party to oil price swap agreements for various periods of the remainder of 2003 covering approximately 3.0 million barrels at a weighted average NYMEX reference price of $25.83 per barrel and gas price swap agreements for various periods of the remainder of 2003 covering approximately 15.1 million MMBtu. The Canadian portion of the gas swap agreements, approximately 6.9 million MMBtu, is at a weighted average NYMEX reference price of 6.48 Canadian dollars per MMBtu. The U.S. portion of the gas swap agreements, approximately 8.2 million MMBtu, is at a weighted average NYMEX reference price of $3.93 per MMBtu. Additionally, the Company has entered into basis swap agreements for the approximately 6.3 million MMBtu of its U.S. gas production covered by the gas swap agreements. 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. At March 31, 2003, the Company had a derivative financial instrument payable of $24.0 million related to cash flow hedges in place related to anticipated 2003 production. The Company did not discontinue any hedges because of the probability that the original forecasted transaction would not occur. The Company continues to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future.

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

The impact of foreign operations for the first quarter of 2002 is primarily the result of the Company’s Canadian operations, which are benefitted at a higher tax rate than in the U.S., partially offset by the net tax impact of the peso devaluation in Argentina.

The impact of foreign operations for the first quarter of 2003 is primarily the effect of the peso devaluation in Argentina on the Company’s tax balance sheet due to the inability, to date, to utilize inflation accounting for fixed assets and the unfavorable tax impact on U.S. dollar liabilities due to the strengthening of the Argentine peso in the first quarter 2003.

On July 30, 2002, the Company completed the sale of its operations in Trinidad. The Company received $40 million in cash and recorded a gain of approximately $31.9 million ($14.9 million after income taxes). On January 31, 2003, the Company completed the sale of its operations in Ecuador. The Company received $137.4 million in cash and recorded a gain of approximately $47.3 million ($9.5 million after income taxes), subject to post-closing adjustments.

In accordance with the rules established by SFAS No. 144, the Company’s operations in Trinidad and Ecuador, along with the gain on the sale of the operations in Ecuador, are accounted for as discontinued operations in the accompanying consolidated financial statements.

Following is summarized financial information for the Company’s Trinidad operations (in thousands):

Following is summarized financial information for the Company’s operations in Ecuador (in thousands):

The income tax expense related to the gain on the sale of operations in Ecuador includes $19.4 million of taxes on previously unremitted foreign earnings. As it is the Company’s intention, generally, to reinvest foreign earnings permanently, no U.S. income taxes were previously recorded on these earnings. In accordance with SFAS No. 144, the assets of the Company’s operations in Ecuador were reclassified as “Assets of discontinued operations” and the liabilities were reclassified as “Liabilities of discontinued operations” in the accompanying consolidated balance sheet as of December 31, 2002.

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 natural gas and crude oil. Revenues for the gathering/plant segment arise from the processing, transportation and sale of natural gas and crude oil. The gas marketing segment generates revenue by earning fees through the marketing of Company-produced gas volumes and the purchase and resale of third party-produced gas volumes. The Company evaluates the performance of its operating segments based on segment operating income.

Operations in the gathering/plant and gas marketing segments are in the United States. The Company operates in the oil and gas exploration and production industry in the United States, Canada, South America, Yemen and Italy. The financial information related to the Company’s discontinued operations in Trinidad and Ecuador has been excluded in all periods presented (see Note 9), except for total assets at the end of each period. Summarized financial information for the Company’s reportable segments for the three month period ended March 31, 2003 and 2002, is shown in the following tables (in thousands):

Intersegment sales are priced in accordance with terms of existing contracts and current market conditions. Capital investments include expensed exploratory costs. Long-lived assets include property, plant and equipment and goodwill. Corporate general and administrative costs and interest costs, including the loss on early extinguishment of debt, are not allocated to segments.

The Company’s results of operations have been significantly affected by its success in acquiring oil and gas properties and its ability to maintain or increase production through its exploitation and exploration activities. Significant dispositions of producing oil and gas properties during 2002 and 2003 affect the comparability of operating data for the periods presented in the tables below. Fluctuations in oil and gas prices and substantially curtailed capital expenditures in 2002 have also significantly affected the Company’s results. The following table reflects the Company’s oil and gas production and its average oil and gas sales prices for the periods presented:

Average U.S. and Canadian oil prices received by the Company fluctuate generally with changes in the NYMEX reference price for oil. The Company’s oil production in Argentina is sold at West Texas Intermediate spot prices as quoted on the Platt’s Crude Oil Marketwire (approximately equal to the NYMEX reference price) less a specified differential. During the first three months of 2003, the Company experienced a 74 percent increase in its average oil price, including the impact of hedging activities (86 percent increase excluding hedging activities), compared to the same period in 2002. The Company’s realized average oil price for the first three months of 2003 before hedges increased to 88 percent of the NYMEX reference price compared to 74 percent for the same period in 2002. This increase in realizations is primarily a result of the impact on 2002 of the one-time government-mandated forced settlement of domestic Argentine oil sales and the sale of the Company’s heavy oil assets in June 2002. These heavy oil assets generally realized lower prices relative to NYMEX than the Company’s other oil production.

As discussed in Note 1 to the Company’s consolidated financial statements included elsewhere in this Form 10-Q, the Argentine government took actions which in effect caused the devaluation of the peso in early December 2001 and, in January 2002, enacted an emergency law that required certain contracts that were previously payable in U.S. dollars to be payable in pesos. Subsequently, on February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002. The tax of 20 percent is applied on the sales value after the tax, thus the net effect is 16.7 percent and is included in lease operating expenses in the Company’s statement of operations. The tax is limited by law to a term of no more than five years. For additional information, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency and Operations Risk” included elsewhere in this Form 10-Q. Domestic Argentine oil sales, while valued in U.S. dollars, are now being paid in pesos. Export oil sales continue to be valued and paid in U.S. dollars.

The Company currently exports approximately 70 percent of its Argentine oil production. The Company believes that this export tax has continued to have the effect of decreasing all future Argentine oil revenues, not only export revenues, by the tax rate for the duration of the tax. The U.S. dollar equivalent value for domestic Argentine oil sales, now paid in pesos, has generally moved to parity with the U.S. dollar-denominated export values, net of the export tax. The adverse impact of this tax will be partially offset by the net cost savings from the devaluation of the peso on peso-denominated costs and will be further reduced by the Argentine income tax savings related to deducting the impact of the export tax. The export tax is not deducted in the calculation of royalty payments.

During both the first three months of 2003 and 2002, the Company participated in oil hedges covering approximately 1.2 MMBbls in each quarter. The impacts of these oil hedges on the Company’s average oil prices are reflected in the preceding tables.

Average U.S. gas prices received by the Company fluctuate generally with changes in spot market prices, which may vary significantly by region. The Company’s gas in Canada is generally sold at spot market prices as reflected by the AECO gas price index. Most of the Company’s Bolivian gas production is sold at average prices tied to a long-term contract under which the base price is adjusted for changes in specified fuel oil indexes. The Company’s Argentine gas is sold under spot contracts of varying lengths, which, as a result of the emergency law enacted in January 2002, are now paid in pesos. This has initially resulted in a decrease in sales revenue value when converted to U.S. dollars due to the devaluation of the peso and current market conditions. This value may improve over time as domestic Argentine gas drilling declines and market conditions improve. The Company’s total average gas price for the first three months of 2003, including the impact of hedging activities, was 99 percent higher (133 percent higher excluding hedging activities) than the same period of 2002.

The Company participated in gas hedges covering approximately 5.0 million MMBtu during the first three months of 2003. The Company did not participate in any gas hedges in the first three months of 2002.

The Company has previously engaged in oil and gas hedging activities and intends to continue to consider various hedging arrangements to realize commodity prices which it considers favorable. As of March 31, 2003, the Company has entered into various oil price swap agreements for various periods of the remainder of 2003 covering approximately 3.0 million barrels at a weighted average NYMEX reference price of $25.83 per barrel and gas price swap agreements for various periods of the remainder of 2003 covering approximately 15.1 million MMBtu. The Canadian portion of the gas swap agreements, approximately 6.9 million MMBtu, is at a weighted average NYMEX reference price of 6.48 Canadian dollars per MMBtu and will be settled in Canadian dollars. The U.S. portion of the gas swap agreements, approximately 8.2 million MMBtu, is at an average NYMEX reference price of $3.93 per MMBtu. Additionally, the Company has entered into basis swap agreements for the approximately 6.3 million MMBtu of its U.S. gas production covered by the gas swap agreements. 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 counterparties to the Company’s current hedging agreements are commercial or investment banks. The Company continues to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future.

Relatively modest changes in either oil or gas prices significantly impact the Company’s results of operations and cash flow. However, the impact of changes in the market prices for oil and gas on the Company’s average realized prices may be reduced from time to time based on the level of the Company’s hedging activities. Based on the oil production from continuing operations for the first three months of 2003, a change in the average oil price realized, before hedges, by the Company of $1.00 per Bbl would result in a change in net income and cash flow before income taxes on an annual basis of approximately $12.4 million and $19.6 million, respectively. A 10 cent per Mcf change in the average price realized, before hedges, by the Company would result in a change in net income and cash flow before income taxes on an annual basis of approximately $3.8 million and $6.1 million, respectively, based on gas production for the first three months of 2003.

The period to period comparisons presented below are significantly affected by dispositions made by the Company during the periods. On July 30, 2002, the Company completed the sale of its operations in Trinidad. The Company received $40 million in cash and recorded a gain of approximately $31.9 million ($14.9 million after income taxes). On January 31, 2003, the Company completed the sale of its operations in Ecuador. The Company received $137.4 million in cash and recorded a gain of approximately $47.3 million ($9.5 million after income taxes), subject to post-closing adjustments. 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 Trinidad and Ecuador, along with the gains on the sales, are accounted for as discontinued operations in the Company’s consolidated financial statements. Accordingly, the revenues and operating expenses discussed below exclude the results related to the Company’s operations in Ecuador and Trinidad for all periods.

Three months ended March 31, 2003, compared to three months ended March 31, 2002

The Company reported net income of $40.7 million for the quarter ended March 31, 2003, compared to a net loss of $66.2 million for the same period in 2002. Net income for the first quarter of 2003 included income from discontinued operations of $10.8 million ($49.1 million before tax) related primarily to the gain on the sale of the Company’s operations in Ecuador. Also included was a non-cash gain of $7.1 million ($11.2 million before tax) related to the cumulative effect of a mandated change in accounting principle regarding asset retirement obligations. Included in the net loss for the first quarter of 2002 was a non-cash charge for $60.5 million reflected as a cumulative effect of change in accounting principle resulting from the mandated adoption of SFAS 142 which requires impairment assessments of goodwill. Income from continuing operations before cumulative effect of changes in accounting principles for the first quarter of 2003 was $22.7 million, compared to a loss of $6.3 million for the first quarter of 2002. A significantly higher oil and gas price environment was the primary reason for the increase.

Oil and gas sales increased $67.2 million (57 percent), to $185.7 million for the first quarter of 2003 from $118.5 million for the first quarter of 2002. Oil revenues increased by $40.2 million (47 percent), primarily as a result of a 74 percent increase in average oil prices, which more than offset a 16 percent decrease in oil production from continuing operations. Similarly, gas revenues increased by $27.0 million (83 percent) primarily as a result of a 99 percent increase in average gas prices, which more than offset an eight percent decrease in gas production. Production from continuing operations on an equivalent barrel basis decreased 13 percent resulting from natural production declines compounded by the effects of substantially curtailed capital expenditures in 2002 and the Company’s property divestitures made in the United States. Capital expenditures in 2002 were limited to $129.7 million, or approximately 54 percent of cash flow provided by operating activities, as a result of the Company’s decision to use a portion of cash flow to execute its debt reduction program during 2002 and to restrict the level of expenditures in Argentina pending stabilization of the economic and political environment.

Revenues and expenses for gas marketing increased significantly from the first quarter of 2002 to the first quarter of 2003 primarily due to an increase in U.S. gas prices.

As discussed in Note 2 to the Company’s consolidated financial statements included elsewhere in this Form 10-Q, the Argentine government took actions which, in effect, caused the devaluation of the peso in early December 2001. The translation of peso-denominated balances at March 31, 2002, and peso-denominated transactions during the three months ended March 31, 2002, resulted in a foreign currency exchange gain of $2.9 million on the statement of operations. The Company also recorded a gain of $0.9 million in “Other income (expense)” for the first quarter of 2002 related to the Argentine government-mandated negotiated settlement of U.S. dollar-denominated receivables and payables in existence at January 6, 2002. The translation of peso-denominated balances at March 31, 2003, and peso-denominated transactions for the quarter ended March 31, 2003, resulted in a foreign currency exchange loss of $4.1 million. This loss was caused by the strengthening of the Argentine peso from a rate of 3.38 pesos to one U.S. dollar at December 31, 2002, to a rate of 2.98 pesos to one U.S. dollar at March 31, 2003. This loss was partially offset by a $0.5 million gain resulting from certain transactions of the Company’s Canadian operations that are denominated in U.S. dollars.

Lease operating expenses, including production and export taxes, increased $7.3 million (16 percent), to $54.2 million for the first quarter of 2003 from $46.9 million for the first quarter of 2002. On an equivalent barrel basis, lease operating expenses increased 33 percent from $5.80 for the first quarter of 2002 to $7.71 for the first quarter of 2003. The tax imposed on Argentine oil exports at the end of the first quarter of 2002 was the primary factor that caused the change, increasing lease operating expenses by $9.7 million ($1.38 per equivalent barrel) from the first quarter of 2002 to the first quarter of 2003. Before the impact of the Argentina export tax, lease operating expenses decreased by $2.4 million (five percent) from the first quarter of 2002 to the first quarter of 2003, primarily as a result of the non-strategic asset sales in the U.S. in 2002. Lease operating expenses per equivalent barrel, before the impact of the Argentina export tax, increased by nine percent from $5.73 for the first quarter of 2002 to $6.26 for the first quarter of 2003. This increase was the result of a combination of the negative impact of the strengthening of the Argentine peso on peso-denominated costs and higher severance taxes in the U.S., resulting from the significant increase in product prices in the first quarter of 2003 compared to the first quarter of 2002.

Exploration costs increased by $5.1 million (57 percent), to $14.1 million for the first quarter of 2003 from $9.0 million for the first quarter of 2002. During the first quarter of 2003, the Company’s exploration costs included $11.8 million for unsuccessful exploratory drilling and leasehold impairments and $2.3 million for seismic and other geological and geophysical costs. Exploration expenses for the first quarter of 2002 consisted of $5.5 million for unsuccessful exploratory drilling and leasehold impairments and $3.5 million for seismic and other geological and geophysical costs.

General and administrative expenses increased $1.9 million (15 percent), to $14.4 million for the first quarter of 2003 from $12.5 million for the first quarter of 2002. Expenses increased in the U.S. due to increases in non-cash charges for amortization of restricted stock awards and expenses in Argentina increased due to the negative impact of the strengthening of the Argentine peso on peso-denominated costs. These increases, along with a 13 percent decline in production on an equivalent barrel basis, increased the Company’s general and administrative expenses per equivalent barrel produced from $1.55 for the first quarter of 2002 to $2.05 for the first quarter of 2003.

Depreciation, depletion and amortization decreased $11.9 million (24 percent), to $37.3 million for the first quarter of 2003 from $49.2 million for the first quarter of 2002. The Company’s average oil and gas amortization rate per equivalent barrel produced decreased from $5.97 in the first quarter of 2002 to $5.16 in the first quarter of 2003. These decreases primarily result from the impact that substantially higher product prices in 2003 had in increasing proved reserves used to determine the amortization rate and, to a lesser degree, from the Company’s mandated adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”), effective January 1, 2003. Previously, the Company accrued an undiscounted estimate of future abandonment costs of wells and related facilities through its depreciation calculation in accordance with the provisions of Statement of Financial Accounting Standards No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, (“SFAS No. 19”)and industry practice. With the implementation of SFAS No. 143, the Company has now recorded a discounted fair value of the future retirement obligation as a liability with a corresponding amount 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. The liability accretes over time with a charge to accretion expense, which was $1.7 million for the first quarter of 2003. As a result of the implementation of SFAS No. 143, the Company recorded a non-cash gain as a cumulative effect of change in accounting principle of $7.1 million, net of taxes of $4.1 million.

Interest expense increased $1.1 million (six percent) to $18.5 million for the first quarter of 2003 from $17.4 million for the first quarter of 2002 due to a higher average interest rate resulting from a change in the Company’s fixed-to-floating rate debt mix. In May 2002, the Company issued $350 million of its 8¹/4% Senior Notes due 2012 (the “8 1/4% Notes”). All of the net proceeds were used to repay a portion of the outstanding balance under the Company’s revolving credit facility and to redeem $100 million of the Company’s outstanding 9% Senior Subordinated Notes due 2005 (the “9% Notes”). The increase in the Company’s average interest rate was offset by a 19 percent reduction in its average debt outstanding from the first quarter of 2002 to the first quarter of 2003.

During the first quarter of 2003, the Company advanced funds under its revolving credit facility to redeem the remainder of the Company’s 9% Notes. As a result, the Company was required to expense certain associated deferred financing costs and discounts. This $0.7 million non-cash charge and a $0.7 million cash charge for the call premium on the redemption of the remaining 9% Notes resulted in a one-time charge of approximately $1.4 million ($0.9 million net of tax).

Effective January 1, 2002, the Company adopted the provisions of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (“SFAS No. 142”). SFAS No. 142 changed the accounting for goodwill from an amortization method to an impairment-only method. Goodwill was tested for impairment in conjunction with a transitional goodwill impairment test in 2002. As a result of the transitional impairment test, the Company recorded a $60.5 million charge as a cumulative effect of change in accounting principle retroactive to January 1, 2002, in accordance with the provisions of SFAS No. 142. No similar charge was required in 2003.

During the first three months of 2003, the Company’s total oil and gas capital expenditures were $45.5 million ($44.4 million for continuing operations). In North America, the Company’s oil and gas capital expenditures totaled $31.8 million. Exploitation activities accounted for $18.5 million of the North America capital expenditures with exploration activities contributing $13.3 million. During the first three months of 2003, the Company’s international oil and gas capital expenditures totaled $13.7 million. This amount consists of exploitation activities of $7.1 million in Argentina, $1.1 million in Ecuador and exploration activities of $5.5 million, primarily in Yemen.

As of March 31, 2003, the Company had total unproved oil and gas property costs of approximately $88.9 million, consisting of undeveloped leasehold costs of $74.3 million, including $61.0 million in Canada, and unevaluated exploratory drilling costs of $14.6 million. Approximately $19.3 million of the total unproved costs are associated with the Company’s drilling program in Yemen and approximately $21.8 million of the total unproved costs are associated with undeveloped leaseholds in the Northwest Territories in Canada. Future exploration expense and earnings may be impacted to the extent that the Company’s future exploration activities are unsuccessful in discovering commercial oil and gas reserves in sufficient quantities to recover its costs.

The timing of most of the Company’s capital expenditures is discretionary with no material long-term capital expenditure commitments. Consequently, the Company has a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. The Company uses internally-generated cash flows to fund capital expenditures other than significant acquisitions. The Company’s capital expenditure budget for 2003 is currently set at $185 million, exclusive of acquisitions. The Company does not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. The Company is actively pursuing additional acquisitions of oil and gas properties. In addition to internally-generated cash flow and advances under its revolving credit facility, the Company may seek additional sources of capital to fund any future significant acquisitions (see “Capital Resources and Liquidity”); however, no assurance can be given that sufficient funds will be available to fund the Company’s desired acquisitions.

Cash on hand, internally generated cash flow and the borrowing capacity under its revolving credit facility are the Company’s major sources of liquidity. The Company also has the ability to adjust its level of capital expenditures. The Company may use other sources of capital, including the issuance of additional debt securities or equity securities, to fund any major acquisitions it might secure in the future and to maintain its financial flexibility.

In the past, the Company has accessed the public markets to finance significant acquisitions and provide liquidity for its future activities. Since 1990, the Company has completed five public equity offerings as well as two public debt offerings and three Rule 144A private debt offerings, all of which have provided the Company with aggregate net proceeds of approximately $1.2 billion.

On May 2, 2002, the Company issued, through a Rule 144A offering, $350 million of its 8¹/4% Notes. All of the net proceeds were used to repay a portion of the outstanding balance under the Company’s revolving credit facility and to redeem $100 million of the Company’s outstanding 9% Notes. The 8¹/4% Notes are redeemable at the option of the Company, in whole or in part, at any time on or after May 1, 2007. In addition, prior to May 1, 2005, the Company may redeem up to 35 percent of the 8¹/4% Notes with the proceeds of certain underwritten public offerings of the Company’s common stock. The 8¹/4% Notes mature on May 1, 2012, with interest payable semi-annually on May 1 and November 1, of each year.

In conjunction with the offering of 8¹/4% Notes, the Company entered into a new $300 million revolving credit facility (as amended, the “Bank Facility”), which was used to refinance its previously existing credit facility and to provide funds for ongoing operating and general corporate needs.

During the first quarter of 2003, the Company advanced funds under the Bank Facility to redeem the remainder of the 9% Notes. As a result, the Company was required to expense certain associated deferred financing costs and discounts. This $0.7 million non-cash charge and a $0.7 million cash charge for the call premium on the redemption of the remaining 9% Notes resulted in a one-time charge of approximately $1.4 million ($0.9 million net of tax).

The Bank Facility consists of a three-year senior secured credit facility with availability governed by a borrowing base determination. The Company’s availability under the Bank Facility is reduced by the outstanding letters of credit. The borrowing base (currently $300 million) is based on the banks’ evaluation of the Company’s oil and gas reserves. The amount available to be borrowed under the Bank Facility is limited to the lesser of the borrowing base or the facility size, which is also currently set at $300 million. The next semi-annual borrowing base redetermination will be in late May 2003. The Bank Facility is secured by a first priority lien on the Company’s U.S. oil and gas properties constituting at least 80 percent of the present value of the Company’s U.S. proved reserves owned now or in the future. The Bank Facility will be guaranteed by any of the Company’s existing and future U.S. subsidiaries that grant a lien on oil and gas properties under the Bank Facility.

Outstanding advances under the Bank Facility bear interest payable quarterly at a floating rate based on Bank of Montreal’s alternate base rate (as defined) or, at the Company’s option, at a fixed rate for up to six months based on the Eurodollar market rate (“LIBOR”). The Company’s interest rate increments above the alternate base rate and LIBOR vary based on the level of outstanding senior debt to the borrowing base. In addition, the Company must pay a commitment fee of 0.50 percent per annum on the unused portion of the banks’ commitment. As of March 31, 2003, the Company had no outstanding borrowings under its Bank Facility, excluding outstanding letters of credit of approximately $9.8 million.

The terms of the Bank Facility require the maintenance of a minimum current ratio (as defined therein) and tangible net worth (as defined therein) of not less than $425 million plus 75 percent of the net proceeds of any future equity offerings less any impairment write downs required by GAAP or by the Securities and Exchange Commission and excluding any impact related to SFAS No. 133.

The Company’s internally generated cash flows, results of operations and financing for its operations are dependent on oil and gas prices. Realized oil and gas prices for the first quarter of 2003 increased by 74 percent and 99 percent, respectively, as compared to the same period in 2002. For the first three months of 2003, approximately 64 percent of the Company’s production was oil. The Company believes that its cash on hand, cash flows and unused availability under the Bank Facility are sufficient to fund its planned capital expenditures for the foreseeable future. To the extent oil and gas prices decline, the Company’s earnings and cash flows from operations may be adversely impacted. Prolonged periods of low oil and gas prices could cause the Company to not be in compliance with maintenance covenants under its Bank Facility and could negatively affect its credit statistics and coverage ratios and thereby affect its liquidity.

Consistent with its stated goal of maintaining financial flexibility and optimizing its portfolio of assets, the Company announced in early 2002 plans to reduce debt by $200 million through a combination of asset sales and cash flows in excess of planned capital expenditures. The Company’s operations in Ecuador were sold in January 2003 for $137.4 million in cash, subject to post-closing adjustments. The closing of this sale culminated the achievement of the Company’s $200 million debt reduction goal. The Company is considering additional property sales in 2003 to continue its progress toward lower debt levels. The Company sold certain non-strategic U.S. assets on March 31, 2003, for approximately $29.5 million and is currently marketing certain non-strategic properties in Canada. However, there can be no assurance that any future property sales will be completed.

The Company’s contractual obligations have not changed significantly since December 31, 2002, except for the following:

As a result of the recent devaluation of the Argentine peso, 2002 peso inflation was approximately 41 percent in Argentina. However, in recent months, the Argentine inflation rate has slowed significantly, with the inflation rate for the first quarter of 2003 at less than two percent. In recent years, inflation outside of Argentina has not had a significant impact on the Company’s operations or financial condition and is not currently expected to have a significant impact on future periods.

The Company incurred a current provision for income taxes related to continuing operations of approximately $14.5 million and $2.0 million for the first three months of 2003 and 2002, respectively. The total provision for U.S. income taxes is based on the federal corporate statutory income tax rate plus an estimated average rate for state income taxes. 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.

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

The income tax expense related to the gain on the sale of operations in Ecuador includes $19.4 million of taxes on previously unremitted foreign earnings. No. U.S. income taxes were previously recorded on these earnings.

Management’s discussion and analysis of its financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgements and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The preparation of these consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions. Note 1 to the Company’s 2002 audited consolidated financial statements included in its 2002 Annual Report on Form 10-K and Note 2 to the Company’s consolidated financial statements included elsewhere in this Form 10-Q, contain a comprehensive summary of the Company’s significant accounting policies. The following is a discussion of the Company’s most critical accounting policies, judgments and uncertainties that are inherent in the Company’s application of GAAP:

Accounting for Oil and Gas Properties. 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 is 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, are expensed as incurred. The Company recognizes gains or losses on the sale of properties on a field basis.

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Delineation seismic costs incurred to select development locations within a productive oil and gas field are typically treated as development costs and capitalized. Judgment is required to determine when the seismic programs are not within proved reserve areas and therefore would be charged to expense as exploratory. The evaluation of oil and gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when the Company enters a new exploratory area in hopes of finding oil and gas reserves. Seismic costs can be substantial which will result in additional exploration expenses when incurred. The initial exploratory wells may be unsuccessful, causing the associated costs to be expensed as dry hole costs.

Proved reserve estimates. Estimates of the Company’s proved reserves included in its consolidated financial statements are prepared in accordance with guidelines established by GAAP and the SEC. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The process relies on interpretations of available geologic, geophysic, engineering and production data. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgment of the persons preparing the estimate.

The Company’s proved reserve information is based on estimates prepared by its independent petroleum consultants. Estimates prepared by others may be higher or lower than these estimates. Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

The present value of future net cash flows should not be assumed to be the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves were based on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

The estimates of proved reserves materially impact depletion, depreciation and amortization expense. If the estimates of proved reserves decline, the rate at which the Company records depletion, depreciation and amortization expense increases, reducing net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost reserves. In addition, the decline in proved reserve estimates may impact the outcome of the Company’s assessment of its oil and gas producing properties for impairment.

Impairment 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. 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 methods used for acquisition evaluations. Oil and gas reserve estimates may change in future periods and oil and gas prices are historically volatile. Events may arise that will require the Company to record an impairment of its oil and gas properties and there can be no assurance that such impairments will not be required in the future.

Impairment of unproved oil and gas properties. Unproved leasehold costs and exploratory drilling in progress are capitalized and reviewed periodically for impairment. Individual unproved properties whose acquisition costs are significant are assessed on a property-by-property basis. The impairment associated with unproved properties whose acquisition costs are not individually significant is determined by amortizing the properties in groups. Costs related to impaired prospects or unsuccessful exploratory drilling are charged to expense. Management’s assessment of the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of such leaseholds impact the amount and timing of impairment provisions. Further impairment expense could result if oil and gas prices decline in the future or if downward reserve revisions are recorded, as it may not be economic to develop some of these unproved properties. As of March 31, 2003, the Company had total unproved oil and gas property costs of approximately $88.9 million consisting of undeveloped leasehold costs of $74.3 million, including $61.0 million in Canada, and unproved exploratory drilling costs of $14.6 million. Approximately $19.3 million of the total unproved costs are associated with the Company’s drilling program in Yemen and approximately $21.8 million of the total unproved costs are associated with undeveloped leaseholds in the Northwest Territories in Canada. Future exploration expense and earnings may be impacted to the extent that the Company’s future exploration activities are unsuccessful in discovering commercial oil and gas reserves in sufficient quantities to recover its costs.

Impairment of goodwill. The Company’s goodwill of $22.7 million at March 31, 2003, is related entirely to its Canadian operations. The Company must assess its goodwill for impairment at least annually. The Company must first perform an assessment of whether there is an indication that the carrying value of goodwill is impaired. This assessment is made by comparing the fair value of the Canadian operations, as determined in accordance with SFAS No. 142, to its book value. If the fair value is less than the book value, an impairment is indicated and the Company must perform a second test to measure the amount of the impairment. In the second test, the Company must then calculate the implied fair value of the goodwill by deducting the fair value of all tangible and intangible net assets of the Canadian operations from the fair value of the Canadian operations determined in step one of the assessment. If the carrying value of the goodwill exceeds this calculated implied fair value of the goodwill, an impairment charge is recorded.

Estimates of future dismantlement, restoration, and abandonment costs. Through December 31, 2002, the Company had accrued future abandonment costs of wells and related facilities through its depreciation calculation in accordance with the provisions of SFAS No. 19 and industry practice. The accounting for future development and abandonment costs changed on January 1, 2003, with the mandated adoption of SFAS No. 143. See “Changes in Accounting Principles” for a further discussion of this new standard. Under both methods of accounting, the accrual is based on estimates of these costs for each of the Company’s properties based upon the type of production structure, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment and, beginning in 2003, estimates as to the proper discount rate to use and timing of abandonment.

Income taxes. The Company provides deferred income taxes on transactions which are recognized in different periods for financial and tax reporting purposes. The Company has not recognized a U.S. deferred tax liability related to the unremitted earnings of any of its foreign subsidiaries as it is the Company’s intention, generally, to reinvest such earnings permanently. Management periodically assesses the need to utilize these unremitted earnings to finance the operations of the Company. This assessment is based on cash flow projections that are the result of estimates of future production, commodity pricing and expenditures by tax jurisdiction for the Company’s operations. Such estimates are inherently imprecise since many assumptions utilized in the cash flow projections are subject to revision in the future.

The Company has also recorded deferred tax assets related to operating loss and tax credit carryforwards. Management periodically assesses the probability of recovery of recorded deferred tax assets based on its assessment of future earnings outlooks by tax jurisdiction. Such estimates are inherently imprecise because many assumptions are utilized in the assessments that may prove to be incorrect in the future.

Assessments of functional currencies. All of the Company’s subsidiaries use the U.S. dollar as their functional currency, except for the Company’s Canadian operating subsidiary, which uses the Canadian dollar. Management determines the functional currencies of the Company’s subsidiaries based on an assessment of the currency of the economic environment in which a subsidiary primarily realizes and expends its operating revenues, costs and expenses. The assessment of functional currencies can have a significant impact on periodic results of operations and financial position.

Argentina economic and currency measures. The accounting for and translation of the financial statements of the Company’s operations in Argentina reflects management’s assumptions regarding uncertainties unique to Argentina’s current economic situation. See Notes 1 and 2 to the Company’s consolidated financial statements included elsewhere in this Form 10-Q for a description of the assumptions utilized in the preparation of its consolidated financial statements. Argentina’s economic and political situation evolves continuously and the Argentine government has adopted numerous decrees, is considering implementing various alternatives and may enact future regulations or policies that may materially impact, among other items, (i) the realized prices the Company receives for oil and gas it produces and sells; (ii) the timing and amount of repatriations of cash to the U.S.; (iii) the amount of permitted export sales; (iv) the Argentine banking system; (v) the Company’s asset valuations; and (vi) peso-denominated monetary assets and liabilities. For further information, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk-Foreign Currency and Operations Risk” included elsewhere in this Form 10-Q.

On July 20, 2001, the FASB issued Statement of Financial Accounting Standards No. 141, Business Combinations (“SFAS No. 141”), and SFAS No. 142. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method of accounting. Under SFAS No. 142, goodwill is no longer subject to amortization. Instead, goodwill will be subject to at least an annual assessment for impairment by applying a fair-value based test. Additionally, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

The Company adopted SFAS No. 141 and SFAS No. 142 effective January 1, 2002, resulting in the elimination of goodwill amortization from statements of operations in future periods. As discussed in Note 5 to the Company’s consolidated financial statements included elsewhere in this Form 10-Q, the Company recorded an impairment charge of $60.5 million related to the goodwill of its Canadian operations as a cumulative effect of a change in accounting principle in its statement of operations.

In August 2001, FASB issued SFAS No. 143. The Company was required to adopt this new standard beginning January 1, 2003. Through December 31, 2002, the Company accrued an estimate of future abandonment costs of wells and related facilities through its depreciation calculation and included the cumulative accrual in accumulated depreciation in accordance with the provisions of SFAS No. 19 and industry practice. At December 31, 2002, approximately $54.6 million of accrued future abandonment costs were included in accumulated depreciation. The new standard requires that the Company record the discounted fair value of the retirement obligation as a liability at the time a well is drilled or acquired. The majority of the asset retirement obligations of the Company relate to the plugging and abandonment of oil and gas wells. However, future abandonment liabilities were 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. The liability accretes over time with a charge to accretion expense. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The Company adopted the new standard effective January 1, 2003, and recorded an increase in property, plant and equipment of approximately $50.3 million, a decrease in accumulated depreciation, depletion and amortization of approximately $43.9 million, an increase in current asset retirement liabilities of approximately $4.5 million, an increase in long-term asset retirement liabilities of approximately $78.5 million, a $4.1 million increase in deferred income tax liabilities and a non-cash gain as a result of the cumulative effect of change in accounting principle, net of tax, of approximately $7.1 million.

On April 30, 2002, the FASB issued Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections (“SFAS No. 145”). SFAS No. 145 updates, clarifies and simplifies existing accounting pronouncements. Among other items, it rescinds previous accounting rules which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of related income tax effect. The Company has adopted the provisions of SFAS No. 145 and, accordingly, has classified a $1.4 million ($0.9 million net of tax) loss on the early extinguishment of debt (see Note 3 to the Company’s consolidated financial statements included elsewhere in this Form 10-Q) as a charge to income from continuing operations in its statements of operations for the three months ended March 31, 2003. The adoption of SFAS No. 145 did not have any other material impact on the Company’s financial position or results of operations.

On July 30, 2002, the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities. The standard requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The provisions of this statement are to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The adoption of this standard did not have a material impact on the Company’s financial position or results of operations.

On December 31, 2002, the FASB issued Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation—Transition and Disclosure (“SFAS No. 148”). SFAS No. 148 amends Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”), to provide alternative methods of transition to SFAS No. 123’s fair value method of accounting for stock-based employee compensation. SFAS No. 148 also amends the disclosure provisions of SFAS No. 123 and APB Opinion No. 28, Interim Financial Reporting, to require disclosure in the summary of significant accounting policies of the effects of an entity’s accounting policy with respect to stock-based employee compensation on reported net income and earnings per share in annual and interim financial statements. While SFAS No. 148 does not require companies to account for employee stock options using the fair value method, the disclosure provisions of the standard are applicable to all companies with stock-based employee compensation, regardless of whether they account for that compensation using the fair value method or the intrinsic value method. The Company has adopted the disclosure provisions of SFAS No. 148. The Company is considering the adoption of SFAS No. 123’s fair value method of accounting for stock-based employee compensation in 2003, but has not yet made a final determination.

For information on the Company’s foreign operations, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency and Operations Risk” included elsewhere in this Form 10-Q.

This Form 10-Q includes certain statements that may be deemed to be “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements in this Form 10-Q, other than statements of historical facts, that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future, including production, operating costs and product price realizations, future capital expenditures (including the amount and nature thereof), the drilling of wells, reserve estimates, future production of oil and gas, future cash flows, future reserve activity, planned asset sales or dispositions, events or developments in Argentina, including estimates of oil export levels, and other such matters are forward-looking statements. Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions within the bounds of its knowledge of its business, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements.

Factors that could cause actual results to differ materially from those in forward-looking statements include: oil and gas prices; exploitation and exploration successes; actions taken and to be taken by Argentina as a result of its economic instability; continued availability of capital and financing; general economic, market or business conditions; acquisition and other business opportunities (or lack thereof) that may be presented to the Company; changes in laws or regulations; risk factors listed from time to time in the Company’s reports and other documents filed with the Securities and Exchange Commission; and other factors. The Company assumes no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise.

The Company’s operations are exposed to market risks primarily as a result of changes in commodity prices, interest rates and foreign currency exchange rates. The Company does not use derivative financial instruments for speculative or trading purposes.

The Company produces, purchases and sells crude oil, natural gas, condensate, natural gas liquids and sulfur. As a result, the Company’s financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the impact of commodity price changes based on production levels for the first three months of 2003. The Company has previously engaged in oil and gas hedging activities and intends to continue to consider various hedging arrangements to realize commodity prices which it considers favorable.

As of March 31, 2003, the Company has entered into various oil price swap agreements for various periods of the remainder of 2003 covering approximately 3.0 million barrels at a weighted average NYMEX reference price of $25.83 per barrel and gas price swap agreements for various periods of the remainder of 2003 covering approximately 15.1 million MMBtu. The Canadian portion of the gas swap agreements, approximately 6.9 million MMBtu, is at a weighted average NYMEX reference price of 6.48 Canadian dollars per MMBtu. The U.S. portion of the gas swap agreements, approximately 8.2 million MMBtu, is at a weighted average NYMEX reference price of $3.93 per MMBtu. Additionally, the Company has entered into basis swap agreements for the approximately 6.3 million MMBtu of its U.S. gas production covered by the gas swap agreements. 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. At March 31, 2003, the Company would have paid approximately $24.0 million to terminate its swap agreements then in place.

The counterparties to the Company’s hedging agreements are commercial or investment banks. The Company continues to monitor oil and gas prices and may enter into additional oil and gas hedges or swaps in the future.

The Company’s interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from its commercial banks. To reduce the impact of fluctuations in interest rates, the Company has historically maintained a portion of its total debt portfolio in fixed-rate debt. At March 31, 2003, all of the Company’s outstanding debt was at fixed rates. However, the Company expects that this relationship will not continue and that a portion of the Company’s debt in future periods will be at variable rates. In the past, the Company has not entered into financial instruments such as interest rate swaps or interest rate lock agreements. However, it may consider these instruments to manage the portfolio mix between fixed and floating rate debt and to mitigate the impact of changes in interest rates based on management’s assessment of future interest rates, volatility of the yield curve and the Company’s ability to access the capital markets in a timely manner. Since all of the Company’s outstanding debt at March 31, 2003, was at fixed rates, changes in average interest rates would have had no impact on the Company’s net income and cash flow.

The following table provides information about the Company’s long-term debt principal payments and weighted-average interest rates by expected maturity dates:

International investments represent, and are expected to continue to represent, a significant portion of the Company’s total assets. The Company has international operations in Canada, Argentina, Bolivia, Yemen and Italy. For the three months ended March 31, 2003, the Company’s operations in Argentina and Canada accounted for approximately 34 percent and 18 percent, respectively, of the Company’s revenues and, approximately 27 percent and 33 percent, respectively, of the Company’s total assets. During the first three months of 2003 and at March 31, 2003, the Company’s operations in Argentina and Canada represented its only foreign operations accounting for more than 10 percent of its revenues or total assets. The Company continues to identify and evaluate international opportunities, but currently has no binding agreements or commitments to make any material international investment. As a result of such significant foreign operations, the Company’s financial results could be affected by factors such as changes in foreign currency exchange rates, weak economic conditions or changes in the political climate in these foreign countries.

Historically, the Company has not used derivatives or other financial instruments to hedge the risk associated with the movement in foreign currencies. However, the Company evaluates currency fluctuations and will consider the use of derivative financial instruments or employment of other investment alternatives if it deems cash flows or investment returns so warrant.

The Company’s international operations, properties or investments may be adversely affected by political and economic instability, changes in the legal and regulatory environment and other factors. For example:

The Company does not currently maintain political risk insurance. However, the Company will consider obtaining such coverage in the future if it deems conditions so warrant.

Canada. The Company views the operating environment in Canada as stable and the economic stability as good. Substantially all of the Company’s Canadian revenues and costs are denominated in Canadian dollars. While the value of the Canadian dollar does fluctuate in relation to the U.S. dollar, the Company believes that any currency risk associated with its Canadian operations would not have a material impact on the Company’s results of operations. The exchange rate at March 31, 2003, was US$1:C$1.47 as compared to US$1:C$1.58 at December 31, 2002.

Argentina. Beginning in 1991, Peronist Carlos Menem, as newly-elected President of Argentina, and Domingo Cavallo, as his Minister of Economy, set out to reverse economic decline through free market reforms such as open trade. The key to their plan was the “Law of Convertibility” under which the peso was tied to the U.S. dollar at a rate of one peso to one U.S. dollar. Between 1991 and 1997 the plan succeeded. With the risk of devaluation apparently removed, capital came in from abroad and much of Argentina’s state-owned assets were privatized. During this period, the economy grew at an annual average rate of 6.1 percent, the highest in the region.

However, the “convertibility” plan left Argentina with few monetary policy tools to respond to outside events. A series of external shocks began in 1998: prices for Argentina’s commodities stopped rising; the dollar appreciated against other currencies; and Brazil, Argentina’s main trading partner, devalued its currency. Argentina began a period of economic deflation, but failed to respond by reforming government spending. During 2001, Argentina’s budget deficit exceeded $9 billion and its sovereign debt reached $140 billion.

As a result of economic instability and substantial withdrawals from the banking system, in early December 2001, the Argentine government, with Fernando de la Rua as President and Domingo Cavallo as Minister of Economy, instituted restrictions that prohibit foreign money transfers without Central Bank approval and limit cash withdrawals from bank accounts for personal transactions in small amounts with certain limited exceptions. While the legal exchange rate remained at one peso to one U.S. dollar, financial institutions were allowed to conduct only limited activity due to these controls, and currency exchange activity was effectively halted except for personal transactions in small amounts.

On January 6, 2002, the Argentine government abolished the one peso to one U.S. dollar legal exchange rate. On January 9, 2002, Decree 71 created a dual exchange market whereby foreign trade transactions were conducted at an official exchange rate of 1.4 pesos to one U.S. dollar and other transactions were conducted in a free floating exchange market. On February 8, 2002, Decree 260 unified the dual exchange markets and allowed the peso to float freely with the U.S. dollar. The exchange rate at March 31, 2003, was 2.98 pesos to one U.S. dollar. The devaluation of the peso reduced the Company’s gas revenues and peso-denominated costs. Oil revenues remain valued on a U.S. dollar basis.

On February 3, 2002, Decree 214 required all contracts that were previously payable in U.S. dollars to be payable in pesos. Pursuant to an emergency law passed on January 10, 2002, U.S. dollar obligations between private parties due after January 6, 2002, were liquidated in pesos at a negotiated rate of exchange which reflected a sharing of the impact of the devaluation. The Company’s settlements in pesos of the existing U.S. dollar-denominated agreements have been completed, thus future periods will not be impacted by this mandate. This government-mandated “equitable sharing” of the impact of the devaluation resulted in a reduction in oil revenues from domestic sales for the first quarter of 2002 of approximately $8 million, ($2.67 per Argentine barrel produced or $1.44 per total Company barrel produced). The reduction of the Company’s Argentine lease operating costs, which were also reduced as a result of this mandate and the positive impact of devaluation on the Company’s peso-denominated costs, essentially offset the negative impact on Argentine oil revenues.

On February 13, 2002, the Argentine government announced a 20 percent tax on oil exports, effective March 1, 2002. The tax is limited by law to a term of no more than five years. The tax of 20 percent is applied on the sales value after the tax, thus the net effect is 16.7 percent. The Company currently exports approximately 70 percent of its Argentine oil production. The Company believes that this export tax has and will continue to have the effect of decreasing all future Argentine oil revenues (not only export revenues) by the tax rate for the duration of the tax. The U.S. dollar equivalent value for domestic Argentine oil sales (now paid in pesos) has generally moved to parity with the U.S. dollar denominated export values, net of the export tax. The adverse impact of this tax has been partially offset by the net cost savings resulting from the devaluation of the peso on peso denominated costs and is further reduced by the Argentine income tax savings related to deducting the impact of the export tax. The export tax is not deducted in the calculation of royalty payments.

Since May 2002, many of Argentina’s important economic indicators have stabilized. The Central Bank’s foreign currency reserves have risen from a low of $8.9 billion in 2002 to a recent high on March 3, 2003, of $10.3 billion. Since being allowed to freely float against the U.S. dollar, the peso reached its weakest value at 3.80 pesos to one U.S. dollar in June of 2002, and has since stabilized, gradually appreciating to a value of 2.79 pesos to one U.S. dollar on May 7, 2003. Monthly inflation has decreased from a high of 10 percent for the month of April 2002 to an average of less than two percent per month from May to December 2002 with first quarter 2003 inflation of less than two percent. Inflation for all of 2002 was approximately 41 percent.

After a year of negotiations, the International Monetary Fund (“IMF”) approved a $6.8 billion dollar debt rollover agreement on January 24, 2003. While only short term in nature, the package is designed to allow stability to continue at least through the presidential election process in May 2003 by rescheduling all IMF debts falling due between January and August of 2003. As part of the agreement, the government agreed to raise its primary budget surplus target to 2.5 percent of the country’s gross domestic product.

The plan set in motion by current President Eduardo Duhalde to transition the government back into the hands of an elected president remains in place. General elections were held on April 27, 2003 and a runoff election between the top two candidates, former president Carlos Menem and current governor of Santa Cruz province, Nestor Kirchner will be held on May 18, 2003. President Duhalde has indicated that the transition of government will take place on May 25, 2003, after elections are complete.

On January 2, 2003, at the Argentine government’s request, crude oil producers and refiners agreed to cap amounts payable for domestic sales occurring during the first quarter of 2003 at $28.50 per Bbl. The producers and refiners further agreed that the difference between the actual price and the capped price would be payable once actual prices fall below the cap. The debt payable under the agreement accrues interest at eight percent. The total debt will be collected by invoicing future deliveries at $28.50 per Bbl after actual prices fall below the capped price. Additionally, the agreement allowed for renegotiation if the West Texas Intermediate reference price exceeded $35.00 per Bbl for ten consecutive days, which occurred on February 24, 2003.

On February 25, 2003, the agreement between the producers and the refiners was modified to limit the amount payable from refiners to producers for deliveries occurring between February 26, 2003, and March 31, 2003. While the $28.50 per Bbl payable cap was maintained, under the modified terms refiners have no obligation to pay producers for sales values that exceed $36.00 per Bbl. Furthermore, interest for debts established during this period was reduced to seven percent. On April 11, 2003, the agreement was extended until May 31, 2003.

The Company sold approximately 460,000 net Bbls of its first quarter 2003 Argentine oil production under this agreement and expects to sell 380,000 net Bbls under the modified terms in the second quarter of 2003.

Bolivia. Since the mid 1980’s, Bolivia has been undergoing major economic reform, including the establishment of a free market economy and the encouragement of foreign private investment. Economic activities that had been reserved for government corporations were opened to foreign and domestic Bolivian private investments. Barriers to international trade have been reduced and tariffs lowered. A new investment law and revised codes for mining and the petroleum industry, intended to attract foreign investment, have been introduced.

Elections held during June 2002 marked the sixth consecutive democratic election held in Bolivia since 1982, representing the longest period of constitutional democratic government in the country’s history. Coalitions were formed among the two leading political parties allowing Gonzalo Sanchez de Lozada to win the runoff election. Since election, President Sanchez de Lozada’s government has been working to improve the economic and fiscal framework in order to facilitate new loan agreements from the IMF. After violent protests to his proposed tax increases and cuts in government spending in early 2003, President Sanchez de Lozada was forced to reorganize his government and propose a new budget for 2003. The new budget was approved and led to the IMF’s approval of a one year stand-by loan agreement for $118 million in April 2003. Bolivia’s economic focus for 2003 is stabilizing the economy after the recent civil disturbances and resulting financial instability, and laying the basis for a return to growth.

Also in an attempt to narrow budget deficits, the government has announced new taxes on oil refiners. The oil refiners have, in turn, sued the government. While the final outcome of the newly announced tax on refiners remains unclear, the Company will receive lower prices for domestic oil sales as a result of these taxes in the short term. In 2002, the Company’s Bolivian oil production accounted for less than one percent of the Company’s total production from continuing operations on an equivalent barrel basis.

In 1987, the Boliviano replaced the peso at the rate of one million pesos to one Boliviano. The exchange rate is set daily by the government’s exchange house, the Bolsin, which is under the supervision of the Bolivian Central Bank. Foreign exchange transactions are not subject to any controls. The exchange rate at March 31, 2003, was 7.60 Bolivianos to one U.S. dollar. The Company believes that any currency risk associated with its Bolivian operations would not have a material impact on the Company’s financial position or results of operations because its gas revenues are received in U.S. dollars.

Within the 90 days prior to the filing date of this Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures, as defined in Rule 13a-14(c) of the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its periodic filings under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Subsequent to the date of their evaluation, there have been no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls.

For information regarding legal proceedings, see the Company’s Form 10-K for the year ended December 31, 2002.

The following documents are included as exhibits to this Form 10-Q. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, such exhibit is filed herewith.

Form 8-K dated January 8, 2003, was filed on January 8, 2003, to report under Item 5 an update to the Company’s 2003 hedging activities.

Form 8-K dated January 21, 2003, was filed on January 21, 2003, to report under Item 5 the signing of a definitive agreement to sell the Company’s holdings in Ecuador and presentation of certain unaudited financial information related thereto.

Form 8-K dated January 27, 2003, was filed on January 28, 2003, to report under Item 5 the Company’s press release dated January 27, 2003, updating its Yemen drilling campaign.

Form 8-K dated February 3, 2003, was filed on February 4, 2003, to report under Item 5 the Company’s press releases dated February 3, 2003, announcing the closing of the sale of the Company’s holdings in Ecuador and achievement of the Company’s debt reduction target and announcing the call for redemption of the Company’s 9% Senior Subordinated Notes due 2005.

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 thereunto duly authorized.

VINTAGE PETROLEUM, INC.

(Registrant)

\s\ MICHAEL F. MEIMERSTORF

Michael F. Meimerstorf
Vice President and Controller
(Principal Accounting Officer)

Delaware		73-1182669
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

110 West Seventh Street Tulsa, Oklahoma		74119-1029
(Address of principal executive offices)		(Zip Code)

Class		Outstanding at May 9, 2003
Common Stock, $.005 Par Value		63,899,775

	March 31, 2003		December 31, 2002
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	110,962	$	9,259
Accounts receivable—
Oil and gas sales		104,819		90,267
Joint operations		7,938		9,542
Prepaids and other current assets		20,981		21,021
Assets of discontinued operations		—		86,174

Total current assets		244,700		216,263

PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method		2,568,698		2,487,549
Oil and gas gathering systems and plants		21,384		20,588
Other		26,846		26,501

		2,616,928		2,534,638

Less accumulated depreciation, depletion and amortization		1,033,229		1,047,665

Total property, plant and equipment, net		1,583,699		1,486,973

GOODWILL, net		22,677		21,099

OTHER ASSETS, net		50,798		51,469

TOTAL ASSETS	$	1,901,874	$	1,775,804

	March 31, 2003		December 31, 2002
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Revenue payable	$	25,161	$	30,869
Accounts payable—trade		34,413		42,038
Current income taxes payable		67,794		18,722
Short-term debt		3,570		4,732
Derivative financial instruments payable		24,021		17,122
Other payables and accrued liabilities		76,297		54,281
Liabilities of discontinued operations		—		10,769

Total current liabilities		231,256		178,533

LONG-TERM DEBT		799,416		883,180

DEFERRED INCOME TAXES		147,621		137,015

LONG-TERM LIABILITY FOR ASSET RETIREMENT OBLIGATIONS		79,007		—

OTHER LONG-TERM LIABILITIES		5,352		6,084

COMMITMENTS AND CONTINGENCIES (Note 6)

STOCKHOLDERS’ EQUITY, per accompanying statement:
Preferred stock, $.01 par, 5,000,000 shares authorized, zero shares issued and outstanding		—		—
Common stock, $.005 par, 160,000,000 shares authorized, 64,020,975 and 63,432,972 shares issued and 63,899,775 and 63,348,272 outstanding, respectively		320		317
Capital in excess of par value		331,978		326,510
Retained earnings		313,118		274,971
Accumulated other comprehensive income (loss)		796		(28,573	)

		646,212		573,225

Less treasury stock, at cost, 121,200 and 84,700 shares		—		—
Less unamortized cost of restricted stock awards		6,990		2,233

Total stockholders’ equity		639,222		570,992

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,901,874	$	1,775,804

	Three Months Ended March 31,
	2003			2002
				(Restated)
REVENUES:
Oil and gas sales	$	185,658		$	118,500
Gas marketing		32,920			12,328
Oil and gas gathering and processing		1,954			1,385
Gain (loss) on disposition of assets		(650	)		85
Foreign currency exchange gain (loss)		(3,637	)		2,892
Other income (expense)		(249	)		616

Total revenues		215,996			135,806

COSTS AND EXPENSES:
Lease operating, including production and export taxes		54,210			46,854
Exploration costs		14,078			8,953
Gas marketing		32,037			11,804
Oil and gas gathering and processing		2,596			1,777
General and administrative		14,406			12,514
Depreciation, depletion and amortization		37,294			49,242
Accretion		1,747			—
Interest		18,541			17,436
Loss on early extinguishment of debt		1,426			—

		176,335			148,580

Income (loss) from continuing operations before income taxes and cumulative effect of changes in accounting principles		39,661			(12,774	)

PROVISION (BENEFIT) FOR INCOME TAXES:
Current		14,463			2,039
Deferred		2,480			(8,518	)

Total provision (benefit) for income taxes		16,943			(6,479	)

Income (loss) from continuing operations before cumulative effect of changes in accounting principles		22,718			(6,295	)
INCOME FROM DISCONTINUED OPERATIONS, net of income taxes		10,844			675

Income (loss) before cumulative effect of changes in accounting principles		33,562			(5,620	)
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES, net of income tax provision of $4,104 and zero, respectively		7,119			(60,547	)

NET INCOME (LOSS)	$	40,681		$	(66,167	)

	Three Months Ended March 31,
	2003		2002
			(Restated)
BASIC INCOME (LOSS) PER SHARE:
Income (loss) from continuing operations before cumulative effect of changes in accounting principles	$	.36	$	(.10	)
Income from discontinued operations		.17		.01

Income (loss) before cumulative effect of changes in accounting principles		.53		(.09	)
Cumulative effect of changes in accounting principles		.11		(.96	)

Net income (loss)	$	.64	$	(1.05	)

DILUTED INCOME (LOSS) PER SHARE:
Income (loss) from continuing operations before cumulative effect of changes in accounting principles	$	.35	$	(.10	)
Income from discontinued operations		.17		.01

Income (loss) before cumulative effect of changes in accounting principles		.52		(.09	)
Cumulative effect of changes in accounting principles		.11		(.96	)

Net income (loss)	$	.63	$	(1.05	)

Weighted average common shares outstanding:
Basic		63,590		63,083

Diluted		64,811		63,083

	Common Stock			Treasury Shares	Capital In Excess of Par Value			Un- amortized Restricted Stock Awards			Retained Earnings			Accumulated Other Compre-hensive Income (Loss)			Total
	Shares	Amount		Treasury Shares	Capital In Excess of Par Value			Un- amortized Restricted Stock Awards			Retained Earnings			Accumulated Other Compre-hensive Income (Loss)			Total
BALANCE AT DECEMBER 31, 2002	63,433	$	317	85	$	326,510		$	(2,233	)	$	274,971		$	(28,573	)	$	570,992

Comprehensive income:
Net income	—		—	—		—			—			40,681			—			40,681
Foreign currency translation adjustment	—		—	—		—			—			—			33,384			33,384
Change in value of derivatives, net of tax	—		—	—		—			—			—			(4,015	)		(4,015	)

Total comprehensive income																		70,050

Exercise of stock options and resulting tax effects	18		—	—		131			—			—			—			131
Issuance of restricted stock	570		3	—		5,596			(5,599	)		—			—			—
Amortization of restricted stock awards	—		—	—		138			814			—			—			952
Forfeiture of restricted stock and other	—		—	36		(397	)		28			—			—			(369	)
Cash dividends declared ($.04 per share)	—		—	—		—			—			(2,534	)		—			(2,534	)

BALANCE AT MARCH 31, 2003	64,021	$	320	121	$	331,978		$	(6,990	)	$	313,118		$	796		$	639,222

	Three Months Ended March 31,
	2003			2002
				(Restated)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	40,681		$	(66,167	)
Adjustments to reconcile net income (loss) to cash provided by operating activities—
Income from discontinued operations, net of tax		(10,844	)		(675	)
Cumulative effect of changes in accounting principles		(7,119	)		60,547
Depreciation, depletion and amortization		37,294			49,242
Accretion expense		1,747			—
Exploration costs		14,078			8,953
Provision (benefit) for deferred income taxes		2,480			(8,518	)
Foreign currency exchange (gain) loss		3,637			(2,892	)
(Gain) loss on dispositions of assets		650			(85	)
Loss on early extinguishment of debt		1,426			—
Other non-cash items		995			(177	)

		85,025			40,228
Increase in receivables		(11,322	)		(11,087	)
Increase (decrease) in payables and accrued liabilities		8,337			(11,545	)
Other working capital changes		853			6,645

Cash provided by continuing operations		82,893			24,241
Cash used by discontinued operations		(2,045	)		(1,358	)

Cash provided by operating activities		80,848			22,883

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures—
Oil and gas properties		(45,392	)		(33,935	)
Gathering systems and other		(981	)		530
Proceeds from sale of oil and gas properties		29,460			7,195
Proceeds from sale of company, net of cash sold		116,107			—
Other		(1,454	)		5,261

Cash provided (used) by investing activities—continuing operations		97,740			(20,949	)
Cash provided by investing activities—discontinued operations		10,309			1,237

Cash provided (used) by investing activities		108,049			(19,712	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock		131			398
Redemption of 9% Senior Subordinated Notes due 2005		(50,750	)		—
Advances on revolving credit facility and other borrowings		93,800			68,006
Payments on revolving credit facility and other borrowings		(128,762	)		(66,000	)
Dividends paid		(2,534	)		(2,205	)
Other		—			(332	)

Cash used by financing activities		(88,115	)		(133	)

EFFECT OF EXCHANGE RATE CHANGES ON CASH		921			6

NET INCREASE IN CASH AND CASH EQUIVALENTS		101,703			3,044
CASH AND CASH EQUIVALENTS, beginning of period		9,259			6,359

CASH AND CASH EQUIVALENTS, end of period	$	110,962		$	9,403

Initial liability for asset retirement obligations as of January 1, 2003	$	83,040
Obligations fulfilled during the three months ended March 31, 2003		(603	)
Reversal of liability for dispositions of assets		(689	)
Accretion expense		1,747

Liability for asset retirement obligations as of March 31, 2003	$	83,495

	As Reported			Pro Forma
Net Loss	$	(66,167	)	$	(67,098	)

Loss per share:
Basic	$	(1.05	)	$	(1.06	)
Diluted	$	(1.05	)	$	(1.06	)

	March 31,
	2003			2002
Foreign currency translation adjustments	$	13,727		$	(25,121	)
Changes in value of derivatives, net of tax		(12,931	)		(5,950	)

	$	796		$	(31,071	)

	March 31, 2003		December 31, 2002
Revolving credit facility	$	—	$	33,800
8¹/4% Senior Notes due 2012		350,000		350,000
Senior Subordinated Notes:
9% Notes due 2005, less unamortized discount		—		49,958
8⁵/8% Notes due 2009, less unamortized discount		99,477		99,484
9³/4% Notes due 2009		150,000		150,000
7⁷/8% Notes due 2011, less unamortized discount		199,939		199,938

	$	799,416	$	883,180

	As Reported			As Restated
Loss before cumulative effect of change in accounting principle	$	(5,620	)	$	(5,620	)
Cumulative effect of change in accounting principle		—			(60,547	)

Net loss	$	(5,620	)	$	(66,167	)

Basic Loss Per Share:
Loss before cumulative effect of change in accounting principle	$	(.09	)	$	(.09	)
Cumulative effect of change in accounting principle		—			(.96	)

Net loss	$	(.09	)	$	(1.05	)

Diluted Loss Per Share:
Loss before cumulative effect of change in accounting principle	$	(.09	)	$	(.09	)
Cumulative effect of change in accounting principle		—			(.96	)

Net loss	$	(.09	)	$	(1.05	)

	Three Months Ended March 31, 2002
Loss from discontinued operations	$	(111	)
Deferred tax benefit		(39	)

Loss from discontinued operations, net of tax	$	(72	)

	December 31, 2002
Current assets	$	19,365
Property, plant and equipment, net		58,968
Other assets, net		2,676
Deferred income tax asset		5,165

Assets of discontinued operations	$	86,174

Current liabilities of discontinued operations	$	10,769

	Exploration and Production
	U.S.		Canada		Argentina		Bolivia		Other Foreign
Three Months Ended 3/31/03
Revenues from external customers	$	69,726	$	38,446	$	73,727	$	3,108	$	—
Intersegment revenues		—		—		—		—		—
Depreciation, depletion and amortization expense		10,078		15,334		10,298		649		—
Segment operating income (loss)		31,209		7,543		40,449		1,261		(1,849	)
Total assets		445,993		621,419		520,722		121,047		19,842
Capital investments		20,262		11,496		7,062		257		5,345
Long-lived assets		419,033		587,522		472,455		93,561		19,481

	Exploration and Production
	U.S.		Canada			Argentina		Bolivia		Other Foreign
Three Months Ended 3/31/02 (Restated)
Revenues from external customers	$	45,132	$	24,851		$	44,813	$	3,612	$	—
Intersegment revenues		—		—			—		—		—
Depreciation, depletion and amortization expense		15,561		18,884			12,658		1,173		—
Segment operating income (loss)		3,351		(11,080	)		20,849		1,286		(80	)
Total assets		454,708		814,330			515,888		119,490		21,278
Capital investments		7,236		19,351			7,961		99		588
Long-lived assets		423,686		789,453			471,232		92,414		20,972

	Three Months Ended March 31,
	2003	2002
Production:

Oil (MBbls)—
U.S.	1,556	1,746
Canada	374	528
Argentina(a)	2,526	2,993
Bolivia(b)	19	40
Continuing operations	4,475	5,307
Ecuador	114	264
Total	4,589	5,571

Gas (MMcf)—
U.S.	6,017	5,952
Canada	5,876	7,155
Argentina	2,030	1,502
Bolivia	1,418	2,027
Total	15,341	16,636

MBOE from continuing operations	7,032	8,080
Total MBOE	7,146	8,344

	Three Months Ended March 31,
	2003		2002
Average Sales Price (including impact of hedges):

Oil (per Bbl)—
U.S.	$	26.56	$	18.22
Canada		30.88		17.71
Argentina		28.86		14.75	(a)
Bolivia		22.48		18.17
Continuing operations		28.20		16.21	(a)
Ecuador		26.87		15.42
Total		28.17		16.18	(a)

Gas (per Mcf)—
U.S.	$	4.83	$	2.23
Canada		4.58		2.19
Argentina		.41		.44
Bolivia		1.89		1.43
Total		3.88		1.95

Average Sales Price (excluding impact of hedges):

Oil (per Bbl)—
U.S.	$	31.50	$	17.65
Canada		31.14		17.71
Argentina		28.86		14.82	(a)
Bolivia		22.48		18.17
Continuing operations		29.94		16.06	(a)
Ecuador		26.87		15.42
Total		29.87		16.04	(a)

Gas (per Mcf)—
U.S.	$	5.77	$	2.23
Canada		5.33		2.19
Argentina		.41		.44
Bolivia		1.89		1.43
Total		4.54		1.95

	Gathering/ Plant			Gas Marketing		Corporate			Total
Three Months Ended 3/31/03
Revenues from external customers	$	1,954		$	32,920	$	(3,885	)	$	215,996
Intersegment revenues		—			328		—			328
Depreciation, depletion and amortization expense		(118	)		—		1,053			37,294
Segment operating income (loss)		(524	)		883		(4,938	)		74,034
Total assets		11,682			19,683		141,486			1,901,874
Capital investments		792			—		77			45,291
Long-lived assets		8,985			—		5,339			1,606,376

	2003	2004	2005	2006	2007	There- after			Total			Fair Value at 3/31/03
Long-Term Debt:
Fixed rate (in thousands)	—	—	—	—	—	$	799,416		$	799,416		$	843,152
Average interest rate	—	—	—	—	—		8.5	%		8.5	%		—
Variable rate (in thousands)	—	—	—	—	—		—			—			—
Average interest rate	—	—	—	—	—		—			—			—

99.1		Certificate pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.2		Certificate pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit Number		Description

99.1		Certificate pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.2		Certificate pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.