PATINA OIL & GAS CORP - 10-Q Quarterly 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 Rule 12b-2 of the Exchange Act). Yes x No ¨.

There were 33,815,710 shares of common stock outstanding on August 1, 2003, exclusive of 1,359,292 common shares held in treasury stock.

The financial statements included herein have been prepared in conformity with generally accepted accounting principles. The statements are unaudited but reflect all adjustments, which, in the opinion of management, are necessary to fairly present the Company’s financial position and results of operations. All such adjustments are of a normal recurring nature. All share and per share amounts for all periods have been restated to reflect the 5-for-4 stock split which was effected in the form of a stock dividend to common stockholders of record as of May 27, 2003 with a payment date of June 4, 2003.

Patina Oil & Gas Corporation (the “Company” or “Patina”), a Delaware corporation, was formed in 1996 to hold the assets of Snyder Oil Corporation (“SOCO”) in the Wattenberg Field and to facilitate the acquisition of Gerrity Oil & Gas Corporation (“Gerrity”). In conjunction with the Gerrity acquisition, SOCO received 21.9 million common shares of Patina. In 1997, a series of transactions eliminated SOCO’s ownership in the Company.

In November 2000, Patina acquired various property interests out of bankruptcy. The assets were acquired through Elysium Energy, L.L.C. (“Elysium”), a New York limited liability company, in which Patina held a 50% interest. Patina invested $21.0 million. In January 2003, the Company purchased the remaining 50% interest in Elysium for $23.1 million, comprised of $16.0 million and the assumption of $7.1 million in debt and other liabilities.

In November 2002, Patina acquired Le Norman Energy Corporation (“Le Norman”) for $62.0 million and the issuance of 256,626 shares of common stock. Le Norman’s properties are located primarily in the Anadarko and Ardmore-Marietta Basins of Oklahoma and primarily produce oil. See Note (3).

In December 2002, Patina acquired Bravo Natural Resources, Inc. (“Bravo”) for $119.0 million. Bravo’s properties are primarily located in Hemphill County, Texas and Custer and Caddo Counties of western Oklahoma, within the Anadarko Basin and primarily produce gas. See Note (3).

In March 2003, Patina acquired the remaining 70% interest in Le Norman Partners (“LNP”) for $39.7 million, comprised of $18.5 million and the assumption of $21.2 million of debt and other liabilities. LNP’s properties are located in Stephens, Garvin, and Carter Counties of southern Oklahoma and primarily produce oil.

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Prior to the purchase of the remaining 50% interest in Elysium in January 2003, Patina’s 50% interest in Elysium’s assets, liabilities, revenues and expenses were included in the accounts of the Company on a proportionate consolidation basis. All significant intercompany balances and transactions have been eliminated in consolidation.

The Company’s operations currently consist of the acquisition, development, exploitation and production of oil and gas properties. Historically, Patina’s properties were primarily located in the Wattenberg Field of Colorado’s D-J Basin. Over the past two years, the Company accumulated acreage positions in three Rocky Mountain basins and a small producing field in West Texas in efforts to expand and diversify through grassroots projects (“Grassroots Projects”). Through Elysium, Le Norman, LNP and Bravo and the Grassroots Projects, the Company currently has oil and gas properties in central Kansas, the Illinois Basin, Utah, Wyoming, Texas, and Oklahoma. At December 31, 2002, Wattenberg accounted for approximately 69%, Mid Continent for 25%, Elysium for 5% and the Grassroots Projects for 1% of the PV10 value of proven reserves which totaled $1.5 billion.

The Company utilizes the successful efforts method of accounting for its oil and gas properties. Leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments are charged to expense. Exploratory expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Costs of productive wells, unsuccessful developmental wells and productive leases are capitalized and amortized on a unit-of-production basis over the life of the associated oil and gas reserves. Oil is converted to natural gas equivalents (Mcfe) at the rate of one barrel to six Mcf. Amortization of capitalized costs has generally been provided on a field-by-field basis.

The Company follows the provisions of Statement of Financial Accounting Standards No. 144 (“SFAS No. 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” which requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a field-by-field basis. When the net book value of properties exceeds their undiscounted future cash flows, the cost of the property is written down to “fair value,” which is determined using discounted future cash flows on a field-by field basis. While no impairments have been necessary since 1997, changes in oil and gas prices, underlying assumptions or amortization units could result in impairments in the future.

The Company adopted the provision of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS No. 143”) on January 1, 2003. This statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The asset retirement liability is allocated to operating expense by using a systematic and rational method.

Upon adoption of the statement, the Company recorded an asset retirement obligation of approximately $21.4 million to reflect the Company’s estimated obligations related to the future plugging and abandonment of the Company’s wells. In addition, the Company recorded an addition to oil and gas properties of approximately $17.2 million for the related asset retirement costs, and recorded a one-time, non-cash charge of approximately $2.6 million (net of $1.6 million of deferred taxes) for the cumulative effect of change in accounting principle. At June 30, 2003 an asset retirement obligation of $24.8 million is recorded in Other noncurrent liabilities. This statement would not have had a material impact on the three or six month periods ended June 30, 2002 assuming adoption on a pro forma basis.

Depreciation of field equipment and other is provided using the straight-line method generally ranging from three to ten years.

At December 31, 2002, the balance represented $5.3 million in assets held in a rabbi trust for the benefit of participants under the Company’s deferred compensation plan and $4.6 million representing the value assigned under purchase accounting for the Company’s 30% interest in Le Norman Partners which the Company acquired in conjunction with the Le Norman acquisition. At June 30, 2003, the balance represented $7.2 million in assets held in a rabbi trust for the benefit of participants under the Company’s deferred compensation plan and $805,000 in unamortized loan origination costs. See Notes (3) and (7).

The Company uses the sales method to account for gas imbalances. Under this method, revenue is recognized based on the cash received rather than the Company’s proportionate share of gas produced. Gas imbalances at December 31, 2002 and June 30, 2003 were insignificant.

The Company follows the provisions of SFAS No. 130, “Reporting Comprehensive Income,” which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to the owners of the Company. The Company had no such changes prior to 2001. The components of accumulated other comprehensive income (loss) and related tax effects for the six months ended June 30, 2003 were as follows (in thousands):

Comprehensive income (loss) for the three months ended June 30, 2002 and 2003 totaled $13.6 million and ($6.9) million, respectively. Comprehensive income (loss) for the six months ended June 30, 2002 and 2003 totaled $1.5 million and $265,000, respectively.

The book value and estimated fair value of cash and equivalents was $1.9 million at both December 31, 2002 and June 30, 2003. The book value and estimated fair value of the bank debt was $200.0 million and $239.0 million at December 31, 2002 and June 30, 2003, respectively. The book value of these assets and liabilities approximates fair value due to their short maturity or floating rate structure of these instruments.

The Company regularly enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. The contracts, which are generally placed with major financial institutions or with counter parties which management believes to be of high credit quality, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these contracts are based upon oil and natural gas futures, which have a high degree of historical correlation with actual prices received by the Company. Currently, the Company’s oil and gas swap contracts are designated as cash flow hedges.

The Company entered into various swap contracts for oil based on NYMEX prices for the first six months of 2002 and 2003, recognizing a gain of $1.0 million and a loss of $11.8 million, respectively, related to these contracts. The Company entered into various swap contracts for natural gas based on the Colorado Interstate Gas (“CIG”) index during the first six months of 2002 and 2003, recognizing a gain of $12.5 million and a loss of $8.4 million, respectively, related to these contracts. The Company also entered into various swap contracts for natural gas based on the ANR Pipeline Oklahoma (“ANR”) index during the first six months of 2003, recognizing a loss of $4.0 million related to these contracts.

At June 30, 2003, the Company was a party to swap contracts for oil based on NYMEX prices covering approximately 12,400 barrels of oil per day for the remainder of 2003 at fixed prices ranging from $22.31 to $30.07 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $24.90 per barrel for the remainder of 2003. The Company also entered into swap contracts for oil for 2004 and 2005 as of June 30, 2003, which are summarized in the table below. The net unrealized losses on these contracts totaled $16.2 million based on NYMEX futures prices at June 30, 2003.

At June 30, 2003, the Company was a party to swap contracts for natural gas based on CIG and ANR index prices covering approximately 88,300 MMBtu’s and 16,000 MMBtu’s per day, respectively, for the remainder of 2003 at fixed prices ranging from $2.80 to $4.47 per MMBtu based on CIG and from $3.74 to $4.82 per MMBtu based on ANR. The overall weighted average hedged price for the swap contracts is $3.53 per MMBtu for the remainder of 2003. The Company also entered into natural gas swap contracts for 2004 and 2005 as of June 30, 2003, which are summarized in the table below. The net unrealized losses on these contracts totaled $45.4 million based on CIG and ANR futures prices at June 30, 2003.

At June 30, 2003, the Company was a party to the fixed price swaps summarized below:

The Company follows SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, which establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. It also requires that changes in the derivatives’ 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 income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting treatment. The Company adopted SFAS No. 133 on January 1, 2001.

During the first six months of 2003, net hedging losses of $22.6 million ($14.0 million after tax) were reclassified from Accumulated other comprehensive loss to earnings and the changes in the fair value of outstanding derivative net liabilities increased by $93.3 million ($58.0 million after tax). As the underlying prices in the Company’s hedge contracts were consistent with the indices used to sell their oil and gas, no ineffectiveness was recognized related to its hedge contracts in the first six months of 2003.

As of June 30, 2003, the Company had net unrealized hedging losses of $61.6 million ($38.2 million after tax), comprised of $626,000 of current assets, $2.8 million of non-current assets, $46.9 million of current liabilities and $18.1 million of non-current liabilities. Based on estimated futures prices as of June 30, 2003, the Company would reclassify as a decrease to earnings during the next twelve months $46.3 million ($28.7 million after tax) of net unrealized hedging losses from Accumulated other comprehensive loss.

The Company accounts for its stock-based compensation plans under the principles prescribed by the Accounting Principles Board’s Opinion No. 25 (“APB No. 25”), “Accounting for Stock Issued to Employees.” Stock options awarded under the Employee Plan and the non-employee Directors’ Plan do not result in recognition of compensation expense. See Note (7). The Company accounts for assets held in a rabbi trust for participants under the Company’s deferred compensation plan in accordance with EITF 97-14. See Note (7).

In June 2002, the Company declared a 5-for-4 stock split which was effected in the form of a 25% stock dividend to common stockholders. In June 2003, the Company declared another 5-for-4 stock split which was effected in the form of a 25% stock dividend to common stockholders. All share and per share amounts for all periods have been restated to reflect the 5-for-4 stock splits.

The Company uses weighted average shares outstanding in calculating earnings per share. When dilutive, options and common stock issuable upon conversion of convertible preferred securities are included as share equivalents using the treasury stock method and included in the calculation of diluted earnings per share. See Note (6).

Historically, oil and gas prices have experienced significant fluctuations and have been particularly volatile in recent years. Price fluctuations can result from variations in weather, levels of regional or national production and demand, availability of transportation capacity to other regions of the country and various other factors. Increases or decreases in prices received could have a significant impact on future results.

All liquid investments with a maturity of three months or less are considered to be cash equivalents. Certain amounts in prior period consolidated financial statements have been reclassified to conform with the current classifications. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries and prior to the purchase of the remaining 50% interest in Elysium in January 2003, 50% of the accounts of Elysium. All significant intercompany balances and transactions have been eliminated in consolidation.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities 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. In the opinion of management, those adjustments to the financial statements (all of which are of a normal and recurring nature) necessary to present fairly the Company’s financial position and results of operations have been made. These interim financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

In July 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 146, “Accounting for Costs Associated With Exit or Disposal Activities,” which provides guidance for financial accounting and reporting of costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” This statement requires the recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. The statement was effective for the Company in 2003. The adoption of SFAS No. 146 did not have a material effect on the Company’s financial position or results of operations.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – an amendment of SFAS No. 123.” SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. SFAS No. 148 was effective for the Company’s year ended December 31, 2002. The Company’s adoption of this pronouncement did not have an impact on financial condition or results of operations.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Company does not expect the adoption of this statement to have a material effect on its financial statements.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards for how an issuer measures certain financial instruments with characteristics of both liabilities and equity and requires that an issuer classify a financial instrument within its scope as a liability (or asset in some circumstances). SFAS No. 150 was effective for financial instruments entered into or modified after May 31, 2003 and otherwise was effective and adopted by the Company on July 1, 2003. As the Company has no such instruments, the Company’s adoption of this statement did not have an impact on financial condition or results of operations.

The FASB and representatives of the accounting staff of the Securities and Exchange Commission are currently engaged in discussions regarding the application of certain provisions of SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets,” to companies in the extractive industries, including oil and gas companies. The FASB and the SEC staff are considering whether the provisions of SFAS No. 141 and SFAS No.142 require registrants to classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures.

Historically, the Company has included oil and gas lease acquisition costs as a component of oil and gas properties. In the event the FASB and SEC staff determine that costs associated with mineral rights are required to be classified as intangible assets, a portion of the Company’s oil and gas property acquisition costs may be required to be separately classified on its balance sheets as intangible assets or further described in footnote disclosures. However, the Company currently believes that its results of operations and financial condition would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. The Company does not believe the classification of oil and gas lease acquisition costs as intangible assets would have any impact on the Company’s compliance with covenants under its debt agreements.

On November 5, 2002, Patina acquired the stock of Le Norman Energy Corporation (“Le Norman” or the “Le Norman Acquisition”) for $62.0 million and the issuance of 256,626 shares of common stock. Le Norman’s properties are located primarily in the Anadarko and Ardmore-Marietta Basins of Oklahoma. The Le Norman properties primarily produce oil.

On December 6, 2002, Patina acquired the stock of Bravo Natural Resources, Inc. (“Bravo” or the “Bravo Acquisition”), for $119.0 million. Bravo’s properties are primarily located in Hemphill County, Texas and Custer and Caddo Counties of western Oklahoma, within the Anadarko Basin. The Bravo properties primarily produce gas.

As these acquisitions were recorded using the purchase method of accounting, the results of operations from the acquisitions are included in the results of the Company from the respective acquisition dates. The table below summarizes the preliminary allocation of the purchase price of each transaction based upon the acquisition date fair values of the assets acquired and the liabilities assumed (in thousands):

The following table reflects the unaudited pro forma results of operations for the three and six month periods ended June 30, 2002 as though the acquisitions had occurred on January 1, 2002 (in thousands, except per share amounts):

The pro forma amounts above are presented for information purposes only and are not necessarily indicative of the results which would have occurred had the acquisitions been consummated on January 1, 2002, nor are the pro forma amounts necessarily indicative of future results.

The cost of oil and gas properties at December 31, 2002 and June 30, 2003 included $10.3 million and $9.5 million, respectively, in net unevaluated leasehold and property costs to which proved reserves have not been assigned. These amounts have been excluded from amortization during the respective period. The following table sets forth costs incurred related to oil and gas properties:

In conjunction with the Le Norman and Bravo acquisitions, the Company recorded additions to oil and gas properties of $4.5 million and $40.7 million, respectively, as a result of the deferred tax liability for the difference between the tax basis of the properties acquired and the book basis attributed to the properties under the purchase method of accounting. See Note (3).

During the first quarter of 2003, the Company recorded an addition to oil and gas properties of approximately $17.2 million for the asset retirement costs related to the adoption of SFAS No. 143. During the second quarter of 2003, the Company recorded an addition to oil and gas properties of approximately $252,000 for the estimated asset retirement costs related to new wells drilled.

In January 2003, the Company entered into an Amended Bank Credit Agreement (the “Credit Agreement”). The Credit Agreement is a revolving credit facility in an aggregate amount up to $500.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and equaled $300.0 million at June 30, 2003. Patina had $61.0 million available under the Credit Agreement at June 30, 2003.

The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.25% to 1.90%, or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.65%. The margins are determined by a debt to EBITDA ratio, as defined. The weighted average interest rate under the facility was 2.7% during the first six months of 2003 and 2.6% at June 30, 2003.

The Credit Agreement contains financial covenants, including but not limited to a maximum total debt to EBITDA ratio, as defined, and a minimum current ratio. It also contains negative covenants, including but not limited to restrictions on indebtedness; certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers; changes in fiscal year; transactions with affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge causes; issuance of securities; and non-speculative commodity hedging. At December 31, 2002 and June 30, 2003, the Company was in compliance with the covenants. Borrowings under the Credit Agreement mature in January 2007, but may be prepaid at anytime. The Company had a restricted payment basket under the Credit Agreement of $45.1 million as of June 30, 2003, which may be used to repurchase equity securities, pay dividends or make other restricted payments.

In May 2001, Elysium entered into a bank credit agreement. In January 2003, the Elysium facility was terminated in conjunction with the closing of the acquisition by the Company of the remaining 50% interest in Elysium.

Scheduled maturities of indebtedness for the next five years are zero in 2003, 2004, 2005, 2006 and $239.0 million in 2007. Management intends to extend the maturity of its credit facility on a regular basis; however, there can be no assurance it will be able to do so. Cash payments for interest totaled $1.1 million and $2.8 million during the first six months of 2002 and 2003, respectively.

A total of 156.3 million common shares, $0.01 par value, are authorized of which 35.4 million were issued at June 30, 2003. The common stock is listed on the New York Stock Exchange. Prior to December 1997, no dividends had been paid on common stock. In June 2002, a 5-for-4 stock split was affected in the form of a 25% stock dividend to common stockholders. In June 2003, another 5-for-4 stock split was affected in the form of a 25% stock dividend to common stockholders. All share and per share amounts for all periods have been restated to reflect the 5-for-4 stock splits. Adjusted for the stock dividends, a quarterly cash dividend of $0.0064 per common share was initiated in December 1997, increased to $0.0128 per share in the fourth quarter of 1999, to $0.0256 per share in the fourth quarter of 2000, to $0.032 per share in the fourth quarter of 2001, to $0.04 per share in the second quarter of 2002, to $0.048 per share in the fourth quarter of 2002, and to $0.06 per share in the second quarter of 2003. The Company has a stockholders’ rights plan designed to ensure that stockholders receive full value for their shares in the event of certain takeover attempts. The following is a schedule of the changes in the Company’s shares of common stock since January 1, 2002:

During the first six months of 2003, the Company repurchased and retired 351,900 shares of common stock for $10.1 million.

A total of 5,000,000 preferred shares, $0.01 par value, are authorized with no shares issued or outstanding at December 31, 2002 and June 30, 2003.

The Company follows SFAS No. 128, “Earnings per Share.” The following table specifies the calculation of basic and diluted earnings per share (in thousands except per share amounts):

At June 30, 2003, no options were excluded from the computation of diluted earnings per share because to do so would have been anti-dilutive.

The Company maintains a 401(k) profit sharing and savings plan (the “401(k) Plan”). Eligible employees may make voluntary contributions to the 401(k) Plan. The Company may, at its discretion, make additional matching or profit sharing contributions to the 401(k) Plan. The Company made profit sharing contributions of $647,000 and $801,000 for 2001 and 2002, respectively. The contributions were made in common stock. A total of 37,800 and 30,200 common shares were contributed in 2001 and 2002, respectively.

The Company maintains a shareholder approved stock purchase plan (“Stock Purchase Plan”). Pursuant to the Stock Purchase Plan, officers, directors and certain managers are granted options to purchase shares of common stock at prices ranging from 50% to 85% of the closing price of the stock on the trading day prior to the date of purchase (“Market Price”). To date, all purchase prices have been set at 75% of Market Price. In addition, employee participants may be granted the right to purchase shares pursuant to the Stock Purchase Plan with all or a part of their salary and bonus. A total of 781,250 shares of common stock are reserved for possible purchase under the Stock Purchase Plan. In May 1999, an amendment to the Stock Purchase Plan was approved by the stockholders allowing for the annual renewal of the 781,250 shares of common stock reserved for possible purchase under the Stock Purchase Plan. Plan years run from the date of the Annual Meeting through the next Annual Meeting. In 2002, the Board of Directors approved 221,000 common shares (exclusive of shares available for purchase with participants’ salaries and bonuses) for possible purchase by participants during the plan year. As of December 31, 2002, participants had purchased 279,000 shares of common stock at an average price of $23.85 per share ($17.89 net price per share), resulting in cash proceeds to the Company of $5.0 million. There were no purchases under the Plan in the first six months of 2003. The Company recorded non-cash general and administrative expenses of $1.7 million associated with these purchases for 2002. Participants had no shares available for purchase under the Plan at June 30, 2003 as the Plan was temporarily suspended as of December 31, 2002.

The Company maintains a shareholder approved deferred compensation plan (“Deferred Compensation Plan”). This plan is available to officers and certain managers of the Company. The plan allows participants to defer all or a portion of their salary and annual bonuses (either in cash or Company stock). The Company can make discretionary matching contributions of the participant’s salary deferral and those assets are invested in instruments as directed by the participant. The Deferred Compensation Plan does not have dollar limits on tax-deferred contributions. The assets of the Deferred Compensation Plan are held in a rabbi trust (“Trust”) and, therefore, are available to satisfy the claims of the Company’s creditors in the event of bankruptcy or insolvency of the Company. Participants have the ability to direct the Plan Administrator to invest their salary and bonus deferrals into pre-approved mutual funds held by the Trust. In addition, participants have the right to request that the Plan Administrator re-allocate the portfolio of investments (i.e., cash, mutual funds, Company stock) in the participants’ individual account within the Trust, however, the Plan Administrator is not required to honor any such request. Company matching contributions are in the form of either cash or Company stock and vest ratably over a three-year period. Participants may elect to receive their payments in either cash or the Company’s common stock. At June 30, 2003, the balance of the assets in the Trust totaled $50.9 million, including 1,359,300 shares of common stock of the Company valued at $43.7 million. The Company accounts for the Deferred Compensation Plan in accordance with Emerging Issues Task Force (“EITF”) Abstract 97-14, “Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held in a Rabbi Trust and Invested”.

Assets of the Trust, other than common stock of the Company, are invested in 11 mutual funds that cover the investment spectrum from equities to money market instruments. These mutual funds are publicly quoted and reported at market value. The Company accounts for these investments in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” The Trust also holds common shares of the Company. The Company’s common stock that is held by the Trust has been classified as treasury stock in the stockholders’ equity section of the accompanying balance sheets. The market value of the assets held by the Trust, exclusive of the market value of the shares of the Company’s common stock that are reflected as treasury stock, at December 31, 2002 and June 30, 2003 was $5.3 million and $7.2 million, respectively, and is classified as Other Assets in the accompanying balance sheets. The amounts payable to the plan participants at December 31, 2002 and June 30, 2003, including the market value of the shares of the Company’s common stock that are reflected as treasury stock, was $38.1 million and $50.9 million, respectively, and is classified as Deferred Compensation Liability in the accompanying balance sheets.

In accordance with EITF 97-14, all market fluctuations in value of the Trust assets have been reflected in the respective income statements. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of the Company, have been included as Other income in the respective income statements. Increases or decreases in the market value of the deferred compensation liability, including the shares of common stock of the Company held by the Trust, while recorded as treasury stock, are included as Deferred compensation adjustments in the respective income statement. In response to the changes in total market value of the Trust, the Company recorded deferred compensation adjustments of $6.1 million and $9.9 million in the first six months of 2002 and 2003, respectively.

The Company maintains a shareholder approved stock option plan for employees (the “Employee Plan”) providing for the issuance of options at prices not less than fair market value at the date of grant. Options to acquire the greater of 4.7 million shares of common stock or 10% of outstanding diluted common shares may be outstanding at any time. The specific terms of grant and exercise are determinable by the Compensation Committee of the Board of Directors. The options vest over a three-year period (30%, 60%, 100%) and expire five years from the date of grant. The following is a summary of stock options granted under the Employee Plan:

The Company also maintains a shareholder approved stock grant and option plan for non-employee Directors (the “Directors’ Plan”). The Directors’ Plan provides for each non-employee Director to receive an annual retainer of $20,000, an attendance fee of $5,000 for each meeting of the Board of Directors, and a $1,000 fee for attendance of each meeting of a committee of the Board of Directors. The total quarterly director fee, including retainer, attendance and committees fees is payable quarterly with common shares having a market value equal to one-half of their quarterly fee and the remainder in cash. A total of 2,900 shares were issued in 2002 and 1,700 in the first six months of 2003. It also provides for 7,800 options to be granted to each non-employee Director upon appointment and upon annual re-election, thereafter. The options vest over a three-year period (30%, 60%, 100%) and expire five years from the date of grant. The following is a summary of stock options granted under the Directors’ Plan:

The Company applies APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations in accounting for the plans. As all stock options have been issued at the market price on the date of grant, no compensation cost has been recognized for these stock option plans. Had compensation cost for the Company’s stock option plans been determined consistent with SFAS No. 123, “Accounting for Stock-Based Compensation,” the Company’s net income (in thousands) and earnings per share would have been reduced to the pro forma amounts indicated below for the three and six month periods ended June 30, 2002 and 2003, respectively:

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants for the first three months of 2002 and 2003: dividend yield of 0.8% and 0.8%; expected volatility of 46% and 45%; risk-free interest rate of 4.2% and 2.3%; and expected life of 3.8 years and 3.8 years, respectively. The following weighted-average assumptions were used for grants for the first six months of 2002 and 2003: dividend yield of 0.8% and 0.7%; expected volatility of 46% and 45%; risk-free interest rate of 4.2% and 2.7%; and expected life of 3.8 years and 3.7 years, respectively.

A reconciliation of the federal statutory rate to the Company’s effective rate as it applies to the tax provision for the six months ended June 30, 2002 and 2003 follows:

Current income tax expense in the six months ended June 30, 2002 and 2003 totaled $4.3 million and $10.8 million, respectively. The Company expects to utilize approximately $13.6 million of net operating loss carryforwards to reduce its 2002 tax liability.

For tax purposes, the Company had net operating loss carryforwards of approximately $72.6 million at December 31, 2002. Utilization of these losses will be limited to a maximum of approximately $9.8 million per year as a result of the Le Norman, Bravo and earlier acquisitions. These carryforwards expire from 2005 through 2021. The Company has provided a valuation allowance of $3.6 million against the loss carryforwards that could expire unutilized. At December 31, 2002, the Company had AMT credit carryforwards of approximately $14.2 million that are available indefinitely. The Company paid $2.7 million and $8.1 million in federal and state income taxes during the six months ended June 30, 2002 and 2003, respectively.

During the six months ended, June 30, 2002 and 2003, Duke Energy Field Services, Inc. accounted for 37% and 23%, BP Amoco Production Company accounted for 7% and 14%, Conoco accounted for 8% and 10%, and E-Prime accounted for 9% and 3%, of revenues, respectively. Accounts receivable amounts from these customers at December 31, 2002 totaled $15.2 million. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

Patina provided certain administrative services to Elysium under an operating agreement. The Company was paid $1.5 million for these services in the first six months of 2002. As the Company purchased the remaining 50% interest in Elysium in January 2003, there were no indirect monthly reimbursements during the six months ended June 30, 2003.

The Company leases office space and certain equipment under non-cancelable operating leases. Future minimum lease payments under such leases approximate $1.2 million per year from 2003 through 2006.

The Company is a party to various lawsuits incidental to its business, none of which are anticipated to have a material adverse impact on its financial position or results of operations.

A recent ruling by the Colorado Supreme Court limiting the deductibility of certain post-production costs to be borne by royalty interest owners has resulted in uncertainty of these deductions insofar as they relate to the Company’s Colorado operations. The Company has been named as a party to a related lawsuit which plaintiff seeks to certify as a class action. The Company filed a response to the lawsuit and intends to vigorously defend the action. Any potential liability from this claim cannot currently be reasonably estimated, and no provision has been accrued for this matter in the Company’s financial statements.

The Company’s discussion and analysis of its financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements. The Company recognizes revenues from the sale of oil and gas in the period delivered. We provide an allowance for doubtful accounts for specific receivables we judge unlikely to be collected. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments in value are charged to expense. Exploratory expenses, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Costs of productive wells, unsuccessful developmental wells and productive leases are capitalized and amortized on a unit-of-production basis through depletion, depreciation and amortization expense over the life of the associated oil and gas reserves. Oil and gas property costs are periodically evaluated for possible impairment. Impairments are recorded when management believes that a property’s net book value is not recoverable based on current estimates of expected future cash flows. Depletion, depreciation and amortization of oil and gas properties and the periodic assessments for impairment are based on underlying oil and gas reserve estimates and future cash flows using then current oil and gas prices combined with operating and capital development costs. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The Company regularly enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. The contracts, which are generally placed with major financial institutions or with counter parties which management believes to be of high credit quality, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these contracts are based upon oil and natural gas futures, which have a high degree of historical correlation with actual prices received by the Company. Currently, all of the Company’s oil and gas swap contracts are designated as cash flow hedges.

During the six months ended June 30, 2003, the Company spent $74.5 million on the further development of properties and $67.3 million on acquisitions. The acquisition expenditures included $23.1 million and $39.7 million on the Elysium and the Le Norman Partners acquisitions, respectively. The development expenditures included $45.9 million in Wattenberg for the drilling or deepening of 28 J-Sand wells, 252 Codell refracs, eight recompletions and the drilling of 14 Codell wells, $29.9 million on the further development of the Mid Continent (Le Norman, Le Norman Partners and Bravo properties) and other properties for the drilling or deepening of 143 wells and performing 42 recompletions. These acquisitions and projects, and the continued success in production enhancement allowed production to increase 42% over the prior year six month period. The Company anticipates incurring approximately $150.0 million on the further development of its properties during 2003. The decision to increase or decrease development activity is heavily dependent on the prices being received for production.

At June 30, 2003, the Company had $859.6 million of assets. Total capitalization was $533.2 million, of which 55% was represented by stockholders’ equity and 45% by bank debt. During the first six months of 2003, net cash provided by operations totaled $113.7 million, as compared to $60.9 million in 2002 ($125.5 million and $74.0 million prior to changes in working capital, respectively). At June 30, 2003, there were no significant commitments for capital expenditures. Based upon a $150.0 million capital budget for 2003, the Company expects production to continue to increase in the coming year. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. The Company plans to finance its ongoing development, acquisition and exploration expenditures and additional equity repurchases using internal cash flow, proceeds from asset sales and bank borrowings. In addition, joint ventures or future public and private offerings of debt or equity securities may be utilized.

The Company’s primary cash requirements will be to finance acquisitions, fund development expenditures, repurchase equity securities, repay indebtedness, and general working capital needs. However, future cash flows are subject to a number of variables, including the level of production and oil and gas prices, and there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken.

The Company believes that borrowings available under its Credit Agreement, projected operating cash flows and the cash on hand will be sufficient to cover its working capital, capital expenditures, planned development activities and debt service requirements for the next 12 months. In connection with consummating any significant acquisition, additional debt or equity financing will be required, which may or may not be available on terms that are acceptable to the Company.

The following summarizes the Company’s contractual obligations at June 30, 2003 and the effect such obligations are expected to have on its liquidity and cash flow in future periods (in thousands):

The following summarizes the Company’s borrowings and availability under Patina’s revolving credit facility (in thousands):

The Company’s principal sources of cash are operating cash flow and bank borrowings. The Company’s cash flow is highly dependent on oil and gas prices. Pricing volatility will be somewhat reduced as the Company has entered into hedging agreements for 2003, 2004 and 2005. The $74.5 million of development expenditures for the first six months of 2003 was funded entirely with internal cash flow. The 2003 development capital budget of $150.0 million, comprised primarily of $90.9 million of development expenditures in Wattenberg, $42.6 million in the Mid Continent region, and $8.7 million on the Elysium properties, is expected to increase production by over 30%. The budgeted capital and production growth estimates include capital for the Elysium properties acquired in January 2003 and the LNP properties acquired in March 2003. The purchase price for the Elysium acquisition was $23.1 million and the purchase price for the LNP properties was $39.7 million. The Company expects the development program to be funded with internal cash flow. As such, exclusive of any other acquisitions or significant equity repurchases, management expects to reduce long-term debt in 2003.

Net cash provided by operating activities in the six months ended June 30, 2002 and 2003 was $60.9 million and $113.7 million, respectively. Cash flow from operations increased in 2003 due to the 42% and 29% increases in oil and gas production and prices, respectively. Lease operating expenses, general and administrative expenses and interest expense all increased as a result of the acquisitions made in the fourth quarter of 2002 (Le Norman and Bravo) and the first quarter of 2003 (Elysium and Le Norman Partners). Operating cash flows in the first six months of 2002 and 2003 were benefited by $3.5 million and $4.7 million related to the tax deduction generated from the exercise and same day sale of stock options.

Net cash used in investing activities in the six months ended June 30, 2002 and 2003 totaled $42.9 million and $143.9 million, respectively. Acquisition, development and exploration expenditures totaled $143.9 million in the first six months of 2003 compared to $43.5 million in 2002. The increase in expenditures in the first six months of 2003 was primarily due to the Company incurring $63.4 million of acquisition costs related to Elysium and Le Norman Partner acquisitions and the $19.5 million of development expenditures spent on the Mid Continent properties acquired in the fourth quarter of 2002. Development expenditures in Wattenberg increased to $45.9 million in the first six months of 2003 as compared to $39.4 million in the first six months of 2002.

Net cash used in financing activities in the six months ended June 30, 2002 totaled $17.7 million, while net cash provided by financing activities in the six months ended June 30, 2003 totaled $30.3 million. Sources of financing have been primarily bank borrowings. During the first six months of 2002, the combination of operating cash flow and $9.8 million in proceeds from the exercise of stock options, allowed the Company to repay $25.0 million of bank debt and fund capital development and acquisition expenditures of $43.5 million. During the first six months of 2003, the combination of operating cash flow, bank borrowings of $39.0 million and$6.2 million in proceeds from the exercise of stock options, allowed the Company to fund capital development and acquisition expenditures of $143.9 million and buy back $10.1 million in common stock.

During the first six months of 2003, $143.9 million of capital was expended, including $74.5 million on development projects and $67.3 million on acquisitions. Development expenditures represented approximately 59% of internal cash flow (defined as net cash provided by operations before changes in working capital). The Company manages its capital budget with the goal of funding it with internal cash flow. The 2003 development capital budget of $150.0 million combined with the benefits of the acquisitions made in the fourth quarter of 2002 and the first quarter of 2003 is expected to increase production by over 30%. The Company expects the development capital program to be funded with internal cash flow. The purchase price for the Elysium acquisition was $23.1 million and the purchase price for the LNP properties was $39.7 million. As such, exclusive of any other acquisitions or significant equity repurchases, management expects to reduce long-term debt in 2003. Development and exploration activities are highly discretionary, and, for the foreseeable future, management expects such activities to be maintained at levels equal to or below internal cash flow.

The Company regularly enters into hedging agreements to reduce the impact on its operations of fluctuations in oil and gas prices. All such contracts are entered into solely to hedge prices and limit volatility. The Company’s current policy is to hedge between 50% and 75% of its production, when futures prices justify, on a rolling twelve to twenty-four month basis. At June 30, 2003, hedges were in place covering 70.9 Bcf at prices averaging $3.70 per MMBtu and 8.5 million barrels of oil averaging $24.40 per barrel. The estimated fair value of the Company’s hedge contracts that would be realized on termination, approximated a net unrealized pre-tax loss of $61.6 million ($38.2 million loss net of $23.4 million of deferred taxes) at June 30, 2003, which is presented on the balance sheet as a current asset of $626,000, a non-current asset of $2.8 million, a current liability of $46.9 million, and a non-current liability of $18.1 million based on contract expiration. The oil and gas contracts expire monthly through December 2005. Gains or losses on both realized and unrealized hedging transactions are determined as the difference between the contract price and a reference price, generally NYMEX for oil and the Colorado Interstate Gas (“CIG”) index or ANR Pipeline Oklahoma (“ANR”) index for natural gas. Transaction gains and losses are determined monthly and are included as increases or decreases in oil and gas revenues in the period the hedged production is sold. Any ineffective portion of such hedges is recognized in earnings as it occurs. Net pre-tax gains relating to these derivatives were $13.6 million in the six months ended June 30, 2002 and net pre-tax hedging losses were $24.2 million in the six months ended June 30, 2003. Effective January 1, 2001, the unrealized gains (losses) on these hedging positions were recorded at an estimate of fair value which the Company based on a comparison of the contract price and a reference price, generally NYMEX or CIG, on the Company’s balance sheet in Accumulated other comprehensive income (loss), a component of Stockholders’ Equity.

While certain costs are affected by the general level of inflation, factors unique to the oil and gas industry result in independent price fluctuations. Over the past five years, significant fluctuations have occurred in oil and gas prices. Although it is particularly difficult to estimate future prices of oil and gas, price fluctuations have had, and will continue to have, a material effect on the Company.

The following table indicates the average oil and gas prices received over the last five years and highlights the price fluctuations by quarter for 2002 and 2003. Average price computations exclude hedging gains and losses and other nonrecurring items to provide comparability. Average prices per Mcfe indicate the composite impact of changes in oil and natural gas prices. Oil production is converted to natural gas equivalents at the rate of one barrel per six Mcf.

Three months ended June 30, 2003 compared to the three months ended June 30, 2002.

Revenues for the second quarter of 2003 totaled $92.4 million, an 82% increase from the prior year period. Net income for the second quarter of 2003 totaled $20.3 million compared to $12.4 million in 2002. The increases in revenue and net income were due to higher oil and gas prices and production.

Average daily oil and gas production in the second quarter of 2003 totaled 16,165 barrels and 168.3 MMcf (265.3 MMcfe), an increase of 46% on an equivalent basis from the same period in 2002. The rise in production was due to the continued development activity in Wattenberg, the benefits of the Le Norman and Bravo acquisitions made in the fourth quarter of 2002, and the Elysium and LNP acquisitions made in January and March of 2003, respectively. During the second quarter of 2003, 22 wells were drilled or deepened and 120 refracs and five recompletions were performed in Wattenberg, compared to 17 new wells or deepenings and 122 refracs in Wattenberg in 2002. During the second quarter of 2003, the Company drilled or deepened 85 wells and performed 30 recompletions on its Mid Continent and other properties, compared to 8 new drills or deepenings and 15 recompletions in 2002. Based upon a $150.0 million development budget for 2003 combined with the benefits of the acquisitions made in the fourth quarter of 2002 and the first quarter of 2003, the Company expects production to increase over 30% from 2002.

Average oil prices increased 3% from $24.96 per barrel in the second quarter of 2002 to $25.60 in 2003. Average gas prices increased 30% from $2.68 per Mcf in the second quarter of 2002 to $3.48 in 2003. Average oil prices include hedging losses of $582,000 or $0.76 per barrel and $3.8 million or $2.58 per barrel in the second quarters of 2002 and 2003, respectively. Average gas prices included hedging gains of $5.1 million or $0.43 per Mcf in the second quarter of 2002 and hedging losses of $8.2 million or $0.54 per Mcf in 2003. Lease operating expenses totaled $13.9 million or $0.58 per Mcfe for the second quarter of 2003 compared to $6.6 million or $0.40 per Mcfe in the prior year period. The increase in operating expenses was primarily attributed to additional operating expenses incurred as a result of increasing oil production associated with the recent acquisitions. Production taxes totaled $6.4 million or $0.27 per Mcfe in the second quarter of 2003 compared to $2.9 million in 2002 or $0.17 per Mcfe. The $3.5 million increase was a result of higher oil and gas prices and production.

General and administrative expenses for the second quarter of 2003 totaled $4.2 million, an increase of $784,000 or 23% over the same period in 2002. The increase was largely attributable to additional employees hired in conjunction with the Le Norman and Bravo acquisitions made in the fourth quarter of 2002.

Interest and other expenses increased to $1.9 million in the second quarter of 2003, an increase of 213% from the prior year period. Interest expense increased as a result of higher average debt balances in conjunction with the acquisitions made in late 2002 and early 2003, somewhat offset by lower average interest rates. The Company’s average interest rate during the second quarter of 2003 was 2.7% compared to 3.1% in 2002.

Deferred compensation adjustment totaled $8.9 million in the second quarter of 2003, an increase of $7.1 million from the prior year period. The increase relates to the increase in value of the Company’s common shares and other investments held in a rabbi trust for the benefit of participants in the Company’s deferred compensation plan over 2002. The Company’s common stock price appreciated by 22% or $5.83 per share in the second quarter of 2003 versus an increase of 9% or $1.77 per share in the second quarter of 2002.

Depletion, depreciation and amortization expense for the second quarter of 2003 totaled $23.3 million, an increase of $7.1 million or 44% from 2002. Depletion expense totaled $22.3 million or $0.92 per Mcfe for the second quarter of 2003 compared to $15.8 million or $0.96 per Mcfe for 2002. The increase in depletion expense resulted from the 46% increase in oil and gas production in the second quarter of 2003, somewhat offset by a lower depletion rate. Depreciation and amortization expense for the three months ended June 30, 2003 totaled $653,000 or $0.03 per Mcfe, compared to $324,000 or $0.02 per Mcfe in the second quarter of 2002. Accretion expense related to SFAS No. 143 totaled $318,000 in the second quarter of 2003 compared to zero in the first quarter of 2002 as the statement was not effective until January 1, 2003.

Provision for income taxes for the second quarter of 2003 totaled $12.4 million, an increase of $5.8 million from the same period in 2002. The increase was due to higher earnings and an increase in the effective tax rate. The Company recorded a 38% tax provision for the second quarter of 2003 compared to a 35% tax provision in 2002. The increase in the effective tax rate was due to the expiration of Section 29 tax credits as of December 31, 2002.

Six months ended June 30, 2003 compared to the six months ended June 30, 2002.

Revenues for the first six months of 2003 totaled $182.4 million, a 78% increase from the prior year period. Net income for the first six months of 2003 totaled $44.3 million compared to $25.5 million in 2002. The increases in revenue and net income were due to higher oil and gas prices and production.

Average daily oil and gas production in the first six months of 2003 totaled 14,782 barrels and 164.4 MMcf (253.1 MMcfe), an increase of 42% on an equivalent basis from the same period in 2002. The rise in production was due to the continued development activity in Wattenberg, the benefits of the Le Norman and Bravo acquisitions made in the fourth quarter of 2002, and the Elysium and LNP acquisitions made in January and March of 2003, respectively. During the first six months of 2003, 42 wells were drilled or deepened and 252 refracs and eight recompletions were performed in Wattenberg, compared to 22 new wells or deepenings and 229 refracs and three recompletions in Wattenberg in 2002. During the first six months of 2003, the Company drilled or deepened 143 wells and performed 42 recompletions on its Mid Continent and other properties, compared to 11 new drills or deepenings and 19 recompletions for the same period in 2002. Based upon a $150.0 million development budget for 2003, the Company expects production to continue to increase over 30% from 2002.

Average oil prices increased 8% from $24.13 per barrel in the first six months of 2002 to $26.11 in 2003. Average gas prices increased 38% from $2.69 per Mcf in the first six months of 2002 to $3.72 in 2003. Average oil prices include hedging gains of $1.0 million or $0.70 per barrel in the first six months of 2002 and hedging losses of $11.8 million or $4.39 per barrel in 2003. Average gas prices included hedging gains of $12.5 million or $0.53 per Mcf in the first six months of 2002 and hedging losses of $12.4 million or $0.42 per Mcf in 2003. Lease operating expenses totaled $24.6 million or $0.54 per Mcfe for the first six months of 2003 compared to $13.7 million or $0.42 per Mcfe in the prior year period. The increase in operating expenses was primarily attributed to additional operating expenses incurred as a result of increasing oil production associated with the recent acquisitions. Production taxes totaled $12.9 million or $0.28 per Mcfe in the first six months of 2003 compared to $4.9 million in 2002 or $0.15 per Mcfe. The $8.0 million increase was a result of higher oil and gas prices and production.

General and administrative expenses for the first six months of 2003 totaled $8.7 million, an increase of $2.6 million or 44% over the same period in 2002. The increase was largely attributed to additional employees hired in conjunction with the Le Norman and Bravo acquisitions made in the fourth quarter of 2002.

Interest and other expenses increased to $4.1 million in the first six months of 2003, an increase of 228% from the prior year period. Interest expense increased as a result of higher average debt balances in conjunction with the acquisitions made in late 2002 and early 2003, somewhat offset by lower average interest rates. The Company’s average interest rate during the first six months of 2003 was 2.7% compared to 3.1% in 2002.

Deferred compensation adjustment totaled $9.9 million in the first six months of 2003, an increase of $3.9 million from the prior year period. The increase relates to the increase in value of the Company’s common shares and other investments held in a rabbi trust for the benefit of participants in the Company’s deferred compensation plan over 2002. The Company’s common stock price appreciated by 27% or $6.83 per share in the first six months of 2003 versus an increase of 25% or $4.34 per share during the first six months of 2002.

Depletion, depreciation and amortization expense for the first six months of 2003 totaled $44.4 million, an increase of $13.4 million or 43% from 2002. Depletion expense totaled $42.5 million or $0.93 per Mcfe for the first six months of 2003 compared to $30.3 million or $0.94 per Mcfe for 2002. The increase in depletion expense resulted from the 42% increase in oil and gas production in the first six months of 2003, somewhat offset by a lower depletion rate. Depreciation and amortization expense for the six months ended June 30, 2003 totaled $1.2 million or $0.03 per Mcfe compared to $633,000 or $0.02 per Mcfe in the first six months of 2002. Accretion expense related to SFAS No. 143 totaled $628,000 in the first six months of 2003 compared to zero in the first six months of 2002 as the statement was not effective until January 1, 2003.

Provision for income taxes for the first six months of 2003 totaled $28.7 million, an increase of $15.0 million from the same period in 2002. The increase was due to higher earnings and an increase in the effective tax rate. The Company recorded a 38% tax provision for the first six months of 2003 compared to a 35% tax provision in 2002. The increase in the effective tax rate was due to the expiration of Section 29 tax credits as of December 31, 2002.

The Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” on January 1, 2003. The cumulative effect of change in accounting principle of $2.6 million (net of $1.6 million deferred taxes) in the first six months of 2003 reflects accretion that would have been recorded if the Company had always been under the requirements of SFAS No. 143.

In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated With Exit or Disposal Activities,” which provides guidance for financial accounting and reporting of costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” This statement requires the recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF No. 94-3. The statement was effective for the Company in 2003. The adoption of SFAS No. 146 did not have a material effect on the Company’s financial position or results of operations.

The Company’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing domestic price for oil and spot prices applicable to the Rocky Mountain and Mid Continent regions for its natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Natural gas price realizations during 2002 and the first six months of 2003, exclusive of any hedges, ranged from a monthly low of $1.59 per Mcf to a monthly high of $5.37 per Mcf. Oil prices, exclusive of any hedges, ranged from a monthly low of $18.74 per barrel to a monthly high of $35.15 per barrel during 2002 and the first six months of 2003. A significant decline in prices of oil or natural gas could have a material adverse effect on the Company’s financial condition and results of operations.

In the first six months of 2003, a 10% reduction in oil and gas prices, excluding oil and gas quantities that were fixed through hedging transactions, would have reduced revenues by $6.9 million. If oil and gas future prices at June 30, 2003 had declined by 10%, the net unrealized hedging losses at that date would have decreased by $53.1 million (from a $61.6 million loss to a $8.5 million loss).

At June 30, 2003, the Company was a party to the fixed price swaps summarized below:

At June 30, 2003, the Company had $239.0 million outstanding under its credit facility at an average interest rate of 2.6%. The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.25% to 1.90% or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.65%. The weighted average interest rate under the facility approximated 2.7% during the first six months of 2003. Assuming no change in the amount outstanding at June 30, 2003, the annual impact on interest expense of a ten percent change in the average interest rate would be approximately $407,000, net of tax. As the interest rate is variable and is reflective of current market conditions, the carrying value approximates the fair value.

Certain information included in this report, other materials filed or to be filed by the Company with the Securities and Exchange Commission (“SEC”), as well as information included in oral statements or other written statements made or to be made by the Company contain or incorporate by reference certain statements (other than statements of historical or present fact) that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.

All statements, other than statements of historical or present facts, that address activities, events, outcomes or developments that the Company plans, expects, believes, assumes, budgets, predicts, forecasts, estimates, projects, intends or anticipates (and other similar expressions) will or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-Q and presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002. Such forward-looking statements appear in a number of places and include statements with respect to, among other things, such matters as: future capital, development and exploration expenditures (including the amount and nature thereof), drilling, deepening or refracing of wells, oil and gas reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), estimates of future production of oil and natural gas, expected results or benefits associated with recent acquisitions, business strategies, expansion and growth of the Company’s operations, cash flow and anticipated liquidity, grassroots prospects and development and property acquisitions, obtaining financial or industry partners for prospect or program development, or marketing of oil and natural gas. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and gas. These risks include but are not limited to: general economic conditions, the market price of oil and natural gas, the risks associated with exploration, the Company’s ability to find, acquire, market, develop and produce new properties, operating hazards attendant to the oil and gas business, uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures, the strength and financial resources of the Company’s competitors, the Company’s ability to find and retain skilled personnel, climatic conditions, labor relations, availability and cost of material and equipment, environmental risks, the results of financing efforts, regulatory developments and the other risks described in this Form 10-Q and presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, these revisions could change the schedule of any further production and/or development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q or presented in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002 occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

The Company’s principal executive officer and principal financial officer have evaluated the effectiveness of the Company’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this report (the “Evaluation Date”). Based upon their evaluation, the principal executive officer and principal financial officer concluded that, as of the Evaluation Date, the Company’s disclosure controls and procedures are effective. During the Company’s most recent fiscal quarter, there were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Information with respect to this item is incorporated by reference from Notes to Consolidated Financial Statements in Part 1 of this report.

On May 22, 2003 the Annual Meeting of the Company’s common stockholders was held. A summary of the proposals upon which a vote was taken and the results of the voting were as follows (the votes were adjusted to reflect the 5-for-4 stock split effective June 4, 2003):

(a) Exhibits—The following documents are filed as exhibits to this Quarterly Report on Form 10-Q:

(b) The following reports on Form 8-K were filed by Registrant during the quarter ended June 30, 2003:

The Company filed a current report on Form 8-K on May 1, 2003 to furnish the information required under Item 12 related to the Company’s April 30, 2003 press release announcing the Company’s financial results for the three months ended March 31, 2003.

The Company filed a current report on Form 8-K on May 2, 2003 to furnish the certifications of the Chief Executive Officer and the Chief Financial Officer which accompanied the Company’s Quarterly Report on Form 10-Q for the three months ended March 31, 2003 pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

The Company filed a current report on Form 8-K on May 15, 2003 to announce that its Board of Directors had approved a 25% stock dividend to be paid on June 4, 2003 to stockholders of record at the close of business on May 27, 2003 (effected in the form of a 5-for-4 split).

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.

PATINA OIL & GAS CORPORATION

By:		/s/ DAVID J. KORNDER
		David J. Kornder, Executive Vice President and Chief Financial Officer

Title of class		Name of exchange on which listed
Common Stock, $.01 par value		New York Stock Exchange

	December 31, 2002			June 30, 2003
				(Unaudited)
ASSETS
Current assets
Cash and equivalents	$	1,920		$	1,928
Accounts receivable		33,555			48,591
Inventory and other		5,453			12,459
Deferred income taxes		—			17,576
Unrealized hedging gains		8,294			626

		49,222			81,180

Unrealized hedging gains		15,558			2,751
Oil and gas properties, successful efforts method		1,104,205			1,267,742
Accumulated depletion, depreciation and amortization		(466,947	)		(508,781	)

		637,258			758,961

Field equipment and other		12,194			14,588
Accumulated depreciation		(5,087	)		(6,104	)

		7,107			8,484

Other assets		9,945			8,264

	$	719,090		$	859,640

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	41,773		$	54,845
Accrued liabilities		14,298			15,848
Unrealized hedging losses		13,001			46,878

		69,072			117,571

Senior debt		200,000			239,000
Deferred income taxes		96,569			101,851
Other noncurrent liabilities		15,012			37,991
Unrealized hedging losses		1,787			18,118
Deferred compensation liability		38,070			50,949
Commitments and contingencies
Stockholders’ equity
Preferred Stock, $.01 par, 5,000,000 shares authorized, none issued		—			—

Common Stock, $.01 par, 156,250,000 shares authorized, 35,162,233 and 35,413,302 shares issued		352			354

Less Common Stock Held in Treasury, at cost, 1,295,339 and 1,359,292 shares		(6,817	)		(8,716	)
Capital in excess of par value		175,537			176,584
Retained earnings		123,707			164,142
Accumulated other comprehensive income (loss)		5,801			(38,204	)

		298,580			294,160

	$	719,090		$	859,640

	Three Months Ended June 30,					Six Months Ended June 30,
	2002			2003		2002		2003
Revenues
Oil and gas sales	$	50,948		$	90,952	$	98,956	$	180,482
Other		(255	)		1,466		3,623		1,903

		50,693			92,418		102,579		182,385

Expenses
Lease operating		6,582			13,948		13,736		24,646
Production taxes		2,877			6,407		4,933		12,892
Exploration		184			1,036		348		2,169
General and administrative		3,453			4,237		6,046		8,683
Interest and other		618			1,937		1,252		4,102
Deferred compensation adjustment		1,752			8,861		6,069		9,919
Depletion, depreciation and amortization		16,169			23,270		30,964		44,357

		31,635			59,696		63,348		106,768

Pre-tax income		19,058			32,722		39,231		75,617

Provision for income taxes
Current		1,563			4,663		4,307		10,775
Deferred		5,108			7,771		9,460		17,959

		6,671			12,434		13,767		28,734

Net income before change in accounting principle	$	12,387		$	20,288	$	25,464	$	46,883
Cumulative effect of change in accounting principle		—			—		—		(2,613	)

Net Income	$	12,387		$	20,288	$	25,464	$	44,270

Net income per share before cumulative effect of change in accounting principle
Basic	$	0.38		$	0.59	$	0.78	$	1.38

Diluted	$	0.36		$	0.57	$	0.75	$	1.32

Net loss per share from cumulative effect of change in accounting principle
Basic	$	0.00		$	0.00	$	0.00	$	(0.08	)

Diluted	$	0.00		$	0.00	$	0.00	$	(0.08	)

Net income per share
Basic	$	0.38		$	0.59	$	0.78	$	1.30

Diluted	$	0.36		$	0.57	$	0.75	$	1.24

Weighted average shares outstanding
Basic		32,785			34,158		32,526		34,052

Diluted		34,614			35,850		34,158		35,616

	Six Months Ended June 30,
	2002			2003
Operating activities
Net income	$	25,464		$	44,270
Adjustments to reconcile net income to net cash provided by operations
Cumulative effect of change in accounting principle, net of tax		—			2,613
Exploration expense		348			2,169
Depletion, depreciation and amortization		30,964			44,357
Deferred income taxes		9,460			17,959
Tax benefit from stock options		3,472			4,657
Deferred compensation adjustment		6,069			9,919
Loss (gain) on deferred compensation asset		536			(734	)
Reversal of hedging impairment, net		(2,340	)		—
Other		69			268
Changes in working capital and other assets and liabilities
Decrease (increase) in
Accounts receivable		873			(10,895	)
Inventory and other		(450	)		(5,615	)
Increase (decrease) in
Accounts payable		131			8,610
Accrued liabilities		(3,957	)		(2,523	)
Other assets and liabilities		(9,698	)		(1,390	)

Net cash provided by operations		60,941			113,665

Investing activities
Development and exploration		(43,499	)		(76,626	)
Acquisitions, net of cash acquired		—			(67,289	)
Disposition of oil and gas properties		2,088			1,719
Other		(1,457	)		(1,717	)

Net cash used by investing		(42,868	)		(143,913	)

Financing activities
Increase (decrease) in indebtedness		(25,000	)		39,000
Loan origination fees		—			(1,074	)
Issuance of common stock		9,768			6,233
Repurchase of common stock		(9	)		(10,068	)
Common dividends		(2,454	)		(3,835	)

Net cash provided (used) by financing		(17,695	)		30,256

Increase in cash		378			8
Cash and equivalents, beginning of period		250			1,920

Cash and equivalents, end of period	$	628		$	1,928

	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive income – 12/31/02	$	9,064		$	(3,263	)	$	5,801
Change in fair value of hedges		(93,278	)		35,265			(58,013	)
Contract settlements during the six months		22,594			(8,586	)		14,008

Accumulated other comprehensive loss – 06/30/03	$	(61,620	)	$	23,416		$	(38,204	)

	Preferred Stock		Common Stock					Treasury			Capital in Excess of			Retained			Accumulated Other Comprehensive Income
	Amount		Shares		Amount			Stock			Par Value			Earnings			(Loss)			Total
Balance, December 31, 2001	$	—	33,191		$	332		$	(5,866	)	$	146,234		$	71,513		$	37,361		$	249,574
Repurchase of common		—	—			—			—			(9	)		—			—			(9	)
Issuance of common stock		—	1,971			20			—			22,996			—			—			23,016
Deferred compensation stock issued, net		—	—			—			(951	)		2,820			—			—			1,869
Tax benefit from stock options		—	—			—			—			3,496			—			—			3,496
Dividends		—	—			—			—			—			(5,513	)		—			(5,513	)
Comprehensive income:
Net income		—	—			—			—			—			57,707			—			57,707
Contract settlements reclassed to income		—	—			—			—			—			—			(11,953	)		(11,953	)
Change in unrealized hedging gains		—	—			—			—			—			—			(19,607	)		(19,607	)

Total comprehensive income		—	—			—			—			—			57,707			(31,560	)		26,147

Balance, December 31, 2002		—	35,162			352			(6,817	)		175,537			123,707			5,801			298,580

Issuance of common stock		—	603			6			—			6,274			—			—			6,280
Repurchase of common		—	(352	)		(4	)		—			(10,064	)		—			—			(10,068	)
Deferred compensation stock issued, net		—	—			—			(1,899	)		180			—			—			(1,719	)
Tax benefit from stock options		—	—			—			—			4,657			—			—			4,657
Dividends		—	—			—			—			—			(3,835	)		—			(3,835	)
Comprehensive income:
Net income		—	—			—			—			—			44,270			—			44,270
Contract settlements reclassed to income		—	—			—			—			—			—			14,008			14,008
Change in unrealized hedging gains		—	—			—			—			—			—			(58,013	)		(58,013	)

Total comprehensive income		—	—			—			—			—			44,270			(44,005	)		265

Balance, June 30, 2003	$	—	35,413		$	354		$	(8,716	)	$	176,584		$	164,142		$	(38,204	)	$	294,160

	Oil Swaps (NYMEX)
Time Period	Daily Volume Bbl	$/Bbl	Unrealized Gain (Loss) ($/thousands)
07/01/03 – 09/30/03	12,300	25.16	(4,983	)
10/01/03 – 12/31/03	12,500	24.64	(4,174	)
01/01/04 – 03/31/04	12,000	25.19	(1,976	)
04/01/04 – 06/30/04	11,500	24.42	(1,787	)
07/01/04 – 09/30/04	10,700	24.06	(1,438	)
10/01/04 – 12/31/04	9,700	23.70	(1,147	)
2005	6,000	23.92	(716	)

	Natural Gas Swaps (CIG Index)				Natural Gas Swaps (ANR Index)
Time Period	Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)		Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)
07/01/03 – 09/30/03	90,000	3.26	(9,784	)	16,000	4.00	(1,757	)
10/01/03 – 12/31/03	86,700	3.60	(8,280	)	16,000	4.11	(1,958	)
01/01/04 – 03/31/04	95,000	4.23	(7,332	)	15,000	4.48	(1,583	)
04/01/04 – 06/30/04	65,000	3.52	(1,714	)	11,000	3.76	(925	)
07/01/04 – 09/30/04	65,000	3.46	(1,971	)	11,000	3.74	(892	)
10/01/04 – 12/31/04	55,000	3.78	(1,643	)	9,000	3.87	(872	)
2005	55,000	3.65	(5,889	)	5,000	4.25	(799	)

	Le Norman			Bravo
Purchase Price:
Cash paid	$	62,023		$	118,974
Stock issued		5,779			—

Total	$	67,802		$	118,974

Allocation of Purchase Price:
Working capital	$	215		$	(1,784	)
Oil and gas properties		66,805			159,913
Other non-current assets		5,271			2,622
Deferred income taxes		(4,489	)		(40,653	)
Other non-current liabilities		—			(1,124	)

Total	$	67,802		$	118,974

	Historical Patina		Pro Forma				Pro Forma Consolidated
Three months ended June 30, 2002	Historical Patina		Le Norman		Bravo		Pro Forma Consolidated
Revenues	$	50,693	$	5,221	$	4,822	$	60,736
Net income		12,387		535		428		13,350
Net income per share – basic		0.38						0.40
Net income per share – diluted		0.36						0.38

	Year Ended December 31, 2002			Six Months Ended June 30, 2003
	(In thousands)
Development	$	97,428		$	74,457
Acquisition – evaluated		182,008			65,952
Acquisition – unevaluated		500			1,337
Exploration and other		2,171			2,169

	$	282,107		$	143,915

Disposition	$	(2,303	)	$	(1,719	)

Depletion rate (per Mcfe)	$	0.93		$	0.93

	Year Ended December 31, 2002		Six Months Ended June 30, 2003
Beginning shares	33,190,500		35,162,200
Exercise of stock options	1,262,500		530,300
Issued under Stock Purchase Plan	278,800		—
Issued in lieu of salaries and bonuses	123,000		71,000
Issued for directors fees	2,900		1,700
Issued for Le Norman acquisition	256,600		—
Issued to deferred comp plan (salary match)	18,000		—
Contributed to 401(k) plan	30,200		—

Total shares issued	1,972,000		603,000
Repurchases	(300	)	(351,900	)

Ending shares	35,162,200		35,413,300
Treasury shares held in rabbi trust (Note 7)	(1,295,300	)	(1,359,300	)

Adjusted shares outstanding	33,866,900		34,054,000

	Three Months Ended June 30,
	2002					2003
	Net Income		Common Shares	Per Share		Net Income		Common Shares	Per Share
Basic net income attributable to common stock	$	12,387	32,785	$	0.38	$	20,288	34,158	$	0.59

Effect of dilutive securities:
Stock options		—	1,829				—	1,692

Diluted net income attributable to common stock	$	12,387	34,614	$	0.36	$	20,288	35,850	$	0.57

Year	Options Granted	Range of Exercise Prices	Weighted Average Exercise Price
2001	990,000	$14.47 – $21.14	$	14.66
2002	1,153,000	$16.50 – $25.33	$	16.82
2003	1,053,000	$27.18	$	27.18

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2002		2003		2002		2003
Net income
As Reported	$	12,387	$	20,288	$	25,464	$	44,270
Pro forma		11,572		19,177		24,026		42,360
Basic net income per common share
As Reported	$	0.38	$	0.59	$	0.78	$	1.30
Pro forma		0.35		0.56		0.74		1.24
Diluted net income per common share
As Reported	$	0.36	$	0.57	$	0.75	$	1.24
Pro forma		0.33		0.53		0.70		1.19

	June 30, 2003
	Borrowing Base		Outstanding		Available
Revolving Credit Facility	$	300,000	$	239,000	$	61,000

	Average Prices
	Oil (Per Bbl)		Natural Gas (Per Mcf)		Equivalent Mcf (Per Mcfe)
Annual
1998	$	13.13	$	1.87	$	1.96
1999		17.71		2.21		2.40
2000		29.16		3.69		3.96
2001		24.99		3.42		3.63
2002		25.71		2.23		2.81

Quarterly

2002
First	$	21.02	$	2.06	$	2.45
Second		25.72		2.25		2.81
Third		27.74		1.74		2.53
Fourth		27.51		2.80		3.34

2003
First	$	33.33	$	4.26	$	4.69
Second	$	28.18	$	4.02	$	4.27

		Number of Shares Voted
	Proposals	For	Withheld	Against
1)	Election of Directors
	Jeffrey L. Berenson	31,621,193	418,651	—
	Robert J. Clark	31,354,144	685,700	—
	Jay W. Decker	19,876,301	12,163,543	—
	Thomas J. Edelman	19,764,453	12,275,391	—
	Elizabeth K. Lanier	31,351,019	688,825	—
	Alexander P. Lynch	31,351,453	688,391	—
	Paul M. Rady	31,354,144	685,700	—
2)	Ratification of Deloitte & Touche LLP as the Company’s independent auditors for the current year	31,057,644	4,210	977,990
3)	Other matters	13,465,720	2,641,248	15,932,876

	2002		2003
Federal statutory rate	35	%	35	%
State income tax rate, net of federal benefit	3	%	3	%
Section 29 tax credits and other	(3	%)	—

Effective income tax rate	35	%	38	%

	Less than One Year		1 – 3 Years		After 3 Years		Total
Long term debt	$	—	$	—	$	239,000	$	239,000
Non-cancelable operating leases		1,172		2,421		914		4,507

Total contractual cash obligations	$	1,172	$	2,421	$	239,914	$	243,507

	Oil Swaps (NYMEX)
Time Period	Daily Volume Bbl	$/Bbl	Unrealized Gain (Loss) ($/thousands)
07/01/03—09/30/03	12,300	25.16	(4,983	)
10/01/03—12/31/03	12,500	24.64	(4,174	)
01/01/04—03/31/04	12,000	25.19	(1,976	)
04/01/04—06/30/04	11,500	24.42	(1,787	)
07/01/04—09/30/04	10,700	24.06	(1,438	)
10/01/04—12/31/04	9,700	23.70	(1,147	)
2005	6,000	23.92	(716	)


10.1.2		First Amendment to the Third Amended and Restated Credit Agreement dated January 28, 2003 by and among the Company, as borrower, Bank One, NA, as Administrative Agent, and certain other financial institutions.

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Chief Executive Officer, dated August 1, 2003, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Chief Financial Officer, dated August 1, 2003, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.