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.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

There were 70,533,053 shares of common stock outstanding on April 28, 2004, exclusive of 2,097,912 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 dividend paid to common stockholders in June 2003 and for the 2-for-1 stock split paid in March 2004.

Patina Oil & Gas Corporation (the “Company” or “Patina”), a Delaware corporation, is a rapidly growing independent energy company engaged in the acquisition, development and exploitation of oil and natural gas properties within the continental United States. The Company’s properties and oil and gas reserves are principally located in relatively long-lived fields with well-established production histories. The properties are primarily concentrated in the Wattenberg Field (“Wattenberg”) of Colorado’s Denver-Julesburg Basin (“D-J Basin”), the Mid Continent region of southern Oklahoma and the Texas Panhandle, and the San Juan Basin in New Mexico. The Company was formed in 1996 to hold the assets of Snyder Oil Corporation (“SOCO”) in the Wattenberg Field and to facilitate the acquisition of a competitor in the Field. In conjunction with the acquisition, SOCO received 43.8 million common shares of Patina. In 1997, a series of transactions eliminated SOCO’s ownership in the Company.

Over the past two years, the Company has acquired properties in efforts to expand and diversify the Company’s asset base. 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 the stock of Le Norman Energy Corporation (“Le Norman”) for $62.0 million and the issuance of 513,200 shares of the Company’s Common Stock. Le Norman’s properties are located primarily in the Anadarko and Ardmore-Marietta Basins of Oklahoma and primarily produce oil. The acquisition included a 30% reversionary interest in Le Norman Partners (“LNP”). 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. In March 2003, Patina acquired the remaining 70% interest in 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. In October 2003, the Company acquired the assets of Cordillera Energy Partners, LLC (“Cordillera”) for $243.0 million, comprised of $239.0 million and the issuance of five year warrants to purchase 1,000,000 shares of Common Stock for $22.50 per share. The Cordillera properties are primarily located in the Mid Continent, the San Juan Basin, and the Permian Basin, and primarily produce gas. See Note (3).

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. 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. Through the Le Norman, LNP, Bravo, and certain Cordillera property acquisitions (collectively, “Mid Continent”) and Elysium and the grassroots project (collectively, “Central and Other”), the Company currently has oil and gas properties in central Kansas, the Illinois Basin, Texas, Oklahoma and New Mexico. Based on first quarter 2004 production, Wattenberg accounted for approximately 63%, Mid Continent for 26%, San Juan for 3% and Central and Other for 8% of daily oil and gas production on an equivalent basis.

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 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 projected 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 including development costs, lease operating expenses, production rates, production taxes or oil and gas reserves 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 asset. The asset retirement liability is allocated to operating expense by using a systematic and rational method.

Upon adoption of the statement, an asset retirement obligation of approximately $21.4 million was recorded to reflect the estimated obligations related to the future plugging and abandonment of the Company’s wells. An addition to oil and gas properties of approximately $17.2 million for the related asset retirement costs and a one-time, non-cash charge of approximately $2.6 million (net of $1.6 million of deferred taxes) was recorded for the cumulative effect of change in accounting principle. At March 31, 2004, an asset retirement obligation of $27.7 million is recorded in Other noncurrent liabilities. A reconciliation of the changes in the liability from December 31, 2003 to March 31, 2004 follows (amounts in thousands):

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

At December 31, 2003, the balance primarily represented $14.1 million in assets held in a deferred compensation plan and $937,000 in unamortized loan origination costs. At March 31, 2004, the balance primarily represented $15.6 million in assets held in a deferred compensation plan and $703,000 in unamortized loan origination costs. See Note (7).

The sales method is used 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, 2003 and March 31, 2004 were insignificant. Gathering and processing costs are accounted for as a reduction to revenue.

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. There were no such changes prior to 2001. The components of accumulated other comprehensive income (loss) and related tax effects for the three months ended March 31, 2004 were as follows (in thousands):

Comprehensive income (loss) for the three months ended March 31, 2003 and 2004 totaled $7.2 million and ($6.1) million, respectively.

The book value and estimated fair value of cash and equivalents was $545,000 and $1.6 million at December 31, 2003 and March 31, 2004, respectively. The book value and estimated fair value of bank debt was $416.0 million and $370.0 million at December 31, 2003 and March 31, 2004, 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 periodically enters into derivative contracts to help manage its exposure to changes in interest rates. The contracts are placed with major financial institutions which management believes to be of high credit quality. During the fourth quarter of 2003, the Company entered into LIBOR swap contracts to fix the interest rate on $100.0 million of LIBOR based floating rate bank debt for one year and an additional $100.0 million for two years. At March 31, 2004, the net unrealized pretax losses on these contracts totaled $369,000 ($229,000 loss net of $140,000 of deferred taxes) based on LIBOR futures prices at March 31, 2004. These interest rate swap contracts have been designated as cash flow hedges.

The Company regularly enters into derivative contracts and fixed-price physical contracts to help 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 oil and gas swap contracts have been designated as cash flow hedges.

The Company entered into various swap contracts for oil based on NYMEX prices for the first quarters of 2003 and 2004, recognizing losses of $8.0 million and $11.9 million, respectively, related to these contracts. The Company entered into various swap contracts for natural gas based on the Colorado Interstate Gas (“CIG”), ANR Pipeline Oklahoma (“ANR”), Panhandle Eastern Pipeline (“PEPL”), and the El Paso San Juan (“EPSJ”) indexes during the first quarters of 2003 and 2004, recognizing losses of $4.2 million and $6.7 million, respectively, related to these contracts.

At March 31, 2004, the Company was a party to swap contracts for oil based on NYMEX prices covering approximately 14,650 barrels of oil per day for the remainder of 2004 at fixed prices ranging from $23.03 to $27.91 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $24.68 per barrel for the remainder of 2004. The Company was also a party to swap contracts for oil for 2005 and 2006, which are summarized in the table below. The net unrealized pretax losses on these contracts totaled $76.3 million based on NYMEX futures prices at March 31, 2004.

At March 31, 2004, the Company was a party to swap contracts for natural gas based on CIG, EPSJ, ANR and PEPL index prices covering approximately 130,900 MMBtu’s per day for the remainder of 2004 at fixed prices ranging from $2.83 to $5.58 per MMBtu. The overall weighted average hedged price for the swap contracts is $3.93 per MMBtu for the remainder of 2004. The Company was also a party to natural gas swap contracts for 2005 and 2006, which are summarized in the table below. The net unrealized pretax losses on these contracts totaled $90.1 million based on futures prices at March 31, 2004.

At March 31, 2004, the Company was a party to the fixed price swaps summarized below.

The Company is required to provide margin deposits to certain counterparties when the unrealized losses on its oil and gas hedges exceed specified credit thresholds. At December 31, 2003 and March 31, 2004, the Company had $9.9 million and $20.7 million, respectively, on deposit with counterparties. These amounts are included in Inventory and other in the accompanying consolidated balance sheets.

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 quarter of 2004, net hedging losses of $18.8 million ($11.7 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 $97.6 million ($60.5 million after tax). As the underlying prices in the Company’s hedge contracts were consistent with the indices used to sell its oil and gas and determine the interest rate on the Company’s bank debt, no ineffectiveness was recognized related to its hedge contracts in the first three months of 2004.

As of March 31, 2004, the Company had net unrealized hedging losses of $166.8 million ($103.4 million after tax), comprised of $192,000 of non-current assets, $106.4 million of current liabilities and $60.6 million of non-current liabilities. Based on estimated futures prices as of March 31, 2004, the Company expects to reclassify as a decrease to earnings during the next twelve months $106.4 million ($66.0 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, “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 deferred compensation plan in accordance with EITF 97-14. See Note (7).

In June 2003, a 5-for-4 stock dividend was paid to common stockholders. In March 2004, a 2-for-1 stock split was paid. All share and per share amounts for all periods have been restated to reflect the stock dividend and stock split.

The Company uses weighted average shares outstanding in calculating earnings per share. When dilutive, options and common stock issuable upon conversion of warrants 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. 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 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 was generally effective for contracts entered into or modified after June 30, 2003. The adoption of this pronouncement did not have an impact on the Company’s financial condition or results of operations.

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 adopted by the Company on July 1, 2003. As the Company has no such instruments, the adoption of this statement did not have an impact on the Company’s financial condition or results of operations.

The FASB is currently evaluating 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 is 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 oil and gas property costs, and provide specific footnote disclosures. In the event the FASB determines that costs associated with mineral rights are required to be classified as intangible assets, the Company currently believes that its financial condition and results of operations would not be affected.

In October 2003, the assets of Cordillera Energy Partners, L.L.C. (“Cordillera”) were acquired for $239.0 million and the issuance of five year warrants to purchase 1,000,000 shares of the Company’s Common Stock for $22.50 per share. Cordillera’s properties are located primarily in the Mid Continent, the San Juan Basin, and the Permian Basin. The Cordillera properties produce primarily gas.

As this acquisition was recorded using the purchase method of accounting, the results of operations from the acquisition are included with the results of the Company from the acquisition date. The table below summarizes the preliminary allocation of the purchase price of the 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 months ended March 31, 2003 as though the Cordillera acquisition had occurred on January 1, 2003 (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 Cordillera acquisition been consummated on January 1, 2003, nor are the pro forma amounts necessarily indicative of the future results of operations of the Company.

The cost of oil and gas properties at December 31, 2003 and March 31, 2004 included approximately $2.5 million and $5.0 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.

The disposition of properties in 2003 primarily relates to the sale of properties in Louisiana for $8.4 million, $4.8 million for sales of certain Wattenberg properties, and $3.2 million for the sale of the Company’s Utah properties. The disposition of properties in 2004 primarily relates to the sale of the Adams Baggett properties for $15.2 million and the sale of certain Permian Basin properties acquired in the Cordillera acquisition for $6.3 million.

In conjunction with the Cordillera acquisition in 2003, an addition to oil and gas properties for $39.8 million was recorded 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). In conjunction with the acquisition of the remaining 70% interest in LNP in March 2003, $4.6 million representing the value assigned for the 30% reversionary interest in LNP which the Company acquired in conjunction with the Le Norman acquisition was recorded in oil and gas properties. During 2003, the Company exchanged its interest in the Wyoming grassroots project for certain oil and gas properties in Wattenberg. No gain or loss was recognized on the exchange.

During 2003, an addition to oil and gas properties of approximately $17.2 million was recorded for the asset retirement costs related to the adoption of SFAS No. 143. During 2003 and the first quarter of 2004, additions to oil and gas properties of approximately $3.8 million and $220,000, respectively, were recorded for the estimated asset retirement costs related to new wells drilled or acquired.

In January 2003, the Company entered into an Amended Bank Credit Agreement (the “Credit Agreement”). The Credit Agreement is a revolving credit facility for up to $500.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and equaled $500.0 million at March 31, 2004. The Company had $130.0 million available under the Credit Agreement at March 31, 2004.

The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the LIBOR 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 2.6% during the first quarter of 2004 and 2.5% at March 31, 2004.

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, 2003 and March 31, 2004, 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 $77.2 million as of March 31, 2004, which may be used to repurchase equity securities, pay dividends or make other restricted payments.

In October 2003, the Company entered into interest rate swaps effective November 1, 2003 for one-year and two-year periods. Each contract is for $100.0 million principal with a fixed interest rate of 1.26% on the one-year term and 1.83% on the two-year term, respectively, payable by the Company and the variable interest rate, the three-month LIBOR, payable by the third party. The difference between the Company’s fixed rates of 1.26% and 1.83% and the three-month LIBOR rate, which is reset every 90 days, is received or paid every 90 days in arrears.

Scheduled maturities of indebtedness for the next five years are zero in 2004, 2005, and 2006 and $370.0 million in the first quarter of 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 $3.0 million during the first quarters of 2003 and 2004, respectively.

A total of 100.0 million common shares, $0.01 par value, are authorized of which 72.3 million were issued at March 31, 2004 (“Common Stock”). The Common Stock is listed on the New York Stock Exchange. In June 2003, a 5-for-4 stock dividend was paid to common stockholders. In March 2004, a 2-for-1 stock split was paid. All share and per share amounts for all periods have been restated to reflect the stock dividend and the stock split. 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, 2003:

Adjusted for the stock dividends and split, the following is a schedule of quarterly cash dividends paid on the Common Stock since 2001:

During the first three months of 2004, the Company repurchased and retired 667,800 shares of Common Stock for $14.7 million.

In conjunction with the Cordillera acquisition made in October 2003, the Company issued 1,000,000 five year warrants to purchase Common Stock for $22.50 per share (“Warrants”). At March 31, 2004, all of the Warrants were outstanding. The Warrants expire on October 1, 2008.

A total of 5,000,000 preferred shares, $0.01 par value, are authorized with no shares issued or outstanding at December 31, 2003 and March 31, 2004.

In September 2003, the Compensation Committee of the Board of Directors awarded restricted stock grants totaling 47,500 shares of Common Stock to the officers and directors of the Company in lieu of the suspended Stock Purchase Plan. The shares vest 30% in May 2004, 30% in May 2005 and 40% in May 2006. The non-vested shares have been recorded as Deferred compensation in the equity section of the accompanying consolidated balance sheets.

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 March 31, 2004, the calculation of diluted earnings per share excluded 1.6 million outstanding stock options as they were 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. In addition, the Company may, at its discretion, make matching or profit sharing contributions to the 401(k) Plan. The Company made profit sharing contributions of $801,000 and $1.4 million for 2002 and 2003, respectively. The contribution in 2002 was made in Common Stock while the 2003 contribution was made in cash. A total of 60,500 common shares were contributed in 2002.

The Company maintains a shareholder approved deferred compensation plan (the “Plan”). The Plan is available to officers and certain key employees of the Company and allows participants to defer all or a portion of their salary and annual bonuses (either in cash or Common 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 Plan does not have dollar limits on tax-deferred contributions. The assets of the Plan are held in a rabbi trust (“Trust”) and, therefore, may be 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, Common Stock) in the participant’s individual account within the Trust, however, the Plan Administrator is not required to honor such requests. Matching contributions are in made in cash or Common Stock and vest ratably over a three-year period. Participants may elect to receive their payments in either cash or Common Stock. At March 31, 2004, the balance of the assets in the Trust totaled $73.3 million, including 2,197,912 shares of Common Stock valued at $57.7 million. The Company accounts for the 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 an investment spectrum ranging 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 Stock. 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 consolidated balance sheets. The market value of the assets held by the Trust, exclusive of the market value of the shares of the Common Stock that are reflected as treasury stock, at December 31, 2003 and March 31, 2004, was $14.1 million and $15.6 million, respectively, and is classified as Other Assets in the accompanying consolidated balance sheets. The amounts payable to plan participants at December 31, 2003 and March 31, 2004, including the market value of the shares of Common Stock that are reflected as treasury stock, was $74.9 million and $73.3 million, respectively, and is classified as Deferred Compensation Liability in the accompanying consolidated balance sheets. Approximately 2,100,000 shares or 96% of the Common Stock held in the Plan were attributable to the Chief Executive Officer at March 31, 2004.

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 statements. Based on changes in the total market value of the Trust’s assets, the Company recorded deferred compensation adjustments of $1.1 million and $4.7 million in the first quarters of 2003 and 2004, 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 on the date of grant. Options to acquire the greater of 9.4 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 Common Stock in partial payment of their quarterly retainer. A total of 5,400 shares were issued in 2003 and 700 in the first quarter of 2004. It also provides for stock 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,” 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 stock option plans been determined consistent with SFAS No. 123, “Accounting for Stock-Based Compensation,” net income (in thousands) and earnings per share would have been reduced to the pro forma amounts indicated below for the three months ended March 31, 2003 and 2004, respectively.

The fair value of each option grant was 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 quarters of 2003 and 2004: dividend yields of 1% and 1%; expected volatility of 45% and 29%; risk-free interest rates of 2.7% and 3.0%; and expected lives of 3.7 years and 3.8 years, respectively.

A reconciliation of the federal statutory rate to the Company’s effective rate as it applies to the tax provision for the three months ended March 31, 2003 and 2004 follows:

Current income tax expense in the three months ended March 31, 2003 and 2004 totaled $6.1 million and $9.8 million, respectively. In 2004, the Company expects to utilize approximately $12.6 million of net operating loss carryforwards and approximately $9.1 million of alternative minimum tax (“AMT”) credit to reduce current taxes.

For tax purposes, the Company had net operating loss carryforwards of approximately $41.3 million at December 31, 2003. Utilization of these losses will be limited each year as a result of various acquisitions. The carryforwards expire from 2005 through 2023. The Company has provided a $3.2 million valuation allowance against the loss carryforwards that could expire unutilized. At December 31, 2003, the Company had AMT credit carryforwards of approximately $9.1 million that are available indefinitely. In addition, at December 31, 2003, the Company had depletion deduction carryforwards of approximately $12.0 million that are available indefinitely. The Company paid $1.7 million and $1.0 million in federal and state taxes during the three months ended March 31, 2003 and 2004, respectively.

During the three months ended March 31, 2003 and 2004, Duke Energy Field Services, Inc. accounted for 22% and 23%, and BP Amoco Production Company accounted for 12% and 17% of revenues, respectively. Accounts receivable amounts from these customers at December 31, 2003 totaled $25.4 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.

The Company leases office space and certain equipment under non-cancelable operating leases. In 2003, the Company entered into a firm transportation agreement for 4,773 MMBtu’s per day on a pipeline from central Wyoming to the Oklahoma panhandle. The term of the agreement is through February 2024, with a fixed fee of $0.334 per MMBtu. Under this agreement, the Company buys and sells third party gas at various delivery points on the pipeline. During the first quarter of 2004, $79,000 was recorded as a component of other income in the accompanying consolidated statements of operations reflecting proceeds of $6.7 million from gas sold, net of costs of $6.6 million.

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 ruling by the Colorado Supreme Court in July 2001 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.

Patina Oil & Gas Corporation (“Patina” or the “Company”) is a rapidly growing independent energy company engaged in the acquisition, development and exploitation of oil and natural gas properties within the continental United States. The Company’s properties and oil and gas reserves are principally located in relatively long-lived fields with well-established production histories. The properties are primarily concentrated in the Wattenberg Field (“Wattenberg”) of Colorado’s Denver-Julesburg Basin (“D-J Basin”), the Mid Continent region of southern Oklahoma and the Texas Panhandle, and the San Juan Basin in New Mexico.

The Company seeks to increase its reserves, production, revenues, net income and cash flow in a cost-efficient manner primarily through: (i) further Wattenberg development; (ii) accelerated development of the recently acquired Mid Continent and San Juan Basin properties; (iii) selective pursuit of further consolidation and acquisition opportunities, and (iv) generation and exploitation of exploration and development projects with a focus on projects near currently owned productive properties.

During the three months ended March 31, 2004, the Company performed well in several key respects:

Based on the $210.0 million 2004 capital budget combined with the benefits of the acquisitions made in 2003, the Company expects production to increase by approximately 17% to 20% in 2004.

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 reflect 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, the Company’s oil and gas swap contracts are designated as cash flow hedges.

During the three months ended March 31, 2004, the Company spent $53.7 million on the further development of existing properties and $3.0 million on acquisitions. Development expenditures included $24.3 million in Wattenberg for the drilling or deepening of 27 wells, performing 117 refracs and trifracs and one recompletion, $22.2 million on the further development of the Mid Continent (Le Norman, Le Norman Partners, Bravo, and certain Cordillera properties) for the drilling or deepening of 46 wells and 12 recompletions, $3.3 million in the San Juan Basin for the drilling of five wells and performing two recompletions, and $3.9 million on other properties (primarily in Illinois and Kansas), primarily for drilling or deepening 10 wells and performing 12 recompletions. During the quarter, the Company sold its interest in the Adams Baggett project in west Texas, certain properties in the Permian Basin and various other minor properties for a total of $22.7 million. These projects combined with the benefits of the prior year acquisitions and the continued success in production enhancement allowed production to increase 29% over the prior year period. On October 1, 2003, Cordillera was acquired for $243.0 million. The Cordillera properties are primarily located in the Mid Continent, the San Juan Basin, and the Permian Basin and primarily produce gas. The decision to increase or decrease development activity is heavily dependent on the prices being received for production.

At March 31, 2004, the Company had $1.2 billion of assets. Total capitalization was $702.0 million, of which 47% was represented by stockholders’ equity and 53% by bank debt. During the first quarter of 2004, net cash provided by operations totaled $91.0 million, as compared to $53.2 million in 2003. At March 31, 2004, there were no significant commitments for capital expenditures. Although a $210.0 million capital budget has been approved for 2004, 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 fund development expenditures, finance acquisitions, repurchase equity securities, repay indebtedness, and satisfy 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 twelve 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.

The following summarizes the Company’s contractual obligations at March 31, 2004 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 its revolving credit facility (in thousands):

In January 2003, the Company entered into an Amended Bank Credit Agreement (the “Credit Agreement”). The Credit Agreement is a revolving credit facility for up to $500.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and equaled $500.0 million at March 31, 2004. Patina had $130.0 million available under the Credit Agreement at March 31, 2004.

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 March 31, 2003 and 2004, 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 $77.2 million as of March 31, 2004, which may be used to repurchase equity securities, pay dividends or make other restricted payments.

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 covering part of its expected production for 2004, 2005, and 2006, respectively. The $53.7 million of development expenditures for the first quarter of 2004 were funded entirely with internal cash flow. The 2004 capital budget of $210.0 million, comprised primarily of $110.0 million of development expenditures in Wattenberg, $70.0 million in the Mid Continent region, $15.0 million in the San Juan Basin, and $15.0 million on the Central and Other properties, combined with the benefits of the acquisitions made in 2003, is expected to increase production by approximately 17% to 20%. On October 1, 2003, Cordillera was acquired for $243.0 million, comprised of $239.0 million and the issuance of five year warrants to purchase 1,000,000 shares of Common Stock for $22.50 per share. On March 31, 2004, $370.0 million was outstanding under the bank facility. Exclusive of any other acquisitions or significant equity repurchases, management expects to reduce long-term debt and fund the development program with internal cash flow.

Net cash provided by operating activities in the three months ended March 31, 2003 and 2004 was $53.2 million and $91.0 million, respectively. Cash flow from operations increased in 2004 due to the 29% increase in oil and gas equivalent production and the 10% increase in average oil and gas prices received. Lease operating expenses, production taxes, general and administrative expenses and interest expense all increased as a result of the acquisitions made at the end of the first quarter of 2003 (Le Norman Partners), and in the fourth quarter of 2003 (Cordillera). Operating cash flows in the first quarters of 2003 and 2004 were benefited by $3.6 million and $8.8 million, respectively, due to the tax deduction generated from the exercise and same day sale of stock options.

Net cash used in investing activities in the three months ended March 31, 2003 and 2004 totaled $98.3 million and $35.2 million, respectively. The decrease in expenditures in 2004 was primarily due to a $60.4 million decrease in acquisition expenditures (the Elysium and Le Norman Partners acquisitions were made in the first quarter of 2003) and the sale of oil and gas properties for $22.7 million in first quarter of 2004, offset by an increase in development expenditures of $19.5 million, comprised primarily of increases in Wattenberg of $1.0 million, Mid Continent of $14.7 million and San Juan of $3.3 million.

Net cash provided by (used in) financing activities in the three months ended March 31, 2003 and March 31, 2004 was $44.9 million and ($54.7) million, respectively. Sources of financing have been primarily bank borrowings. During the first quarter of 2003, the combination of operating cash flow and bank borrowings of $46.0 million, allowed the Company to fund capital development and acquisition expenditures of $97.7 million and buy back $2.7 million in Common Stock and pay dividends of $1.7 million. During the first quarter of 2004, the combination of operating cash flow and $9.6 million in proceeds from the exercise of stock options, allowed the Company to repay $46.0 million of bank debt, fund net capital development and acquisition expenditures of $34.1 million, repurchase $14.7 million in Common Stock and pay dividends of $3.6 million.

During the first quarter of 2004, $34.1 million of capital, net of $22.7 million of property sales, was expended, including $53.7 million on development projects and $3.0 million on acquisitions. Development expenditures represented approximately 57% of internal cash flow (defined as net cash provided by operations before changes in working capital). The Company manages its development budget with the goal of funding it with internal cash flow. Based on the 2004 development budget of $210.0 million combined with the benefits of the acquisitions made in 2003, production is expected to increase by approximately 17% to 20% in 2004. Based on current futures prices for oil and natural gas, the Company expects its capital program to be funded with internal cash flow. As such, exclusive of any other acquisitions or significant equity repurchases, management expects to continue to reduce long-term debt in 2004. 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 12 to 36 month basis. At March 31, 2004, hedges were in place covering 88.7 Bcf at prices averaging $4.05 per MMBtu and 12.6 million barrels of oil averaging $25.29 per barrel. The estimated fair value of the oil and gas hedge contracts that would be realized on termination approximated a net unrealized pretax loss of $166.4 million ($103.2 million loss net of $63.2 million of deferred taxes) at March 31, 2004. The combined net unrealized losses from the oil, gas, and interest rate hedges are presented on the balance sheet as a non-current asset of $192,000, a current liability of $106.4 million, and a non-current liability of $60.6 million based on contract expirations. The oil and gas contracts settle monthly through December 2006. 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, ANR Pipeline Oklahoma (“ANR”) index, Panhandle Eastern Pipeline (“PEPL”) index and El Paso San Juan (“EPSJ”) 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 pretax losses relating to these derivatives totaled $12.2 million and $18.6 million in the three months ended March 31, 2003 and 2004, respectively. Effective January 1, 2001, the unrealized gains (losses) on open 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, CIG, ANR, PEPL or EPSJ 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 2003 and 2004. 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 March 31, 2004 compared to the three months ended March 31, 2003.

Revenues for first quarter of 2004 totaled $137.9 million, a 53% increase from the prior year period. Net income for the first quarter of 2004 totaled $42.8 million, an increase of 78% from 2003. The increases in revenue and net income were due to higher oil and gas prices and production and a $7.4 million gain on the sale of the Adams Baggett properties.

Average daily oil and gas production in the first quarter of 2004 totaled 17,744 barrels and 204.8 MMcf (311.2 MMcfe), an increase of 29% on an equivalent basis from the same period in 2003. The rise in production was due to the continued development activity in Wattenberg and the Mid Continent, as well as the benefits of the LNP and Cordillera acquisitions made in 2003. During the first quarter of 2004, the Company drilled or deepened 27 wells, performed 117 refracs and trifracs, and one recompletion in Wattenberg, compared to 20 new wells or deepenings, 132 refracs and three recompletions in Wattenberg in 2003. During the first quarter of 2004, the Company drilled or deepened 46 wells and performed 12 recompletions on its Mid Continent properties, compared to 51 new drills or deepenings and one recompletion for 2003. Based on a $210.0 million capital budget for 2004 combined with the benefits of the acquisitions made in 2003, the Company expects production to increase by approximately 17% to 20% in 2004. The following table sets forth summary information with respect to oil and natural gas production for the three months ended March 31, 2003 and 2004:

Average realized oil prices decreased 0.4% from $26.73 per barrel in the first quarter of 2003 to $26.62 in 2004. Average realized gas prices increased 16% from $3.97 per Mcf in the first quarter of 2003 to $4.62 in 2004. Average oil prices include hedging losses of $8.0 million or $6.60 per barrel and $11.9 million or $7.39 per barrel in the first quarters of 2003 and 2004, respectively. Average gas prices included hedging losses of $4.2 million or $0.29 per Mcf in 2003 and $6.7 million or $0.36 per Mcf in 2004. The following table sets forth summary information with respect to oil and natural gas prices for the three months ended March 31, 2003 and 2004:

Gain on sale of oil and gas properties for the first quarter of 2004 totaled $7.4 million, relating to the sale of the Adams Baggett properties for $15.2 million.

Lease operating expenses totaled $15.7 million or $0.56 per Mcfe for the first quarter of 2004 compared to $10.7 million or $0.49 per Mcfe in the prior year period. The increase in operating expenses was primarily attributed to the 29% increase in oil and gas production. Production taxes totaled $10.5 million or $0.37 per Mcfe in the first quarter of 2004 compared to $6.5 million or $0.30 per Mcfe in 2003. The $4.1 million increase was a result of higher oil and gas prices and production.

General and administrative expenses for the first quarter of 2004 totaled $5.3 million, an increase of $888,000 or 20% over the same period in 2003. The increase was largely attributed to additional employees hired in conjunction with the recent acquisitions.

Interest and other expenses increased to $3.2 million in the first quarter of 2004, an increase of 46% from the prior year period. Interest expense increased as a result of higher average debt balances in conjunction with the acquisitions made in 2003, somewhat offset by lower average interest rates. The Company’s average interest rate during the first quarter of 2004 was 2.6% compared to 2.7% in 2003.

Deferred compensation adjustment totaled $4.7 million in the first quarter of 2004, an increase of $3.7 million from the prior year period. The increase relates to the increase in value of the Company’s Common Stock and other investments held in a deferred compensation plan over 2002. The Company’s Common Stock price appreciated by 7% or $1.75 per share in the first quarter of 2004 versus an increase of 4% or $0.50 per share in the first quarter of 2003.

Depletion, depreciation and amortization expense for the first quarter of 2004 totaled $29.4 million, an increase of $8.3 million or 39% from the first quarter of 2003. Depletion expense totaled $28.4 million or $1.00 per Mcfe for the first quarter of 2004 compared to $20.2 million or $0.93 per Mcfe for 2003. The increase in depletion expense resulted from the increase in oil and gas production in the first quarter of 2004 and revised depletion rates based on the year-end 2003 reserve report. Depreciation and amortization expense for the three months ended March 31, 2004 totaled $666,000 or $0.02 per Mcfe compared to $595,000 or $0.03 per Mcfe in the first quarter of 2003. Accretion expense related to SFAS No. 143 totaled $360,000 in the first quarter of 2004 compared to $310,000 in the first quarter of 2003.

Provision for income taxes for the first quarter of 2004 totaled $26.2 million, an increase of $9.9 million from the same period in 2003. The increase was due to higher pretax earnings. A 38% tax provision was recorded for the first quarters of 2003 and 2004.

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 quarter 2003 reflects accretion that would have been recorded if the Company had always been under the requirements of SFAS No. 143.

At March 31, 2004, $370.0 million was outstanding under the credit facility with an average interest rate of 2.5%. The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) LIBOR 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 2.6% during the first quarter of 2004. Assuming no change in the amount outstanding at March 31, 2004, the annual impact on interest expense of a 10% change in the average interest rate would be approximately $580,000, net of tax. As the interest rate is variable and is reflective of current market conditions, the carrying value approximates the fair value.

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 the Company’s 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 2003 and the first quarter of 2004, exclusive of any hedges, ranged from a monthly low of $3.45 per Mcf to a monthly high of $5.37 per Mcf. Oil prices, exclusive of any hedges, ranged from a monthly low of $27.35 per barrel to a monthly high of $35.68 per barrel during 2003 and the first quarter of 2004. 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 quarter of 2004, a 10% reduction in oil and gas prices, excluding oil and gas quantities that were fixed through hedging transactions, would have reduced revenues by $4.5 million. If oil and gas futures prices at March 31, 2004 had declined by 10%, the net unrealized pretax hedging losses at that date would have decreased by $84.3 million (from $166.4 million to $82.1 million).

At March 31, 2004, the Company was a party to the fixed price swaps summarized below.

The Company sells the majority of its gas production based on the Colorado Interstate Gas (“CIG”) index. The realized price of the Company’s gas and that of other Rocky Mountain producers has historically traded at a discount to NYMEX gas. This discount is referred to as a “basis differential” and the CIG basis differential for 2003 averaged $1.35 per MMBtu discount from NYMEX, ranging from a discount of $0.42 per MMBtu in December 2003 to a discount of $4.12 per MMBtu in March 2003. Based on the actual indices for January 2004 through March 2004 and futures prices as of March 31, 2004, the CIG basis differential for 2004 averages a $0.83 per MMBtu discount, ranging from a discount of $1.20 per MMBtu in April 2004 to a discount of $0.66 per MMBtu in February 2004. The decrease in the CIG basis differential is believed to be in part due to the pipeline expansions made in 2003 (primarily the Kern River expansion of 900 MMBtu per day in May 2003) resulting in an increase in gas pipeline capacity for transportation out of the Rocky Mountain region.

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, 2003. 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 or trifracing 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, 2003.

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, 2003 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 maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed by the Company in the reports it files or submits to the Securities and Exchange Commission (“SEC”) under the Securities Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Patina’s principal executive officer and principal financial officer have evaluated the effectiveness of Patina’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(c) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this Quarterly Report on Form 10-Q. Based upon their evaluation, they have concluded that the Company’s disclosure controls and procedures are effective. There were no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls, since the date the controls were evaluated.

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

The table below sets forth the information with respect to purchases made by or on behalf of Patina Oil & Gas Corporation, of Common Stock during the three months ended March 31, 2004:

The Company filed a current report on Form 8-K on February 11, 2004 to announce that it’s Board of Directors had approved a 2-for-1 stock split to be paid on March 3, 2004 in which stockholders would receive an additional share of common stock for every share held on that date.

The Company filed a current report on Form 8-K on February 25, 2004 to furnish the information required under Item 12 related to the February 24, 2004 press release announcing the Company’s financial results for the three months and the year ended December 31, 2003.

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


Delaware		75-2629477
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

1625 Broadway, Suite 2000 Denver, Colorado		80202
(Address of principal executive offices)		(zip code)


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


	December 31, 2003			March 31, 2004
				(Unaudited)
ASSETS
Current assets
Cash and equivalents	$	545		$	1,636
Accounts receivable		59,973			57,849
Inventory and other		17,736			30,348
Deferred income taxes		23,641			40,415
Unrealized hedging gains		137			—

		102,032			130,248

Unrealized hedging gains		1,867			192
Oil and gas properties, successful efforts method		1,628,750			1,669,393
Accumulated depletion, depreciation and amortization		(560,090	)		(587,654	)

		1,068,660			1,081,739

Field equipment and other		15,027			15,964
Accumulated depreciation		(6,506	)		(7,076	)

		8,521			8,888

Other assets, net		15,211			16,327

	$	1,196,291		$	1,237,394
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	61,329		$	66,819
Accrued liabilities		18,866			18,808
Unrealized hedging losses		62,349			106,356

		142,544			191,983

Bank debt		416,000			370,000
Deferred income taxes		154,480			157,701
Other noncurrent liabilities		50,236			51,752
Unrealized hedging losses		27,631			60,602
Deferred compensation liability		74,888			73,318
Commitments and contingencies
Stockholders’ equity
Preferred Stock, $.01 par, 5,000,000 shares authorized, none issued or outstanding		—			—
Common Stock, $.01 par, 100,000,000 shares authorized, 71,504,986 and 72,262,524 shares issued		715			723
Common Stock Held in Treasury, at cost, 2,481,820 and 2,197,912 shares		(7,850	)		(7,179	)
Capital in excess of par value		187,171			197,632
Deferred compensation		(764	)		(667	)
Retained earnings		205,786			244,924
Accumulated other comprehensive income (loss)		(54,546	)		(103,395	)

		330,512			332,038

	$	1,196,291		$	1,237,394


	Three Months Ended March 31,
	2003			2004
Revenues
Oil and gas sales	$	89,530		$	129,068
Gain on sale of oil and gas properties		—			7,384
Other		437			1,474

		89,967			137,926

Expenses
Lease operating		10,698			15,738
Production taxes		6,485			10,536
Exploration		1,133			93
General and administrative		4,446			5,334
Interest and other		2,165			3,152
Deferred compensation adjustment		1,058			4,708
Depletion, depreciation and amortization		21,087			29,411

		47,072			68,972

Pretax income		42,895			68,954

Provision for income taxes
Current		6,113			9,826
Deferred		10,187			16,377

		16,300			26,203

Net income before change in accounting principle	$	26,595		$	42,751
Cumulative effect of change in accounting principle		(2,613	)		—

Net income	$	23,982		$	42,751

Net income per share before cumulative effect of change in accounting principle
Basic	$	0.39		$	0.62

Diluted	$	0.38		$	0.59

Net loss per share from change in accounting principle
Basic	$	(0.04	)	$	—

Diluted	$	(0.04	)	$	—

Net income per share
Basic	$	0.35		$	0.62

Diluted	$	0.34		$	0.59

Weighted average shares outstanding
Basic		67,888			69,209
Diluted		71,052			72,345


	Preferred Stock Amount		Common Stock					Treasury Stock			Capital in Excess of Par Value			Deferred Compensation			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	Preferred Stock Amount		Shares		Amount			Treasury Stock			Capital in Excess of Par Value			Deferred Compensation			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance at December 31, 2002	$	—	70,324		$	703		$	(6,817	)	$	175,186		$	—		$	123,707		$	5,801		$	298,580
Repurchase of common stock		—	(1,181	)		(12	)		—			(17,218	)		—			—			—			(17,230	)
Issuance of common stock		—	2,362			24			—			10,229			(861	)		—			—			9,392
Deferred compensation stock issued, net		—	—			—			(1,033	)		4,398			—			—			—			3,365
Amortization of stock grant		—	—			—			—			—			97			—			—			97
Issuance of warrants		—	—			—			—			4,000			—			—			—			4,000
Tax benefit from stock options		—	—			—			—			10,576			—			—			—			10,576
Dividends		—	—			—			—			—			—			(8,817	)		—			(8,817	)
Comprehensive income:
Net income		—	—			—			—			—			—			90,896			—			90,896
Contract settlements reclassed to income		—	—			—			—			—			—			—			29,616			29,616
Change in unrealized hedging gains		—	—			—			—			—			—			—			(89,963	)		(89,963	)

Total comprehensive income		—	—			—			—			—			—			90,896			(60,347	)		30,549

Balance at December 31, 2003		—	71,505			715			(7,850	)		187,171			(764	)		205,786			(54,546	)		330,512
Repurchase of common stock		—	(668	)		(6	)		—			(14,727	)		—			—			—			(14,733	)
Issuance of common stock		—	1,426			14			—			9,647			—			—			—			9,661
Deferred compensation stock issued, net		—	—			—			671			6,752			—			—			—			7,423
Amortization of stock grant		—	—			—			—			—			97			—			—			97
Tax benefit from stock options		—	—			—			—			8,789			—			—			—			8,789
Dividends		—	—			—			—			—			—			(3,613	)		—			(3,613	)
Comprehensive loss:
Net income		—	—			—			—			—			—			42,751			—			42,751
Contract settlements reclassed to income		—	—			—			—			—			—			—			11,686			11,686
Change in unrealized hedging gains		—	—			—			—			—			—			—			(60,535	)		(60,535	)

Total comprehensive loss		—	—			—			—			—			—			42,751			(48,849	)		(6,098	)

Balance at March 31, 2004	$	—	72,263		$	723		$	(7,179	)	$	197,632		$	(667	)	$	244,924		$	(103,395	)	$	332,038


	Three Months Ended March 31,
	2003			2004
Operating activities
Net income	$	23,982		$	42,751
Adjustments to reconcile net income to net cash provided by operating activities
Cumulative effect of change in accounting principle, net of tax		2,613			—
Exploration expense		1,133			93
Depletion, depreciation and amortization		21,087			29,411
Deferred income taxes		10,187			16,377
Tax benefit from exercise of stock options		3,580			8,789
Deferred compensation adjustment		1,058			4,708
Loss (gain) on deferred compensation asset		168			(381	)
Gain on sale of oil and gas properties		—			(7,384	)
Other		134			331

Subtotal		63,942			94,695
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable		(12,429	)		2,124
Inventory and other		(2,311	)		(12,552	)
Increase (decrease) in
Accounts payable		8,314			5,453
Accrued liabilities		(3,351	)		(78	)
Other assets and liabilities		(1,004	)		1,327

Net cash provided by operating activities		53,161			90,969

Investing activities
Development and exploration		(34,313	)		(53,774	)
Acquisitions, net of cash acquired		(63,372	)		(3,000	)
Disposition of oil and gas properties		116			22,684
Other		(697	)		(1,084	)

Net cash used in investing activities		(98,266	)		(35,174	)

Financing activities
Increase (decrease) in indebtedness		46,000			(46,000	)
Loan origination fees		(1,074	)		—
Issuance of common stock		4,331			9,643
Repurchase of common stock		(2,664	)		(14,734	)
Common stock dividends		(1,703	)		(3,613	)

Net cash provided by (used in) financing activities		44,890			(54,704	)

Increase (decrease) in cash		(215	)		1,091
Cash and equivalents, beginning of period		1,920			545

Cash and equivalents, end of period	$	1,705		$	1,636


Asset retirement obligation at December 31, 2003	$	27,594
Liabilities incurred		220
Liabilities settled		(477	)
Accretion expense		360

Asset retirement obligation at March 31, 2004	$	27,697


	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive loss at 12/31/03	$	(87,977	)	$	33,431		$	(54,546	)
Change in fair value of hedges		(97,636	)		37,101			(60,535	)
Contract settlements during the quarter		18,848			(7,162	)		11,686

Accumulated other comprehensive loss at 03/31/04	$	(166,765	)	$	63,370		$	(103,395	)


	Oil Swaps (NYMEX)				Natural Gas Swaps (CIG Index)
Time Period	Daily Volume Bbl	$/Bbl	Unrealized Gain (Loss) ($/thousands)		Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)
04/01/04 - 06/30/04	14,365	24.93	(13,091	)	90,000	3.58	(9,976	)
07/01/04 - 09/30/04	14,750	24.69	(12,015	)	90,000	3.57	(13,711	)
10/01/04 - 12/31/04	14,830	24.43	(11,093	)	82,000	3.98	(10,916	)
01/01/05 - 03/31/05	13,700	25.07	(8,204	)	70,000	4.15	(9,191	)
04/01/05 - 06/30/05	13,700	24.80	(7,772	)	70,000	3.57	(6,181	)
07/01/05 - 09/30/05	13,700	24.67	(7,361	)	70,700	3.59	(6,698	)
10/01/05 - 12/31/05	13,700	24.60	(6,890	)	70,700	3.88	(6,024	)
2006	9,900	26.67	(9,871	)	20,000	4.23	(1,705	)


	Natural Gas Swaps (ANR/PEPL Indexes)				Natural Gas Swaps (EPSJ Index)
Time Period	Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)		Daily Volume MMBtu	$/MMBtu	Unrealized Gain (Loss) ($/thousands)
04/01/04 - 06/30/04	33,500	4.35	(3,294	)	8,300	4.16	(612	)
07/01/04 - 09/30/04	34,700	4.31	(4,458	)	9,000	4.15	(1,014	)
10/01/04 - 12/31/04	36,600	4.62	(4,116	)	8,600	4.36	(896	)
01/01/05 - 03/31/05	32,100	5.10	(2,525	)	9,000	4.72	(751	)
04/01/05 - 06/30/05	32,100	4.42	(1,744	)	9,000	3.98	(556	)
07/01/05 - 09/30/05	32,100	4.37	(1,875	)	9,000	4.00	(527	)
10/01/05 - 12/31/05	32,100	4.54	(1,835	)	9,000	4.22	(496	)
2006	10,200	4.65	(822	)	2,650	4.33	(178	)


	Cordillera
Purchase Price:
Cash paid	$	238,969
Warrants issued		4,000

Total	$	242,969

Allocation of Purchase Price:
Working capital	$	(676	)
Oil and gas properties		285,183
Other non-current assets		410
Deferred income taxes		(39,800	)
Other non-current liabilities		(2,148	)

Total	$	242,969


Three months ended March 31, 2003	Historical Patina		Pro Forma Cordillera		Pro Forma Consolidated
Revenues	$	89,967	$	9,974	$	99,941
Net income		23,982		1,638		25,620
Net income per share – basic		0.35				0.38
Net income per share – diluted		0.34				0.36


	Year Ended December 31, 2003			Three Months Ended March 31, 2004
	(In thousands, except per Mcfe amounts)
Development	$	169,929		$	53,681
Acquisition - evaluated		305,833			1,320
Acquisition - unevaluated		1,493			1,680
Exploration and other		6,207			93

	$	483,462		$	56,774

Asset retirement costs	$	3,761		$	220

Disposition of properties	$	(16,943	)	$	(22,684	)

Depletion rate (per Mcfe)	$	0.94		$	1.00


	December 31, 2003		March 31, 2004
	(In thousands)
Bank debt	$	416,000	$	370,000
Less current portion		—		—

Bank debt, net	$	416,000	$	370,000


	Year Ended December 31, 2003		Three Months Ended March 31, 2004
Beginning shares	70,324,400		71,505,000
Exercise of stock options	2,214,600		1,424,600
Issued in lieu of salaries and bonuses	142,200		—
Issued for directors fees	5,400		700

Total shares issued	2,362,200		1,425,300
Repurchases	(1,181,600	)	(667,800	)

Ending shares	71,505,000		72,262,500
Treasury shares held in deferred comp (Note 7)	(2,481,800	)	(2,197,900	)

Adjusted shares outstanding	69,023,200		70,064,600


	Quarter
	First		Second		Third		Fourth		Total
2001	$	0.0128	$	0.0128	$	0.0128	$	0.0160	$	0.0544
2002		0.0160		0.0200		0.0200		0.0240		0.0800
2003		0.0240		0.0300		0.0300		0.0400		0.1240
2004		0.0500


Year	Options Granted	Range of Exercise Prices		Weighted Average Exercise Price
2002	2,305,000	$	8.25 – $12.66	$	8.41
2003	2,122,000	$	13.59 – $17.13		13.62
2004	1,627,000	$	25.84		25.84


Year	Options Granted	Range of Exercise Prices		Weighted Average Exercise Price
2002	78,100	$	11.30 - $12.80	$	11.60
2003	78,100	$	15.39		15.39
2004	15,000	$	26.23		26.23


	Less than One Year		1 – 3 Years		3 – 5 Years		After 5 Years		Total
Long term debt	$	—	$	370,000		—	$	—	$	370,000
Firm transportation agreement		582		1,164		1,164		8,631		11,541
Non-cancelable operating leases		1,216		3,032		2,160		—		6,408

Total contractual cash obligations	$	1,798	$	374,196	$	3,324	$	8,631	$	387,949


	2003		2004
Federal statutory rate	35	%	35	%
State income tax rate, net of federal benefit	3	%	3	%

Effective income tax rate	38	%	38	%


	Expenditures (in millions)		Drillings/ Deepenings	Refracs/ Trifracs	Recompletions
Wattenberg	$	24.3	27	117	1
Mid Continent		22.2	46	—	12
San Juan		3.3	5	—	2
Central and Other		3.9	10	—	12

Total	$	53.7


	March 31, 2004
	Borrowing Base		Outstanding		Available
Revolving Credit Facility	$	500,000	$	370,000	$	130,000


	Average Prices
	Oil		Natural Gas		Equivalent Mcf
	(Per Bbl)		(Per Mcf)		(Per Mcfe)
Annual
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
2003		30.17		4.21		4.49

Quarterly

2003
First	$	33.33	$	4.26	$	4.69
Second		28.18		4.02		4.27
Third		29.40		4.27		4.49
Fourth		30.30		4.27		4.53

2004
First	$	34.01	$	4.98	$	5.22


	Oil (Bbls per day)			Gas (Mcfs per day)				Total (Mcfe per day)
	2003	2004	Change	2003	2004	Change		2003	2004	Change
Wattenberg	7,309	8,736	1,427	139,681	143,190	3,509		183,534	195,606	12,072
Mid Continent	2,497	5,060	2,563	17,728	49,936	32,208		32,710	80,297	47,587
San Juan	—	24	24	—	9,133	9,133		—	9,275	9,275
Central and Other	3,579	3,924	345	3,107	2,512	(595	)	24,580	26,059	1,479

Total	13,385	17,744	4,359	160,516	204,771	44,255		240,824	311,237	70,413


	Oil $/Bbls									Gas $/Mcf									Total $/Mcfe
	2003			2004			Change			2003			2004			Change			2003			2004			Change
Wattenberg	$	34.24		$	34.97		$	0.73		$	3.95		$	4.82		$	0.87		$	4.37		$	5.09		$	0.72
Mid Continent		31.92			32.72			0.80			6.61			5.36			(1.25	)		6.02			5.39			(0.63	)
San Juan		—			29.66			N/A			—			5.46			N/A			—			5.45			N/A
Central and Other		32.46			33.57			1.11			4.75			4.86			0.11			5.33			5.52			0.19

Subtotal		33.33			34.01			0.68			4.26			4.98			0.72			4.69			5.22			0.53
Hedging		(6.60	)		(7.39	)		(0.79	)		(0.29	)		(0.36	)		(0.07	)		(0.56	)		(0.66	)		(0.10	)

Total	$	26.73		$	26.62		$	(0.11	)	$	3.97		$	4.62		$	0.65		$	4.13		$	4.56		$	0.43


	Number of Shares Purchased	Average Price Per Share		Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽¹⁾	Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs ⁽¹⁾
January 2004	420,000	$	21.95	420,000	$	15,779,000
February 2004	247,800	$	22.25	247,800		25,000,000
March 2004	—	$	—	—		25,000,000

Total	667,800	$	22.06	667,800