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 72,023,526 shares of common stock outstanding on May 2, 2005, exclusive of 2,095,832 common shares held in a deferred compensation plan which are treated as 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 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 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 western 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 Wattenberg 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 few years, the Company has made a series of acquisitions in an effort to expand and diversify its 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. In January 2003, the Company purchased the remaining 50% interest in Elysium for $23.1 million. Elysium’s properties are located in Illinois, central Kansas and Louisiana, and primarily produce oil. 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. The Le Norman 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. The Bravo 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. The LNP 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.

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 Le Norman, LNP, Bravo, and certain Cordillera properties (collectively, “Mid Continent”) and Elysium (“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 2005 production, Wattenberg accounted for approximately 59%, Mid Continent for 30%, San Juan for 3% and Central and Other for 8% of daily oil and gas production on an equivalent basis.

On December 15, 2004, the boards of directors of Patina and Noble Energy approved Patina’s merger with Noble Energy, Inc. As a result of the merger, Patina will merge into a wholly owned subsidiary of Noble Energy, and Patina shareholders will receive aggregate consideration comprised of approximately 60% Noble Energy common stock and 40% cash. Total consideration for the outstanding shares of Patina Common Stock is fixed at approximately $1.1 billion in cash and approximately 27.8 million shares of Noble Energy common stock (in each case subject to upward adjustment in the event that any shares of Patina Common Stock are issued prior to closing upon exercise of Patina stock options or warrants or otherwise, as provided in the merger agreement). Under the terms of the merger agreement, Patina shareholders will have the right to elect to receive either cash or Noble Energy common stock, or a combination thereof, in exchange for their shares of Patina Common Stock, subject to an allocation mechanism if either the cash election or the stock election is oversubscribed. While the per share consideration was initially set in the merger agreement at $37.00 in cash or .6252 shares of Noble Energy common stock, the per share consideration is subject to adjustment upwards or downwards. The value of the merger consideration to be received with respect to each share of Patina Common Stock will be equal to $14.80 plus approximately $0.375 per $1.00 of the volume-weighted average of the trading sale prices per share of Noble Energy common stock as reported on the New York Stock Exchange during a specified period prior to closing. Regardless of whether a Patina shareholder elects to receive cash, Noble Energy common stock or a combination of cash and Noble Energy common stock, or make no election, the merger agreement contains provisions designed to cause the value of the per share consideration a Patina shareholder receives to be substantially equivalent. The proposed merger is subject to the approval of the shareholders of Patina and Noble Energy and other customary conditions. The companies will hold separate meetings of their shareholders on May 11, 2005 to vote on the merger. Assuming shareholder approval is received, the merger is expected to be completed within a few days following the shareholder meetings. Forward-looking statements in this Quarterly Report on Form 10-Q reflect the Company’s current plans as a stand-alone entity and do not take into account the impact of the proposed merger with Noble Energy, except where such statements specifically relate to the proposed merger.

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. Generally, if an exploratory well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense. Costs of drilling and completing development 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. The Company revises its unit-of-production amortization rates whenever there is an indication of the need for revision and at least annually. Oil is converted to natural gas equivalents (Mcfe) at the rate of one barrel to six Mcf. Amortization of capitalized costs has 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 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, the Company recorded an asset retirement obligation of approximately $21.4 million to reflect the 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 March 31, 2005, an asset retirement obligation of $31.8 million is recorded in Other noncurrent liabilities. A reconciliation of the changes in the Company’s liability from December 31, 2004 to March 31, 2005 is as 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, 2004, the balance represented $25.0 million in assets held in a deferred compensation plan. At March 31, 2005, the balance primarily represented $24.8 million in assets held in a deferred compensation plan. See Note (7).

The Company records revenues from the sales of crude oil, natural gas, and natural gas liquids when the product is delivered to the purchaser at a fixed or determinable price, title has transferred and collectibility is reasonably assured. Gathering and processing costs are accounted for as a reduction to revenue.

The Company follows the sales method to account for gas imbalances. Imbalances occur when the Company sells more or less product than it is entitled to under its ownership percentage. If the Company’s excess sales of production volumes for a well exceed the estimated net remaining recoverable reserves of the well, a liability is recorded. Gas imbalances at December 31, 2004 and March 31, 2005 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 components of accumulated other comprehensive loss and related tax effects for the three months ended March 31, 2005 were as follows (in thousands):

Comprehensive loss for the three months ended March 31, 2004 and 2005 totaled ($6.1) million and ($55.3) million, respectively.

The book value and estimated fair value of cash and equivalents was $3.0 million and $1.9 million at December 31, 2004 and March 31, 2005, respectively. The book value and estimated fair value of bank debt was $297.0 million and $288.0 million at December 31, 2004 and March 31, 2005, 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 interest rate derivative contracts to help manage its exposure to interest rate volatility. The contracts are placed with major financial institutions or with counterparties which management believes to be of high credit quality. The Company’s interest rate swap contracts are designated as cash flow hedges. During the fourth quarter of 2003, the Company entered into LIBOR swap contracts to fix the interest rate on $100.0 million of the Company’s LIBOR based floating rate bank debt for two years. At March 31, 2005, the net unrealized pretax gains on these contracts totaled $939,000 ($592,000 gain net of $347,000 of deferred taxes) based on LIBOR futures prices at March 31, 2005.

The Company regularly enters into commodity 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, 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 quarters of 2004 and 2005, recognizing losses of $11.9 million and $30.6 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 2004 and 2005, recognizing losses of $6.7 million and $4.8 million, respectively, related to these contracts.

At March 31, 2005, the Company was a party to swap contracts for oil based on NYMEX prices covering approximately 13,700 barrels of oil per day for the remainder of 2005 at fixed prices ranging from $23.51 to $26.50 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $24.69 per barrel for the remainder of 2005. The Company also entered into swap contracts for oil for 2006 as of March 31, 2005, which are summarized in the table below. The net unrealized losses on the contracts totaled $221.4 million based on NYMEX futures prices at March 31, 2005.

At March 31, 2005, the Company was a party to swap contracts for natural gas based on CIG, EPSJ, ANR and PEPL index prices covering approximately 127,600 MMBtu’s per day for the remainder of 2005 at fixed prices ranging from $2.83 to $6.19 per MMBtu. The overall weighted average hedged price for the swap contracts is $4.16 per MMBtu for the remainder of 2005. The Company also entered into natural gas swap contracts for 2006 as of March 31, 2005, which are summarized in the table below. The net unrealized losses on these contracts totaled $151.1 million based on futures prices at March 31, 2005.

At March 31, 2005, 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 established by its counterparties. At December 31, 2004 and March 31, 2005, the Company had $11.9 million and $34.3 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 2005, net hedging losses of $35.2 million ($22.2 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 $196.3 million ($125.8 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 2005.

As of March 31, 2005, the Company had net unrealized hedging losses of $371.6 million ($234.1 million after tax), comprised of $939,000 of current assets, $265.6 million of current liabilities and $106.9 million of non-current liabilities. Based on estimated futures prices as of March 31, 2005, the Company expects to reclassify as a decrease to earnings during the next twelve months $264.6 million ($166.7 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 deferred compensation plan in accordance with EITF 97-14. See Note (7).

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 exercise prices not less than 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 months ended March 31, 2004 and 2005, 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 2004 and 2005: dividend yields of 1% and 1%; expected volatility of 29% and 31%; risk-free interest rates of 3.0% and 3.9%; and expected lives of 3.8 years and 3.9 years, respectively.

In February 2004, the Company declared a 2-for-1 stock split in which shareholders received an additional share of Common Stock for every share held. All share and per share amounts for all periods have been restated to reflect the 2-for-1 stock split.

The Company uses weighted average shares outstanding in calculating earnings per share. When dilutive, stock options and Common Stock issuable upon the exercise 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 December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R is a revision of SFAS No. 123, “Accounting for Stock Based Compensation,” and supersedes APB Opinion No. 25. Among other items, SFAS No. 123R eliminates the use of APB 25 and the intrinsic value method of accounting, and requires companies to recognize the cost of employee services received in exchange for awards of equity instruments, based on the grant date fair value of those awards, in the financial statements. The effective date of SFAS No. 123R for the Company is January 1, 2006. SFAS No. 123R permits companies to adopt its requirements using either a “modified prospective” method, or a “modified retrospective” method. Under the “modified prospective” method, compensation cost is recognized in the financial statements beginning with the effective date, based on the requirements of SFAS No. 123R for all share-based payments granted after that date, and based on the requirements of SFAS No. 123 for all unvested awards granted prior to the effective date of SFAS No. 123R. Under the “modified retrospective” method, the requirements are the same as under the “modified prospective” method, but also permits entities to restate financial statements of previous periods, either for all prior periods presented or to the beginning of the fiscal year in which the statement is adopted, based on previous pro forma disclosures made in accordance with SFAS No. 123. The Company has not yet determined which of the methods it will use upon adoption.

The Company currently utilizes the Black-Scholes option pricing model to measure the fair value of stock options granted to employees. While SFAS No. 123R permits entities to continue to use such a model, it also permits the use of a “lattice” model. The Company expects to continue using the Black-Scholes option pricing model upon adoption of SFAS No. 123R to measure the fair value of stock options.

The adoption of this statement will have the effect of reducing net income and income per share as compared to what would be reported under the current requirements. These future amounts cannot be precisely estimated because they depend on, among other things, the number of options issued in the future, and accordingly, the Company has not determined the impact of adoption of this statement on its results of operations.

SFAS No. 123R also requires that the benefits associated with the tax deductions in excess of recognized compensation cost be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after the effective date. These future amounts cannot be estimated, because they depend on, among other things, when employees exercise stock options. However, the amount of operating cash flows recognized in prior periods for such excess tax deductions, as shown in the Company’s consolidated statements of cash flows for the three months ended March 31, 2005 and 2004 were $11.7 million and $8.8 million, respectively.

The cost of oil and gas properties at December 31, 2004 and March 31, 2005 included approximately $9.1 million and $12.9 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 Company had no significant wells in progress at December 31, 2004 and March 31, 2005. The following table sets forth costs incurred related to oil and gas properties.

The disposition of properties in 2004 primarily relates to the sale of the Company’s Adams Baggett, Texas properties for $15.2 million, the sale of certain Permian Basin properties for $6.0 million, the sale of certain properties in Denton County, Texas for $2.0 million, and the sale of the Company’s interest in Moffat County, Colorado for $1.0 million.

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 2004 and the first quarter of 2005, additions to oil and gas properties of approximately $3.7 million and $321,000, respectively, were recorded for the estimated asset retirement costs related to new wells drilled or acquired and to changes in the estimated timing or costs of retirement, respectively.

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, 2005. The Company had $212.0 million available under the Credit Agreement at March 31, 2005.

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 4.1% during the first quarter of 2005 and 4.4% at March 31, 2005.

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, 2004 and March 31, 2005, 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 $155.9 million as of March 31, 2005, which may be used to repurchase equity securities, pay dividends or make other restricted payments.

Effective November 1, 2003, the Company entered into interest rate swap for a two-year period. The contract is for $100.0 million principal with a fixed interest rate of 1.83% on the two-year term 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 rate of 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 2005 and 2006, and $288.0 million in the first quarter of 2007 and zero in 2008, 2009, and 2010. 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 $3.0 million and $3.6 million during the first quarters of 2004 and 2005, respectively.

A total of 250.0 million common shares, $0.01 par value, are authorized of which 74.0 million were issued at March 31, 2005. The Common Stock is listed on the New York Stock Exchange. In February 2004, the Company declared a 2-for-1 stock split in which shareholders received an additional share of Common Stock for every share held. All share and per share amounts for all periods have been restated to reflect the 2-for-1 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, 2004:

Adjusted for the stock dividends and split, the following is a schedule of quarterly cash dividends paid on the Common Stock since 2003:

During 2004, the Company repurchased and retired shares of its Common Stock for $14.7 million. The Company has been authorized by its Board of Directors to repurchase up to $25.0 million of Common Stock. The repurchase program has no set expiration or termination date.

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, 2005, 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, 2004 and March 31, 2005.

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 vested 30% in May 2004 and are scheduled to vest 30% in May 2005 and 40% in May 2006. In June 2004, the Compensation Committee awarded a stock grant totaling 14,000 shares of restricted Common Stock to the non-employee directors of the Company as a component of their annual retainer. The shares vest 30% in June 2005, 30% in June 2006 and 40% in June 2007. In July 2004, the Board of Directors approved the issuance of 16,000 shares of restricted Common Stock to a Senior Vice President of Operations in connection with the commencement of his employment with the Company. A portion of such shares (4,000) were immediately vested upon the date of grant and 6,000 of such shares shall vest on each of the first and second anniversaries of the date of grant. The non-vested shares from such grants have been recorded as Deferred compensation in the equity section of the accompanying consolidated balance sheets. Upon completion of the merger with Noble Energy, these grants will become fully vested. See Note (2).

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 and 2005, the calculation of diluted earnings per share excluded 1.6 million and 1.4 million, respectively, outstanding stock options as they were anti-dilutive.

The Company maintains a profit sharing and 401(k) 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 in cash of $1.4 million and $1.8 million for 2003 and 2004, respectively.

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 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 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, may be available to satisfy the claims of the Company’s creditors in the event of bankruptcy or insolvency. 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 participants’ individual account within the Trust, however, the Plan Administrator is not required to honor such requests. Matching contributions are made in cash or Common Stock and vest ratably over a three-year period. Participants may elect to receive distributions in either cash or Common Stock. At March 31, 2005, the balance of the assets in the Trust totaled $108.6 million, including 2,095,832 shares of Common Stock valued at $83.8 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 19 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 of the Company. The Company’s Common Stock held by the Trust has been classified as treasury stock in the stockholders’ equity section of the accompanying consolidated balance sheets as required by accounting principals generally

accepted in the United States. 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, 2004 and March 31, 2005, was $25.0 million and $24.8 million, respectively, and is classified as Other Assets in the accompanying consolidated balance sheets. The amounts payable to the plan participants at December 31, 2004 and March 31, 2005, including the market value of the shares of the Company’s Common Stock that are reflected as treasury stock, was $103.6 million and $108.6 million, respectively, and is classified as Deferred Compensation Liability in the accompanying consolidated balance sheets. Approximately 2,000,000 shares or 95% of the Common Stock held in the Plan were attributable to the Chief Executive Officer at March 31, 2005.

In accordance with EITF 97-14, all market fluctuations in value of the Trust assets have been reflected in the accompanying consolidated statements of operations. 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 revenues in the accompanying consolidated statements of operations. 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 accompanying consolidated statements of operations. Based on the changes in the total market value of the Trust’s assets, the Company recorded deferred compensation adjustments of $4.7 million and $4.9 million in the first quarters of 2004 and 2005, respectively.

The Company maintains a shareholder approved stock option plan for employees (the “Employee Plan”) providing for the issuance of options at exercise prices not less than fair market value at 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 generally vest in annual installments 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 shares of Common Stock in partial payment of their annual retainers. A total of 700 restricted shares were issued in 2004 under the Directors’ Plan with respect to the first quarter 2004 Director fees. Effective May 2004, the Board of Directors suspended the automatic restricted stock grant provisions of the Directors’ Plan. In June 2004, the Compensation Committee awarded a stock grant outside of the Directors’ Plan totaling 14,000 shares of restricted Common Stock to the non-employee directors as a component of their annual retainer. The shares vest 30% in June 2005, 30% in June 2006 and 40% in June 2007. The Directors’ Plan also provides for stock options to be granted to each non-employee Director upon appointment and upon annual re-election, thereafter. The options vest in annual installments 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:

Upon completion of the merger with Noble Energy, all outstanding unvested stock options will become fully vested. See Note (2).

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, 2004 and 2005 follows:

Current income tax expense in the three months ended March 31, 2004 and 2005 totaled $9.8 million and $14.2 million, respectively. The Company expects to utilize approximately $8.7 million of net operating loss carryforwards in 2005 to reduce current taxes.

For tax purposes, the Company had net operating loss carryforwards of approximately $23.5 million at December 31, 2004. Utilization of these losses will be limited each year as a result of various acquisitions. These carryforwards expire from 2009 through 2023. The Company has provided a $3.2 million valuation allowance against the loss carryforwards that could expire unutilized. At December 31, 2004, the Company had depletion deduction carryforwards of approximately $13.0 million that are available indefinitely. The Company paid $1.0 million and zero in federal and state taxes during the three months ended March 31, 2004 and 2005, respectively.

During October 2004, H.R. 4520, the “American Jobs Creation Act of 2004,” was enacted. The Act provides for certain additional tax deductions from qualified taxable income beginning in 2005, subject to certain limitations. The Company recognized a 1% reduction in the effective federal tax rate during the first quarter of 2005 in response to the Act. The Company has not yet determined the full impact of this law.

During the three months ended March 31, 2004 and 2005, major customer A accounted for 23% and 18%, major customer B accounted for 17% and 12%, major customer C accounted for 9% and 12%, and major customer D accounted for 9% and 11% of revenues, respectively. Accounts receivable amounts from these customers at December 31, 2004 totaled $40.5 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 quarters of 2004 and 2005, $79,000 of income and $52,000 of losses, were recorded as a component of other revenues in the accompanying consolidated statements of operations reflecting proceeds of $6.7 million and $5.0 million from gas sold, net of costs of $6.6 million and $5.1 million, during the first quarters of 2004 and 2005, respectively. Future minimum lease payments under such leases and agreements approximate $2.1 million per year from 2005 through 2007, $1.7 million in 2008 and approximately $600,000 per year from 2009 to 2023.

The ruling by the Colorado Supreme Court in Rogers v. Westerman Farm Co. in July 2001 resulted in uncertainty regarding the deductibility of certain post-production costs from payments to be made to royalty interest owners. In January 2003, the Company was named as a defendant in a lawsuit, which plaintiff seeks to certify as a class action, based upon the Westerman ruling alleging that the Company had improperly deducted certain costs in connection with its calculation of royalty payments relating to the Company’s Colorado operations (Jack Holman, et al v. Patina Oil & Gas Corporation; Case No. 03-CV-09; District Court, Weld County, Colorado). In May 2004, the plaintiff filed an amended complaint narrowing the class of potential plaintiffs, and thereafter filed a motion seeking to certify the narrowed class as described in the amended complaint. The Company has filed an answer to the plaintiff’s amended complaint. The Company intends to oppose class certification and to vigorously defend this action. The potential liability, if any, 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 is also a party to various other lawsuits incidental to its business, none of which are anticipated to have a material adverse impact on its financial position or results of operations.

Pursuant to the merger agreement with Noble Energy, the Company has agreed to terminate its existing hedge positions prior to the closing of the merger. See Note (2). Due to the recent rise in oil and gas prices, the Company will require additional borrowing capacity beyond that expected to be available under the Company’s current credit facility to terminate the hedges. See Note (5). Accordingly, in May 2005, the Company entered into the Third Amendment to the Company’s credit facility and expects to execute an unsecured promissory note (the “Note”) in an amount up to $200.0 million with JPMorgan Chase Bank, N.A., in connection with the termination of the hedges. The Note will bear interest at the prime rate and be due on February 1, 2007 or immediately upon the termination of all commitments and the payment in full of all borrowings outstanding under the Company’s existing credit facility. It is expected that Noble Energy will pay in full all of the Company’s outstanding debt, including the Note, upon consummation of the merger.

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 western Oklahoma and the Texas Panhandle, and the San Juan Basin in New Mexico.

In December 2004, Patina entered into a merger agreement with Noble Energy, Inc. pursuant to which Patina will be acquired by Noble Energy through the merger of Patina into a wholly-owned subsidiary of Noble Energy. The merger is subject to customary conditions, including the approval of the shareholders of Patina and Noble Energy. The companies will hold separate meetings of their shareholders on May 11, 2005 to approve the merger. Assuming shareholder approval is received, the merger is expected to be completed within a few days following the shareholder meetings. For more information regarding the proposed merger, please refer to the Note (2) of the accompanying consolidated financial statements and the joint proxy statement/prospectus of Noble Energy and Patina that is included in the registration statement on Form S-4 (File No. 333-122262) filed by Noble Energy with the SEC, and other relevant materials that may be filed by Patina or Noble Energy with the SEC. The following discussion relates to our plans without regard to the potential impact of the proposed merger.

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 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.

Following are highlights of the Company’s performance in several key areas during the three months ended March 31, 2005:

Including the amounts spent in the first quarter of 2005 on development, the Company anticipates incurring approximately $300.0 million on the further development of its properties in 2005.

The preparation of the consolidated financial statements requires management of the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of the Company’s accounting estimates and judgments which management believes are most significant in its application of generally accepted accounting principles used in the preparation of the consolidated financial statements.

Reserves – The Company’s estimates of proved crude oil and natural gas reserves are prepared by the Company’s engineers in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, proved reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. Proved reserve estimates are updated annually at each year-end. Estimates of proved crude oil and natural gas reserves significantly affect the Company’s depreciation, depletion and amortization (“DD&A”) expense. For example, if estimates of proved reserves decline, the Company’s DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves would also trigger an impairment analysis and could result in an impairment charge.

Oil and Gas Properties – The Company accounts for its crude oil and natural gas properties under the successful efforts method of accounting. The alternative method of accounting for crude oil and natural gas properties is the full cost method. Under the successful efforts method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties are amortized to operations by the unit-of-production method based on proved developed crude oil and natural gas reserves as estimated by Company engineers. Application of the successful efforts method results in the expensing of certain costs including geological and geophysical costs, exploratory dry holes and delay rentals, during the periods the costs are incurred. Under the full cost method, these costs are capitalized as assets and charged to earnings in future periods as a component of DD&A expense.

Impairment of Oil and Gas Properties – The Company assesses proved crude oil and natural gas properties for possible impairment annually or whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. The Company recognizes an impairment loss when the estimated undiscounted future cash flows from a property are less than the current net book value. Estimated future cash flows are based on management’s expectations for the future and include estimates of crude oil and natural gas reserves and future commodity prices and development and operating costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising development or operating costs can result in a reduction in undiscounted future cash flows and could indicate a property impairment.

The Company also performs periodic assessments of individually significant unproved crude oil and natural gas properties for impairment. Management’s assessment of the results of exploration activities, estimated future commodity prices and development and operating costs, and availability of funds for future activities impact the amounts and timing of impairment provisions.

Asset Retirement Obligation – The Company’s asset retirement obligations (“ARO”) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and gas properties. Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; inflation rates; and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A. At December 31, 2004 and March 31, 2005, the Company’s consolidated balance sheet included a liability for ARO of $31.5 million and $31.8 million, respectively.

Derivative Instruments and Hedging Activities – The Company uses various derivative financial instruments to hedge its exposure to price risk from changing commodity prices. The Company does not enter into derivative or other financial instruments for trading purposes. Management exercises significant judgment in determining types of instruments to be used, production volumes to be hedged, prices at which to hedge and the counterparties and their creditworthiness. The Company accounts for its derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” For derivative instruments that qualify as cash flow hedges, an asset or liability is recorded on the balance sheet at its fair value. Changes in fair value, to the extent the hedge is effective, are recognized in accumulated other comprehensive income (“AOCI”) until the forecasted transaction is recognized in earnings. Therefore, prior to settlement of the derivative instruments, changes in the fair market value can cause significant increases or decreases in AOCI. For derivative instruments that do not qualify as cash flow hedges, changes in fair value must be reported in the current period, rather than in the period in which the forecasted transaction occurs. This may result in significant increases or decreases in current period net income.

Deferred Tax Asset Valuation Allowance – The Company’s balance sheet includes deferred tax assets related to deductible temporary differences and operating loss carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. As a result of management’s current assessment, the Company maintains a valuation allowance against a portion of its deferred tax assets. The Company will continue to monitor facts and circumstances in its reassessment of the likelihood that operating loss carryforwards and other deferred tax attributes will be utilized prior to their expiration. As a result, the Company may determine that the deferred tax asset valuation allowance should be increased or decreased. Such changes would impact net income through offsetting changes in income tax expense.

During the three months ended March 31, 2005, the Company spent $79.9 million on the further development of properties and $5.3 million on acquisitions. Acquisition expenditures were primarily comprised of $1.4 million for developed property acquisitions and $3.9 million for unproven property acquisitions, primarily leasehold acreage. Development expenditures included $37.9 million in Wattenberg for the drilling or deepening of 15 J-Sand wells, the drilling of 21 Codell wells, and performing 90 Codell refracs, 16 Niobrara refracs, two Codell trifracs and 41 recompletions, $31.8 million on the further development of the Mid Continent properties for the drilling or deepening of 39 wells, and performing nine recompletions, $6.3 million in the San Juan Basin for the drilling of nine wells and performing four recompletions, and $3.9 million on other properties (primarily in Illinois and Kansas), primarily for drilling or deepening 13 wells and performing three recompletions. These projects and the continued success in production enhancement allowed production to increase 6% over the prior year period. The decision to increase or decrease development activity is heavily dependent on the prices being received for production.

At March 31, 2005, the Company had $1.5 billion of assets. Total capitalization was $662.9 million, of which 57% was represented by stockholders’ equity and 43% by bank debt. During the first quarter of 2005, net cash provided by operations totaled $86.9 million, as compared to $91.0 million in 2004. At March 31, 2005, there were no significant commitments for capital expenditures. Although a $300.0 million capital budget has been approved for 2005, 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 cash flow from operations, 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 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 until maturity of the Credit Agreement. 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 March 31, 2005 and the effect such obligations are expected to have on its liquidity and cash flow in future periods (in thousands):

(a) Derivative obligations represent the estimated net unrealized pretax losses for the Company’s oil and gas and interest rate hedges based on futures prices as of March 31, 2005. The ultimate settlement amounts of these hedges are unknown because they are subject to continuing market risk. See Item 3. Quantitative and Qualitative Disclosures About Market Risk and Note (3) to the accompanying consolidated financial statements for more information regarding the Company’s derivative obligations.

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, 2005. A total of $212.0 million was available under the Credit Agreement at March 31, 2005.

Effective November 1, 2003, the Company entered into an interest rate swap for a two-year period. The contract is for $100.0 million principal with a fixed interest rate of 1.83% on the two-year term 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 rate of 1.83% and the three-month LIBOR rate, which is reset every 90 days, is received or paid every 90 days in arrears.

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, 2004 and 2005, 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 $155.9 million as of March 31, 2005, 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 2005 and 2006, respectively. The $79.9 million of development expenditures for the first quarter of 2005 were funded entirely with cash flow from operations. The Company has set a 2005 capital budget of $300.0 million, comprised primarily of $145.0 million of development expenditures in Wattenberg, $115.0 million in the Mid Continent region, $20.0 million in the San Juan Basin, and $20.0 million on the Central and Other properties. On March 31, 2005, the Company had $288.0 million outstanding under its bank facility. As such, exclusive of any significant acquisitions or equity repurchases, management expects to reduce long-term debt and fund the development program with cash flow from operations.

Net cash provided by operating activities in the three months ended March 31, 2004 and 2005 was $91.0 million and $86.9 million, respectively. Cash flow from operations decreased in 2005 due to large payments for margin deposits and a reduction in accounts payable, partially offset by increased cash flow as a result of the 6% increase in oil and gas equivalent production and the 17% increase in average oil and gas prices received. Lease operating expenses, production taxes, and general and administrative expenses all increased as a result of increased production, higher field costs, and additional employees. Operating cash flows in the first quarters of 2004 and 2005 were benefited by $8.8 million and $11.7 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, 2004 and 2005 totaled $35.2 million and $86.4 million, respectively. The increase in expenditures in 2005 was primarily due to an increase in development expenditures of $26.1 million, comprised primarily of increases in Wattenberg of $13.5 million, Mid Continent of $9.6 million and San Juan of $3.0 million. The net increase in expenditures in 2005 over 2004 was also the result of a $22.6 million decrease in proceeds from the sale of oil and gas properties, partially offset by an increase in acquisition expenditures of $2.3 million during the quarter.

Net cash used in financing activities in the three months ended March 31, 2004 and March 31, 2005 totaled $54.7 million and $1.5 million, respectively. Sources of financing have been primarily bank borrowings. 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 2005, the combination of operating cash flow and $11.9 million in proceeds from the exercise of stock options, allowed the Company to repay $9.0 million of bank debt, fund net capital development and acquisition expenditures of $85.1 million, and pay dividends of $4.4 million.

During the first quarter of 2005, $85.1 million of capital, net of $55,000 of property sales, was expended, including $79.9 million on development projects and $5.3 million on acquisitions. Development expenditures represented 92% of net cash provided by operating activities. The Company manages its capital budget with the goal of funding it with cash flow from operations. The Company anticipates spending approximately $300.0 million on the further development of its properties in 2005. Based on current futures prices for oil and natural gas, the Company expects its 2005 capital program to be funded with cash flow from operations. As such, exclusive of any other significant acquisitions or equity repurchases, management expects to continue to reduce long-term debt in 2005. 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 cash flow from operations.

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. At March 31, 2005, hedges were in place covering 55.3 Bcf at prices averaging $4.38 per MMBtu and 7.4 million barrels of oil averaging $25.66 per barrel. The estimated fair value of the Company’s oil and gas hedge contracts that would be realized on termination approximated a net unrealized pretax loss of $372.5 million ($234.7 million loss net of $137.8 million of deferred taxes) at March 31, 2005. The combined net unrealized losses from the Company’s oil, gas, and interest rate hedges are presented on the balance sheet as a current asset of $939,000, a current liability of $265.6 million, and a non-current liability of $106.9 million based on contract expirations. Both 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 realized losses relating to these derivatives totaled $18.6 million and $35.4 million in the three months ended March 31, 2004 and 2005, 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 2004 and 2005. 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, 2005 compared to the three months ended March 31, 2004.

Revenues for first quarter of 2005 totaled $159.3 million, a 15% increase from the prior year period. Net income for the first quarter of 2005 totaled $48.3 million, an increase of 13% from 2004. 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 quarter of 2005 totaled 18,527 barrels and 219.4 MMcf (330.6 MMcfe), an increase of 6% on an equivalent basis from the same period in 2004. The rise in production was due to the continued development activity in the Mid Continent and to a lesser degree in San Juan. During the first quarter of 2005, the Company drilled or deepened 36 wells, performed 106 refracs, two trifracs, and 41 recompletions in Wattenberg, compared to 27 new wells or deepenings, 115 refracs, two trifracs, and one recompletion in Wattenberg in 2004. During the first quarter of 2005, the Company drilled or deepened 39 wells and performed nine recompletions on its Mid Continent properties, compared to 46 new drills or deepenings and 12 recompletions for 2004. During the first quarter of 2005, the Company drilled nine wells and performed four recompletions on its San Juan properties, compared to five new drills and two recompletions for 2004. During 2005, the Company drilled or deepened 13 wells and performed three recompletions on its Central and Other properties, compared to 10 new drills or deepenings and 12 recompletions for 2004. The Company anticipates spending approximately $300.0 million on the further development of its properties in 2005. The following table sets forth summary information with respect to oil and natural gas production for the three months ended March 31, 2004 and 2005:

Average realized oil prices increased 12% from $26.62 per barrel in the first quarter of 2004 to $29.79 in 2005. Average realized gas prices increased 19% from $4.62 per Mcf in the first quarter of 2004 to $5.50 in 2005. Average oil prices include hedging losses of $11.9 million or $7.39 per barrel and $30.6 million or $18.37 per barrel in the first quarters of 2004 and 2005, respectively. Average gas prices included hedging losses of $6.7 million or $0.36 per Mcf in 2004 and $4.8 million or $0.24 per Mcf in 2005. The following table sets forth summary information with respect to oil and natural gas prices for the three months ended March 31, 2004 and 2005:

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 $19.9 million or $0.67 per Mcfe for the first quarter of 2005 compared to $15.7 million or $0.56 per Mcfe in the prior year period. The increase in operating expenses was primarily attributed to the 6% increase in oil and gas production and the general increase in operating costs in response to the significant increase in oil and gas prices. Production taxes totaled $12.2 million or $0.41 per Mcfe in the first quarter of 2005 compared to $10.5 million or $0.37 per Mcfe in 2004. The $1.7 million increase was a result of higher oil and gas prices and production.

General and administrative expenses for the first quarter of 2005 totaled $7.1 million, an increase of $1.8 million or 34% over the same period in 2004. The increase was largely attributed to additional employees hired in conjunction with the acquisitions made in the last two years, the increase in salaries and wages within the industry and additional employees hired in conjunction with the increased capital development program.

Interest expense remained relatively constant at $3.1 million in the first quarter of 2005 as compared to the prior year period. The slight decrease in interest expense was a result of lower average debt balances, offset by higher interest rates. The Company’s average interest rate during the first quarter of 2005 was 4.1% compared to 2.6% in 2004.

Deferred compensation adjustment totaled $4.9 million in the first quarter of 2005, an increase of $205,000 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 2004. The Company’s Common Stock price appreciated by 7% or $2.50 per share in the first quarter of 2005 versus an increase of 7% or $1.75 per share in the first quarter of 2004.

Depletion, depreciation and amortization expense for the first quarter of 2005 totaled $34.9 million, an increase of $5.4 million or 18% from the first quarter of 2004. Depletion expense totaled $33.7 million or $1.13 per Mcfe for the first quarter of 2005 compared to $28.4 million or $1.00 per Mcfe for 2004. The increase in depletion expense resulted from the increase in oil and gas production in the first quarter of 2005 and revised depletion rates based on the year-end 2004 reserve report. Depreciation and amortization expense for the three months ended March 31, 2005 totaled $781,000 or $0.03 per Mcfe compared to $666,000 or $0.02 per Mcfe in the first quarter of 2004. Accretion expense related to SFAS No. 143 totaled $409,000 in the first quarter of 2005 compared to $360,000 in the first quarter of 2004.

Provision for income taxes for the first quarter of 2005 totaled $28.4 million, an increase of $2.2 million from the same period in 2004. The increase was due to higher pretax earnings slightly offset by a lower effective tax rate. A 38% tax provision was recorded for the first quarter of 2004 and a 37% tax provision was recorded for the first quarter of 2005 due to the impact of the American Jobs Creation Act of 2004.

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 2004 and the first quarter of 2005, exclusive of any hedges, ranged from a monthly low of $4.51 per Mcf to a monthly high of $7.09 per Mcf. Oil prices, exclusive of any hedges, ranged from a monthly low of $32.90 per barrel to a monthly high of $52.79 per barrel during 2004 and the first quarter of 2005. 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 2005, a 10% reduction in oil and gas prices, excluding oil and gas quantities that were fixed through hedging transactions, would have reduced revenues by $5.8 million. If oil and gas futures prices at March 31, 2005 had declined by 10%, the net unrealized pretax hedging losses at that date would have decreased by $80.4 million (from $372.5 million to $292.1 million).

At March 31, 2005, the Company was a party to swap contracts for natural gas based on CIG, EPSJ, ANR and PEPL index prices covering approximately 127,600 MMBtu’s per day for the remainder of 2005 at fixed prices ranging from $2.83 to $6.19 per MMBtu. The overall weighted average hedged price for the swap contracts is $4.16 per MMBtu for the remainder of 2005. The Company was also a party to natural gas swap contracts for 2006 as of March 31, 2005, which are summarized in the table below. The net unrealized losses on the contracts totaled $151.1 million based on futures prices at March 31, 2005.

At March 31, 2005, 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 2004 averaged $0.97 per MMBtu discount from NYMEX, ranging from a discount of $0.58 per MMBtu in September 2004 to a discount of $1.78 per MMBtu in December 2004. Based on the actual indices for January 2005 through March 2005 and futures prices as of March 31, 2005, the CIG basis differential for 2005 averages a $0.82 per MMBtu discount, ranging from a discount of $0.62 per MMBtu in January 2005 to a discount of $1.04 per MMBtu in April 2005. 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.

At March 31, 2005, the Company had $288.0 million outstanding under its credit facility with an average interest rate of 4.4%. 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 4.1% during the first quarter 2005. Assuming no change in the amount outstanding at March 31, 2005, the annual impact on interest expense of a ten percent change in the average interest rate would be approximately $737,000, 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. Statements in this quarterly report regarding the Company’s strategy, risk factors, capital budget, projected expenditures, liquidity and capital resources, and drilling and development plans reflect the Company’s current plans for 2005 as a stand-alone entity and do not take into account the impact of the proposed merger with Noble Energy, Inc., except where such statements specifically relate to the proposed merger. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-Q and in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004. Such forward-looking statements appear in a number of places and include statements with respect to, among other things, such matters as: the proposed merger with Noble Energy, Inc., future capital, development and exploration expenditures (including the amount and nature thereof), drilling, deepening, refracing, or trifracing of wells, oil and gas reserve estimates (including estimates of future net revenues associated with such reserves and the PV10% 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, in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004, and in the Registration Statement on Form S-4 (Reg. No. 333-122262) filed by Noble Energy relating to the proposed merger.

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, in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 or in the Registration Statement on Form S-4 relating to the proposed merger with Noble Energy 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 furnishes 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.

In designing and evaluating the Company’s disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company’s controls will succeed in achieving their goals under all potential future conditions.

In addition, the Company is continuously seeking to improve the efficiency and effectiveness of its internal controls. This results in periodic refinements to internal control processes throughout the Company. However, there have been no significant changes in the Company’s internal controls over financial reporting or in other factors that could significantly affect these controls that occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Information with respect to this item is incorporated by reference from Note (10) to the Consolidated Financial Statements in Part 1 of this report.

Exhibits – The following documents are filed as exhibits to this Quarterly Report on Form 10-Q:

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,
		Chief Financial Officer and Director


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


	December 31, 2004			March 31, 2005
				(Unaudited)
ASSETS
Current assets
Cash and equivalents	$	3,024		$	1,949
Accounts receivable		83,444			82,209
Inventory and other		25,542			46,917
Income taxes receivable		7,137			—
Deferred income taxes		54,817			97,912
Unrealized hedging gains		7,256			939

		181,220			229,926

Oil and gas properties, successful efforts method		1,893,069			1,978,294
Accumulated depletion, depreciation and amortization		(681,394	)		(715,055	)

		1,211,675			1,263,239

Field equipment and other		18,622			19,869
Accumulated depreciation		(8,681	)		(9,382	)

		9,941			10,487

Other assets, net		26,203			25,889

	$	1,429,039		$	1,529,541

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	105,822		$	97,701
Accrued liabilities		28,135			31,064
Unrealized hedging losses		151,512			265,565

		285,469			394,330

Bank debt		297,000			288,000
Deferred income taxes		203,473			198,629
Other noncurrent liabilities		62,477			58,096
Unrealized hedging losses		66,167			106,948
Deferred compensation liability		103,634			108,601

Commitments and contingencies

Stockholders’ equity
Preferred Stock, $.01 par, 5,000,000 shares authorized, none issued or outstanding		—			—
Common Stock, $.01 par, 250,000,000 shares authorized, 72,781,701 and 73,997,459 shares issued		728			740
Less Common Stock Held in Treasury, at cost, 2,097,912 and 2,095,832 shares		(6,945	)		(6,936	)
Capital in excess of par value		207,017			230,710
Deferred compensation		(1,011	)		(876	)
Retained earnings		341,492			385,391
Accumulated other comprehensive loss		(130,462	)		(234,092	)

		410,819			374,937

	$	1,429,039		$	1,529,541


	Three Months Ended March 31,
	2004		2005
Revenues
Oil and gas sales (net of gathering and processing costs of $4,196 and $5,289 respectively)	$	129,068	$	158,254
Gain on sale of oil and gas properties		7,384		—
Other		1,474		1,039

		137,926		159,293

Expenses
Lease operating		15,738		19,925
Production taxes		10,536		12,197
Exploration		93		255
General and administrative		5,334		7,132
Interest		3,099		3,087
Other		53		208
Deferred compensation adjustment		4,708		4,913
Depletion, depreciation and amortization		29,411		34,850

		68,972		82,567

Pretax income		68,954		76,726

Provision for income taxes
Current		9,826		14,195
Deferred		16,377		14,194

		26,203		28,389

Net income	$	42,751	$	48,337

Net income per share
Basic	$	0.62	$	0.68

Diluted	$	0.59	$	0.65

Weighted average shares outstanding
Basic		69,209		71,223

Diluted		72,345		74,621


	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, 2003	$	—	71,505		$	715		$	(7,850	)	$	187,171		$	(764	)	$	205,786		$	(54,546	)	$	330,512

Repurchase of common stock		—	(668	)		(7	)		—			(14,727	)		—			—			—			(14,734	)
Issuance of common stock		—	1,945			20			—			14,372			(832	)		—			—			13,560
Deferred compensation stock issued, net		—	—			—			905			9,457			—			—			—			10,362
Amortization of stock grant		—	—			—			—			—			585			—			—			585
Tax benefit from stock options		—	—			—			—			10,744			—			—			—			10,744
Dividends		—	—			—			—			—			—			(15,257	)		—			(15,257	)
Comprehensive income:
Net income		—	—			—			—			—			—			150,963			—			150,963
Contract settlements reclassed to income		—	—			—			—			—			—			—			90,251			90,251
Change in unrealized hedging losses		—	—			—			—			—			—			—			(166,167	)		(166,167	)

Total comprehensive income		—	—			—			—			—			—			150,963			(75,916	)		75,047

Balance at December 31, 2004		—	72,782			728			(6,945	)		207,017			(1,011	)		341,492			(130,462	)		410,819

Issuance of common stock		—	1,215			12			—			11,887			—			—			—			11,899
Deferred compensation stock issued, net		—	—			—			9			68			—			—			—			77
Amortization of stock grant		—	—			—			—			—			135			—			—			135
Tax benefit from stock options		—	—			—			—			11,738			—			—			—			11,738
Dividends		—	—			—			—			—			—			(4,438	)		—			(4,438	)
Comprehensive loss:
Net income		—	—			—			—			—			—			48,337			—			48,337
Contract settlements reclassed to income		—	—			—			—			—			—			—			22,174			22,174
Change in unrealized hedging losses		—	—			—			—			—			—			—			(125,804	)		(125,804	)

Total comprehensive loss		—	—			—			—			—			—			48,337			(103,630	)		(55,293	)

Balance at March 31, 2005	$	—	73,997		$	740		$	(6,936	)	$	230,710		$	(876	)	$	385,391		$	(234,092	)	$	374,937


	Three Months Ended March 31,
	2004			2005
Operating activities
Net income	$	42,751		$	48,337
Adjustments to reconcile net income to net cash provided by operating activities
Exploration expense		93			47
Depletion, depreciation and amortization		29,411			34,850
Deferred income taxes		16,377			14,194
Tax benefit from exercise of stock options		8,789			11,738
Deferred compensation adjustment		4,708			4,913
Loss (gain) on deferred compensation asset		(381	)		325
Gain on sale of oil and gas properties		(7,384	)		—
Other		331			255
Changes in current and other assets and liabilities
Decrease (increase) in
Accounts receivable		2,124			1,235
Inventory and other		(12,552	)		(21,234	)
Increase (decrease) in
Accounts payable		5,453			(8,121	)
Income taxes payable		—			2,526
Accrued liabilities		(78	)		2,928
Other assets and liabilities		1,327			(5,080	)

Net cash provided by operating activities		90,969			86,913

Investing activities
Development and exploration		(53,774	)		(79,856	)
Acquisitions, net of cash acquired		(3,000	)		(5,291	)
Disposition of oil and gas properties		22,684			55
Furniture, fixtures, and equipment		(1,084	)		(1,357	)

Net cash used in investing activities		(35,174	)		(86,449	)

Financing activities
Proceeds from borrowings on revolving credit facility		112,000			146,500
Repayments of borrowings on revolving credit facility		(158,000	)		(155,500	)
Issuance of common stock		9,643			11,899
Repurchase of common stock		(14,734	)		—
Common stock dividends		(3,613	)		(4,438	)

Net cash used in financing activities		(54,704	)		(1,539	)

Increase (decrease) in cash		1,091			(1,075	)
Cash and equivalents, beginning of period		545			3,024

Cash and equivalents, end of period	$	1,636		$	1,949


Asset retirement obligation at December 31, 2004	$	31,461
Liabilities incurred		321
Liabilities settled		(438	)
Accretion expense		409

Asset retirement obligation at March 31, 2005	$	31,753


	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive loss at 12/31/04	$	(210,423	)	$	79,961		$	(130,462	)
Change in fair value of hedges		(196,348	)		70,544			(125,804	)
Contract settlements during the quarter		35,196			(13,022	)		22,174

Accumulated other comprehensive loss at 03/31/05	$	(371,575	)	$	137,483		$	(234,092	)


	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)
04/01/05 - 06/30/05	13,700	24.80	(39,527	)	80,000	3.83	(20,732	)
07/01/05 - 09/30/05	13,700	24.67	(40,627	)	80,700	3.84	(24,395	)
10/01/05 - 12/31/05	13,700	24.60	(40,041	)	80,700	4.13	(24,673	)

01/01/06 - 03/31/06	9,900	26.80	(25,693	)	35,000	5.20	(8,564	)
04/01/06 - 06/30/06	9,900	26.70	(25,482	)	35,000	4.42	(6,352	)
07/01/06 - 09/30/06	9,900	26.61	(25,263	)	35,000	4.41	(6,759	)
10/01/06 - 12/31/06	9,900	26.55	(24,730	)	35,000	4.66	(6,855	)

	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)
04/01/05 - 06/30/05	38,100	4.63	(8,283	)	9,050	3.97	(2,264	)
07/01/05 - 09/30/05	38,100	4.58	(9,986	)	9,050	3.99	(2,696	)
10/01/05 - 12/31/05	38,100	4.77	(10,486	)	9,050	4.22	(2,747	)

01/01/06 - 03/31/06	16,700	5.53	(3,983	)	3,500	5.16	(868	)
04/01/06 - 06/30/06	16,700	4.80	(2,975	)	3,700	4.39	(710	)
07/01/06 - 09/30/06	16,700	4.78	(3,081	)	3,700	4.29	(778	)
10/01/06 - 12/31/06	16,700	4.99	(3,212	)	3,700	4.62	(751	)


	Year Ended December 31, 2004			Three Months Ended March 31, 2005
	(In thousands, except per Mcfe amounts)
Development	$	253,862		$	79,856
Acquisition - evaluated		20,176			1,402
Acquisition - unevaluated		9,146			3,889
Exploration and other		2,058			255

	$	285,242		$	85,402

Asset retirement costs	$	3,685		$	321

Disposition of properties	$	(29,003	)	$	(55	)

Depletion rate (per Mcfe)	$	1.04		$	1.13


	December 31, 2004		March 31, 2005
	(In thousands)
Bank debt	$	297,000	$	288,000
Less current portion		—		—

Bank debt, net	$	297,000	$	288,000


	Year Ended December 31, 2004		Three Months Ended March 31, 2005
Beginning shares	71,505,000		72,781,700
Exercise of stock options	1,925,500		1,215,800
Issued for directors fees	700		—
Vesting of stock grant	18,300		—

Total shares issued	1,944,500		1,215,800
Repurchases	(667,800	)	—

Ending shares	72,781,700		73,997,500
Treasury shares held in deferred comp (Note 7)	(2,097,900	)	(2,095,800	)

Adjusted shares outstanding	70,683,800		71,901,700


	Quarter
	First		Second		Third		Fourth		Total
2003	$	0.0240	$	0.0300	$	0.0300	$	0.0400	$	0.1240
2004		0.0500		0.0500		0.0500		0.0600		0.2100
2005		0.0600


Year	Options Granted	Range of Exercise Prices	Weighted Average Exercise Price
2003	2,122,000	$13.59 – $17.13	$	13.62
2004	1,762,000	$25.84 – $30.93	$	26.06
2005	1,430,000	$38.55 – $39.80	$	38.57


	2004		2005
Federal statutory rate	35	%	35	%
State income tax rate, net of federal benefit	3	%	3	%
Other	—		(1	)%

Effective income tax rate	38	%	37	%


	Expenditures (in millions)		Drillings/ Deepenings	Refracs/ Trifracs	Recompletions
Wattenberg	$	37.9	36	108	41
Mid Continent		31.8	39	—	9
San Juan		6.3	9	—	4
Central and Other		3.9	13	—	3

Total	$	79.9


	Less than One Year		1 – 3 Years		3 – 5 Years		After 5 Years		Total
Long term debt	$	—	$	288,000		—	$	—	$	288,000
Firm transportation agreement		582		1,164		1,164		8,049		10,959
Non-cancelable operating leases		1,529		3,094		881		—		5,504
Asset retirement obligation		—		3,660		1,566		26,527		31,753
Derivative obligations (a)		264,626		106,948		—		—		371,574

Total obligations	$	266,737	$	402,866	$	3,611	$	34,576	$	707,790


	March 31, 2005
	Borrowing Base		Outstanding		Available
Revolving Credit Facility	$	500,000	$	288,000	$	212,000


	Average Prices
	Oil		Natural Gas		Equivalent Mcf
	(Per Bbl)		(Per Mcf)		(Per Mcfe)
Annual
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
2004		40.28		5.42		5.86

Quarterly

2004
First	$	34.01	$	4.98	$	5.22
Second		37.15		5.16		5.51
Third		42.62		5.40		5.97
Fourth		46.88		6.09		6.67

2005
First	$	48.16	$	5.74	$	6.51


	Oil (Bbls per day)				Gas (Mcfs per day)				Total (Mcfe per day)
	2004	2005	Change		2004	2005	Change		2004	2005	Change
Wattenberg	8,736	9,082	346		143,190	140,774	(2,416	)	195,606	195,265	(341	)
Mid Continent	5,060	5,315	255		49,936	66,879	16,943		80,297	98,767	18,470
San Juan	24	23	(1	)	9,133	10,510	1,377		9,275	10,648	1,373
Central and Other	3,924	4,107	183		2,512	1,236	(1,276	)	26,059	25,880	(179	)

Total	17,744	18,527	783		204,771	219,399	14,628		311,237	330,560	19,323


	Oil $/Bbls									Gas $/Mcf								Total $/Mcfe
	2004			2005			Change			2004			2005			Change		2004			2005			Change
Wattenberg	$	34.97		$	49.04		$	14.07		$	4.82		$	5.57		$	0.75	$	5.09		$	6.30		$	1.21
Mid Continent		32.72			47.00			14.28			5.36			6.05			0.69		5.39			6.62			1.23
San Juan		29.66			45.50			15.84			5.46			6.15			0.69		5.45			6.17			0.72
Central and Other		33.57			47.72			14.15			4.86			4.49			0.37		5.52			7.79			2.27

Subtotal		34.01			48.16			14.15			4.98			5.74			0.76		5.22			6.51			1.29
Hedging		(7.39	)		(18.37	)		(10.98	)		(0.36	)		(0.24	)		0.12		(0.66	)		(1.19	)		(0.53	)

Total	$	26.62		$	29.79		$	3.17		$	4.62		$	5.50		$	0.88	$	4.56		$	5.32		$	0.76



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 May 3, 2005, 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 May 3, 2005, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*