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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



FORM 10-K



(Mark one)



|x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ------------------------------------------------------------------------------------



For the fiscal year ended December 31, 2004



OR



| ̈ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ----------------------------------------------------------------------------------------



For the transaction period from to



Commission file number 1-14344



PATINA OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)



|                                                              |  |                                 
|------------------------------------------------------------- |  | --------------------------------
|Delaware                                                      |  | 75-2629477                      
|(State or other jurisdiction ofincorporation or organization) |  | (IRS EmployerIdentification No.)
|                                                              | 
|1625 Broadway, Suite 2000                                     |  |                                 
|Denver, Colorado                                              |  | 80202                           
|(Address of principal executive offices)                      |  | (Zip Code)                      



Registrants
telephone number, including area code (303) 389-3600



Securities registered pursuant to Section 12(b) of the Act



|                             |  |                                          
|---------------------------- |  | -----------------------------------------
|Title of each class          |  | Name of each exchange on which registered
|Common Stock, $.01 par value |  | New York Stock Exchange                  



Securities
registered pursuant to Section 12(g) of the Act:

None

(Title of Class)



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.

x Yes ̈No



Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x



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

x Yes ̈No



The aggregate market value of the 61,336,000 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the Common Stock on June 30, 2004 of $29.87 per share as reported on the New York Stock
Exchange, was $1,832,112,000. Shares of Common Stock held by each officer and director and by each person who owns 5% or more of the outstanding Common Stock have been excluded in that such persons may be deemed affiliates. This determination of
affiliate status is not necessarily a conclusive determination for other purposes.



As of February 24, 2005, the registrant had 71,198,272 shares of Common Stock outstanding (excludes 2,095,832 common shares held as treasury stock).



DOCUMENT INCORPORATED BY REFERENCE



Part III of the report is incorporated by reference to the Registrants definitive Proxy Statement relating to its
Annual Meeting of Stockholders, or an amendment to this Form 10-K, which will be filed with the Commission no later than April 30, 2005.



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PATINA OIL & GAS
CORPORATION

Annual Report on Form 10-K

December 31, 2004



PART I



|ITEM 1. | BUSINESS
|------- | --------



General



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 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s Common Stock is traded on the New York Stock Exchange
under the symbol POG.



On December 15, 2004, Patina entered
into a merger agreement with Noble Energy, Inc. (Noble Energy). In the transaction, Patina will merge 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 transaction is expected to close in the second quarter of 2005. See Pending Merger with Noble Energy, Inc. below. Statements in this annual 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.



At December 31, 2004, the
Company had 1.6 trillion cubic feet equivalent (Tcfe) of proved reserves having a pretax present value based upon a discount rate of 10% (PV10%, a non-GAAP measure, see reconciliation in Note 12 to the accompanying
consolidated financial statements) of $3.1 billion based on unescalated prices and costs. This valuation reflected average wellhead prices of $5.61 per Mcf and $41.48 per barrel at year-end. During 2004, proved reserves increased 7%. The growth was
largely the result of ongoing development and performance revisions which increased reserves by 212 Bcfe and through acquisitions of 22 Bcfe, respectively. In addition, the change in oil and gas prices and costs increased reserves 10 Bcfe. The
reserve increases were offset by 118 Bcfe of production and 23 Bcfe of reserves sold. The Company replaced over 187% of production in 2004. At year-end, approximately 67% of reserves by volume were natural gas and over 82% of PV10% value was
attributed to proved developed wells.



The Company operates
over 75% of the 7,800 producing wells in which it holds a working interest. The high proportion of operated properties allows the Company to exercise more control over operating costs, capital expenditures and the timing of development and
exploitation activities in its fields. At December 31, 2004, the Company had over 5,300 proven development projects in inventory, including 1,600 drilling or deepening locations, 1,100 recompletions, 2,100 restimulation (refrac or
trifrac) projects and over 500 production enhancement projects.



The Companys properties have relatively long reserve lives and predictable production profiles. In general, these properties have extensive production histories and production enhancement opportunities. During
2004, average daily production totaled 322.2 MMcfe, comprised of 18,049 barrels of oil and 213.9 MMcf of gas. Approximately 61% of equivalent production was attributed to Wattenberg. Based on year-end reserves and fourth quarter production, the
Company had a reserve life index of 13.2 years.



2



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Revenues and net income for 2004 totaled $561.0 million and $151.0 million, respectively. Cash provided
from operations in 2004 totaled $396.6 million. This cash flow, augmented with $13.5 million realized from the issuance of Common Stock, funded the repayment of $119.0 million of bank borrowings and $258.6 million of capital expenditures in 2004,
net of $29.0 million of property sales. These expenditures were largely comprised of $29.3 million spent on acquisitions, $253.9 million on further development of properties and $4.5 million spent on furniture, fixtures, and equipment. Development
expenditures included $112.2 million expended in Wattenberg, $104.5 million in the Mid Continent, $16.0 million in the San Juan Basin, and $21.2 million on the Central and Other properties. The benefits of these projects, continued success in
production enhancement and prior year acquisitions fueled an 18% increase in production during the year. The Company anticipates spending approximately $300.0 million on the further development of its properties in 2005.



Pending Merger with Noble Energy, Inc.



On December 15, 2004, the boards of directors of Patina and Noble Energy
approved Noble Energys merger with Patina. 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 27.3 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 stockholder 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 stockholder 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 merger is expected to be completed in the second quarter of 2005.



For more information regarding the proposed merger between Noble Energy and Patina, please refer to the joint proxy statement/prospectus of Noble Energy
and Patina that is included in the registration statement on Form S-4 filed by Noble Energy with the SEC on January 25, 2005. The joint proxy statement/prospectus contains important information about the proposed merger. These materials are not yet
final and will be amended. Investors and security holders of Noble Energy and Patina are urged to read the joint proxy statement/prospectus filed, and any other relevant materials filed by Noble Energy or Patina because they contain, or will
contain, important information about Noble Energy, Patina and the proposed merger. The preliminary materials filed on January 25, 2005, the definitive versions of these materials and other relevant materials (when they become available) and any
other documents filed by Noble Energy or Patina with the SEC, may be obtained for free at the SECs website at http://www.sec.gov. In addition, the documents filed with the SEC by Noble Energy may be obtained free of charge from Noble
Energys website at http://www.nobleenergyinc.com. The documents filed with the SEC by Patina may be obtained free of charge from Patinas website at http://www.patinaoil.com.



History



Patina was incorporated in Delaware in 1996 to hold the Wattenberg assets of Snyder Oil Corporation (SOCO) and to facilitate the acquisition
of a competitor in Wattenberg. SOCO retained 43.8 million shares of the Companys Common Stock and the acquired companys shareholders received 18.7 million shares of Common Stock, $40.0 million of 7.125% convertible preferred stock and
9.4 million warrants. In 1997, a series of transactions eliminated SOCOs ownership in the Company. The 7.125% preferred stock was retired in January 2000 and the warrants were converted into Common Stock in May 2001.



3



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Originally, the Companys oil and gas properties were located exclusively in Wattenberg. Beginning
in 2000, the Company began to diversify its asset base. Through Elysium Energy, L.L.C. (Elysium), a 50% owned joint venture, certain oil and gas properties located in Louisiana, Texas, Illinois, Kansas and California were acquired out of
a bankruptcy. In 2001, the Company assembled acreage positions in central Wyoming and northwest Colorado, acquired a 50% interest in an early stage coalbed methane project in Utah and purchased a small producing property with enhancement potential
in Texas. In late 2002, two acquisitions established a sizeable base of operations in the Mid Continent region, primarily in southern Oklahoma and the Texas Panhandle. In 2003, the remaining 50% interest in Elysium was acquired and additional Mid
Continent properties were added through the acquisition of Le Norman Partners. In the fourth quarter of 2003, the Company acquired the assets of Cordillera Energy Partners, L.L.C. which included properties primarily in the Mid Continent region and
the San Juan Basin. With this acquisition, the Company currently has three core areas of operations including Wattenberg, the Mid Continent and the San Juan Basin.



Elysiums properties were originally located in central Kansas, the Illinois Basin and the San Joaquin Basin of
California. Approximately 90% of Elysiums production is oil. In early 2001, Elysium sold the great majority of its interest in the Lake Washington Field of Louisiana for $30.5 million ($15.25 million net to the Company). In late 2001, Patina
assumed direct management of Elysium and its properties. In January 2003, the Company acquired the remaining 50% of the joint venture for $23.1 million, simultaneously divesting the remainder of Lake Washington and all California (primarily San
Joaquin Basin) assets.



During 2001, the Company accumulated
acreage positions in three Rocky Mountain basins and acquired a small producing field in West Texas. The intent was to aggregate prospects with significant reserve potential and long-term development prospects. As the grassroots projects comprise an
insignificant portion of the Companys current production, reserves, and expected future growth, they have become non-strategic to the Company. During late 2003, the Company exchanged its interests in the Wyoming prospect for certain oil and
gas properties in Wattenberg and sold its interests in the coalbed methane project in Utah. In early 2004, the Company sold its interests in the West Texas project.



In November 2002, Patina acquired Le Norman Energy Corporation (Le Norman) for $62.0 million. The purchase was
funded with bank borrowings and the issuance of 513,200 shares of Common Stock. The Le Norman properties primarily produce oil from shallow formations and are located principally in the Anadarko and Ardmore-Marietta Basins of Oklahoma. At the date
of the acquisition, Le Norman held a 30% reversionary interest in an affiliated entity, Le Norman Partners (LNP). In December 2002, Patina acquired Bravo Natural Resources, Inc. (Bravo) for $119.0 million. The purchase was
funded entirely with bank borrowings. Bravos properties are primarily located in Hemphill County, Texas and Custer and Caddo Counties of western Oklahoma, within the Anadarko Basin. The Bravo properties primarily produce gas from intermediate
depths. In March 2003, the Company acquired the remaining 70% interest in LNP for $39.7 million funded with bank borrowings. LNPs properties are located in Stephens, Garvin, and Carter Counties of southern Oklahoma and primarily produce oil.
In October 2003, the Company acquired the assets of Cordillera Energy Partners, LLC (Cordillera) for $243.0 million, comprised of $239.0 million funded with borrowings under the Companys bank facility and the issuance of five year
warrants to purchase 1,000,000 shares of Patina 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 produce primarily gas. In combination, the Le
Norman, Bravo, LNP, and certain Cordillera properties established a significant base of operations in the Mid Continent region for the Company.



Over the last five years, the Company has realized consistent growth in nearly every aspect of its business. Revenues increased from $150.3 million in
2000 to $561.0 million in 2004. Net income rose from $42.4 million to $151.0 million during the same period. The growth in revenue and net income was primarily the result of increasing oil and gas production due to acquisitions, increased realized
prices and the execution of high return capital projects, while maintaining low production costs and an efficient operating structure. Production grew from 119.0 MMcfe per day in 2000 to 322.2 MMcfe per day in 2004. Additionally, proven reserves
jumped from 777.8 Bcfe at year-end 2000 to 1.6 Tcfe at December 31, 2004. The reserve growth was largely generated through further development and exploitation in the Wattenberg combined with additions from prior year acquisitions and improved
exploitation.



4



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Business Strategy



From inception, the Company has focused on consolidating ownership of its properties and developing increasingly efficient operations. The Companys
sizable asset base and cash flow, along with its low production costs and efficient operations, provide it a competitive advantage in Wattenberg and in certain analogous basins. These advantages, combined with managements expertise, position
the Company to increase its reserves, production and cash flow in a cost-efficient manner primarily through: (i) further Wattenberg development; (ii) accelerated development of the recently acquired Mid Continent and San Juan Basin properties; (iii)
selective pursuit of further consolidation and acquisition opportunities; and (iv) generation and exploitation of exploration and development projects with a focus on projects near currently owned productive properties. The size and timing of any
future acquisitions will depend on market conditions. The Companys financial position affords it substantial flexibility in executing this strategy. If market conditions appear favorable, the Company routinely hedges future prices on 50% to
75% of its anticipated oil and gas production on a rolling 12 to 24 month basis.



Development, Acquisition and Exploration



During 2004, the Company spent $253.9 million on the further development of properties and $29.3 million on acquisitions. Development expenditures included $112.2 million in Wattenberg for the drilling or deepening of 47 J-Sand wells, 334
Codell refracs, 35 Niobrara refracs, 32 Codell trifracs, 56 recompletions and the drilling of 67 Codell wells, $104.5 million in the Mid Continent for the drilling or deepening of 195 wells, three refracs and 25 recompletions, $16.0 million in the
San Juan Basin, and $21.2 million on the Central and Other properties. The benefits of these projects, the acquisitions, and the continued success in production enhancement contributed to a production increase of 18% over the prior year. The Company
anticipates spending approximately $300.0 million on the further development of its properties in 2005.



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Production, Revenue and Price History



The following table sets forth information regarding oil and gas production, revenues and operating expenses attributable to
such production, average sales prices and other related data for the last five years. The information reflects the acquisitions of 50% of Elysium in November 2000, Le Norman in November 2002, Bravo in December 2002, the remaining 50% of Elysium in
January 2003, Le Norman Partners in March 2003, and Cordillera Energy Partners in October 2003.



|                                         |  |                                                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|---------------------------------------- |  | -------------------------------------------------------------- | ------- | ---- | - | ------- |  | ---- | ------- | ---- | - | ------- |  | - | -------
|                                         |  | Year Ended December 31,                                       
|                                         |  | 2000                                                           |         | 2001 |   | 2002    |  | 2003 |         | 2004
|                                         |  | (Dollars in thousands, except prices and per Mcfe information)
|Production                               |  |                                                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|Oil (MBbl)                               |  |                                                                | 1,685   |      |   | 2,661   |  |      | 3,272   |      |   | 5,737   |  |   | 6,606  
|Gas (MMcf)                               |  |                                                                | 33,463  |      |   | 41,002  |  |      | 49,777  |      |   | 65,570  |  |   | 78,290 
|MMcfe(a)                                 |  |                                                                | 43,572  |      |   | 56,969  |  |      | 69,411  |      |   | 99,996  |  |   | 117,925
|Revenues                                 |  |                                                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|Oil                                      |  | $                                                              | 38,741  |      | $ | 68,447  |  | $    | 80,233  |      | $ | 148,028 |  | $ | 178,095
|Gas(c)                                   |  |                                                                | 109,924 |      |   | 142,824 |  |      | 135,197 |      |   | 250,696 |  |   | 366,720
|                                         |  |                                                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|Subtotal                                 |  |                                                                | 148,665 |      |   | 211,271 |  |      | 215,430 |      |   | 398,724 |  |   | 544,815
|Other                                    |  |                                                                | 1,677   |      |   | 2,902   |  |      | 6,977   |      |   | 7,993   |  |   | 16,186 
|                                         |  |                                                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|Total                                    |  |                                                                | 150,342 |      |   | 214,173 |  |      | 222,407 |      |   | 406,717 |  |   | 561,001
|                                         |  |                                                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|Expenses                                 |  |                                                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|Lease operating expenses                 |  |                                                                | 13,426  |      |   | 25,356  |  |      | 27,986  |      |   | 54,082  |  |   | 71,596 
|Production taxes(d)                      |  |                                                                | 10,628  |      |   | 13,462  |  |      | 11,751  |      |   | 28,726  |  |   | 46,034 
|General and administrative               |  |                                                                | 7,165   |      |   | 10,994  |  |      | 12,714  |      |   | 19,034  |  |   | 26,390 
|Depletion, depreciation and amortization |  |                                                                | 40,600  |      |   | 49,916  |  |      | 66,162  |      |   | 98,119  |  |   | 126,849
|                                         |  |                                                                |         |      |  
|Average sales price(b)                   |  |                                                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|Oil (Bbl)                                |  | $                                                              | 23.00   |      | $ | 25.72   |  | $    | 24.52   |      | $ | 25.80   |  | $ | 26.96  
|Gas (Mcf)(c)                             |  |                                                                | 3.28    |      |   | 3.48    |  |      | 2.72    |      |   | 3.82    |  |   | 4.68   
|Mcfe(a)                                  |  |                                                                | 3.41    |      |   | 3.71    |  |      | 3.10    |      |   | 3.99    |  |   | 4.62   
|                                         |  |                                                                |         |      |  
|Per Mcfe Information                     |  |                                                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|Lease operating expense                  |  | $                                                              | 0.31    |      | $ | 0.45    |  | $    | 0.40    |      | $ | 0.54    |  | $ | 0.61   
|Production tax expense(d)                |  |                                                                | 0.24    |      |   | 0.24    |  |      | 0.17    |      |   | 0.29    |  |   | 0.39   
|General and administrative               |  |                                                                | 0.16    |      |   | 0.19    |  |      | 0.18    |      |   | 0.19    |  |   | 0.22   
|Depletion, depreciation and amortization |  |                                                                | 0.93    |      |   | 0.88    |  |      | 0.95    |      |   | 0.98    |  |   | 1.08   

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|(a) | Oil production is converted to natural gas equivalents (Mcfe) at the rate of one barrel to six Mcf.
|--- | ---------------------------------------------------------------------------------------------------



|(b) | The average sales prices include the effects of hedging. See Managements Discussion and Analysis of Financial Condition and Results of Operations, where the
effects of oil and gas hedging are more fully quantified.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(c) | Sales of natural gas liquids are included in gas revenues.
|--- | ----------------------------------------------------------



|(d) | Production taxes are generally calculated as a percentage of pre-hedged oil and gas revenues. As oil and gas revenues increase (through increases in production
and/or oil and gas prices) production taxes will also increase.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Gathering, Processing and Marketing



The Companys oil and gas production is principally sold to end users, marketers, refiners and other purchasers having
access to pipeline facilities or the ability to truck oil to local refineries. The marketing of oil and gas can be affected by a number of factors that are beyond the Companys control and which cannot be accurately predicted.



Natural Gas. The natural gas produced in Wattenberg is high in heating
content (BTUs) and must be processed to extract natural gas liquids (NGL). Residue gas is sold to utilities, independent marketers and end users through intrastate and interstate pipelines. The Company utilizes two separate
arrangements to gather, process and market its gas production. Approximately 35% of production is sold to Duke Energy Field Services, LP (Duke Energy) at the wellhead under percentage of proceeds contracts. Pursuant to this type of
contract, the Company receives a fixed percentage of the proceeds from Duke Energys sale of residue gas and NGLs. Substantially all of the Companys remaining natural gas production is dedicated for gathering to Duke Energy or Kerr
McGee Gathering, LLC, (KMG) and is processed at plants owned by Duke Energy or BP Amoco Production Company (BP Amoco). Under this arrangement, the Company retains the right to market its share of residue gas at the tailgate
of the plant and sells it under spot and long-term market arrangements generally based on the CIG index along the front range of Colorado or transports it to Midwestern markets under transportation agreements. NGLs are sold by the processor
and the Company receives payment net of applicable processing fees. A portion of the natural gas processed by BP Amoco at the Wattenberg Processing Plant is under a favorable keepwhole contract that not only provides payment for a
percentage of the NGLs stripped from the natural gas, but also redelivers at the tailgate the same amount of MMBtus as was delivered to the plant. This agreement extends through December 2012.



Natural gas production from the Mid Continent and San Juan Basin properties
is gathered and transported to interstate pipelines, where it is sold to end users and marketers. Pricing for Mid Continent production is generally based on the ANR Pipeline Oklahoma index plus a premium, while pricing for San Juan Basin production
is generally based on the Inside FERC San Juan El Paso monthly index.



Oil. Oil production is principally sold to refiners, marketers and other purchasers that truck it to local refineries or pipelines. The price is generally based on a calendar month New York Mercantile Exchange (NYMEX)
price with adjustments for quality and location.



See Note (10)
to the accompanying consolidated financial statements for information regarding the Companys major customers.



Hedging Activities



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 December 31, 2004, the net unrealized pretax gains on these contracts totaled $952,000 ($590,000
gain net of $362,000 of deferred taxes) based on LIBOR futures prices at December 31, 2004.



The Company regularly enters into hedging agreements to reduce the impact on its operations of fluctuations in oil and gas prices. All such contracts are entered into solely to hedge prices and limit volatility. The
Companys current policy is to hedge between 50% and 75% of its production, when futures prices justify, on a rolling 12 to 24 month basis. At December 31, 2004, hedges were in place covering 68.5 Bcf at prices averaging $4.54 per MMBtu and 8.6
million barrels of oil averaging $25.57 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 $211.4 million ($131.1 million loss net
of $80.3 million of deferred taxes) at December 31, 2004. 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 $7.3 million, a current liability of
$151.5 million, and a non-current liability of $66.2 million based on contract expiration. Both the gas contracts and oil 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



7



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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. A net realized pretax gain relating to these derivatives totaled $20.4 million in 2002, with net realized pretax losses of $50.4 million and $145.9
million in 2003 and 2004, respectively. Effective January 1, 2001, the unrealized gains (losses) on open hedging positions were recorded at an estimate of fair value which the Company based on a comparison of the contract price and a reference
price, generally NYMEX, CIG, ANR, PEPL or EPSJ on the Companys balance sheet in Accumulated other comprehensive income (loss), a component of Stockholders Equity.



Competition



The oil and gas industry is highly competitive. The Company encounters competition in all of its operations, including the acquisition of exploration and
development prospects and producing properties. Patina competes for acquisitions of oil and gas properties with numerous entities, including major oil companies, other independents, and individual producers and operators. Many competitors have
financial and other resources substantially greater than those of the Company. The ability of the Company to increase reserves in the future will be dependent on its ability to select and successfully acquire suitable producing properties and
prospects for future development and exploration.



Title to Properties



Title to the Companys oil and gas properties is
subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the industry, liens incident to operating agreements and for current property taxes not yet due and other comparatively minor
encumbrances. As is customary in the oil and gas industry, only a perfunctory investigation as to ownership is conducted at the time undeveloped properties are acquired. Prior to the commencement of drilling operations, a detailed title examination
is typically conducted and curative work is performed with respect to identified title defects.



Government Regulation



Regulation of Drilling and Production. The Companys operations are affected by political developments and by federal, state and local laws and regulations. Legislation and administrative regulations relating to the oil and gas
industry are periodically changed for a variety of political, economic and other reasons. Numerous federal, state and local departments and agencies issue rules and regulations binding on the oil and gas industry, some of which carry substantial
penalties and sanctions for failure to comply. The regulatory burden on the industry increases the cost of doing business, decreases flexibility in the timing of operations and may adversely affect the economics of capital projects.



In the past, the federal government has regulated the prices at which oil and
gas could be sold. Prices of oil and gas sold by the Company are not currently regulated, but there is no assurance that such regulatory treatment will continue indefinitely into the future. Congress, or in the case of certain sales of natural gas
by pipeline affiliates over which it retains jurisdiction, the Federal Energy Regulatory Commission (FERC) could re-enact price controls or other regulations in the future.



In recent years, FERC has taken significant steps to increase competition in the sale, purchase, storage and transportation
of natural gas. FERCs regulatory programs allow more accurate and timely price signals from the consumer to the producer and, on the whole, have helped natural gas become more responsive to changing market conditions. To date, the Company
believes it has not experienced any material adverse effect as the result of these initiatives. Nonetheless, increased competition in natural gas markets can and does add to price volatility and inter-fuel competition, which increases the pressure
on the Company to manage its exposure to changing conditions and position itself to take advantage of changing markets. Additional proposals are pending before Congress and FERC that might affect the oil and gas industry. The oil and gas industry
has historically been heavily regulated at the federal level; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue.



8



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State statutes govern exploration and production operations, conservation of oil and gas resources,
protection of the correlative rights of oil and gas owners, environmental standards and the rights of surface owners. State Commissions implement their authority by establishing rules and regulations requiring permits for drilling, reclamation of
production sites, plugging bonds, reports and other matters. Colorado, where the Companys producing properties are primarily located, amended its statute concerning oil and natural gas development in 1994 to provide the Colorado Oil & Gas
Conservation Commission (the COGCC) with enhanced authority to regulate oil and gas activities to protect public health, safety and welfare, including the environment. The COGCC has implemented several rules pursuant to these statutory
changes concerning groundwater protection, soil conservation and site reclamation, setbacks in urban areas and other safety concerns, and financial assurance for industry obligations in these areas. To date, these rule changes have not adversely
affected the operations of the Company, as the COGCC is required to enact cost-effective and technically feasible regulations, and the Company has been an active participant in their development. However, there can be no assurance that, in the
aggregate, these and other regulatory developments will not increase the cost of operations in the future.



In Colorado, a number of city and county governments have enacted oil and gas regulations. These ordinances increase the involvement of local governments
in the permitting of oil and gas operations, and require additional restrictions or conditions on the conduct of operations so as to reduce their impact on the surrounding community. Accordingly, these local ordinances have the potential to delay
and increase the cost of drilling, refracing and recompletion operations.



Environmental Matters



Environmental
Regulation. The Companys operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The Company currently owns or leases numerous
properties that have been used for many years for oil and gas production. Although the Company believes that it and previous owners have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other
wastes may have been disposed of or released on or under the properties owned or leased by the Company. In connection with its most significant acquisitions, the Company has performed environmental assessments and found no material environmental
noncompliance or clean-up liabilities requiring action in the future. Such environmental assessments have not, however, been performed on all of the Companys properties. The Company may therefore become liable for the environmental
non-compliance of predecessor owners of the Companys properties, including assessments and clean-up costs.



The Companys operations are subject to stringent federal, state and local laws governing the discharge of materials into the environment or
otherwise relating to environmental protection. Numerous governmental departments such as the Environmental Protection Agency (EPA) issue regulations to implement and enforce such laws, which are often difficult and costly to comply with
and which carry substantial civil and criminal penalties and sanctions for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various
substances that can be released into the environment in connection with drilling, production and transporting through pipelines, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, frontier and other protected
areas, require some form of remedial action to prevent pollution from former operations such as plugging abandoned wells, and impose substantial liabilities for pollution resulting from operations. In addition, these laws, rules and regulations may
restrict the rate of production. The regulatory burden on the oil and gas industry increases the cost of doing business and affects profitability. Changes in environmental laws and regulations occur frequently, and changes that result in more
stringent and costly waste handling, disposal or clean-up requirements could adversely affect the Companys operations and financial position, as well as the industry in general. Management believes the Company is in substantial compliance with
current applicable environmental laws and regulations. The Company has not experienced any material adverse effect from compliance with environmental requirements, however, there is no assurance that this will continue. The Company did not have any
material expenditures in connection with environmental matters in 2004, nor does it anticipate that such expenditures will be material in 2005.



The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), known as the Superfund law, and analogous state
laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance



9



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into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or
arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into
the environment, for damages to natural resources and for the costs of certain health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damages allegedly caused by the
release of hazardous substances or other pollutants into the environment. Furthermore, although petroleum, including crude oil and natural gas, is exempt from CERCLA, at least two courts have ruled that certain wastes associated with the production
of crude oil may be classified as hazardous substances under CERCLA and that such wastes may become subject to liability and regulation under CERCLA. State initiatives to further regulate the disposal of oil and gas wastes are pending in
certain states and these initiatives could have a significant impact on the Company.



The Federal Water Pollution Control Act (FWPCA) imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into navigable waters. Permits must be
obtained to discharge produced waters and other oil and gas wastes into state and federal waters. The FWPCA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous
substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. State water discharge regulations and the federal National Pollutant Discharge Elimination System permits
applicable to the oil and gas industry generally prohibit the discharge of produced water, sand and some other substances into U.S. waters. The cost to comply with discharge standards mandated under federal and state law have not had a material
adverse impact on the Companys financial condition and results of operations. Some oil and gas exploration and production facilities may be required to obtain permits for their stormwater discharges. Costs may be incurred in connection with
treatment of wastewater or developing stormwater pollution prevention plans.



The Oil Pollution Act of 1990 (OPA) imposes regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from spills in waters of the United
States. A responsible party includes the owner or operator of an onshore facility, vessel or pipeline, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns strict, joint and several liability to
each responsible party for oil removal costs and a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was
caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Even if applicable, the liability
limits for onshore facilities require the responsible party to pay all removal costs, plus up to $350.0 million in other damages. Few defenses exist to the liability imposed by OPA. Failure to comply with ongoing requirements or inadequate
cooperation during a spill event may subject a responsible party to administrative civil or criminal enforcement actions.



The Resource Conservation and Recovery Act (RCRA), and analogous state laws govern the handling and disposal of hazardous and solid wastes.
Wastes that are classified as hazardous under RCRA are subject to stringent handling, recordkeeping, disposal and reporting requirements. RCRA specifically excludes from the definition of hazardous waste drilling fluids, produced waters, and
other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy. However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, many ordinary industrial
wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, the Company does not expect to experience more
burdensome costs than similarly situated companies.



The
Company operates its own exploration and production waste management facilities in Colorado, which enable it to treat, bioremediate and otherwise dispose of tank sludges and contaminated soil generated from the Companys Colorado operations.
There can be no assurance that these facilities, or other commercial disposal facilities utilized from time to time, will not give rise to environmental liability in the future. To date, expenditures for the Companys environmental control
facilities and for remediation of production sites have not been significant. The Company believes, however, that the trend toward stricter standards in environmental legislation and regulations will continue and could have a material adverse impact
on operating costs and the oil and gas industry in general.



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Forward-Looking Statements



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 annual 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. When considering any forward-looking statements contained herein, you should keep in mind the risk factors and other cautionary statements in this Form 10-K. 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-K.



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-K 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.



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Risk Factors



In addition to the factors described elsewhere in this report, the following are some of the important factors that could cause the Companys actual
results to differ materially from those projected in any forward-looking statements. Also please refer to the joint proxy statement/prospectus of Patina and Noble Energy that is included in the registration statement on Form S-4 filed by Noble
Energy with the SEC on January 25, 2005 for a description of additional risks applicable to the combined company following the consummation of Patinas proposed merger with Noble Energy.



Demand for Our Oil and Gas from Our Customer Base



We sell our oil and gas production to end-users, marketers and refiners and
other similarly situated purchasers that have access to natural gas pipeline facilities near our properties or the ability to truck oil to local refineries or pipeline delivery points. The demand for oil and natural gas production and our ability to
market it to our customers may be affected by a number of factors that are beyond our control and that we cannot accurately predict at this time. These factors include:



| |  |  | The performance of the U.S. and world economies;
| | - |  | ------------------------------------------------



| |  |  | Retail customers demand for oil and natural gas;
| | - |  | -------------------------------------------------



| |  |  | Weather conditions;
| | - |  | -------------------



| |  |  | The competitive position of alternative energy sources;
| | - |  | -------------------------------------------------------



| |  |  | The price of our oil and gas production as compared to that for similar product grades from other producing basins;
| | - |  | -------------------------------------------------------------------------------------------------------------------



| |  |  | The availability of pipeline and other transportation facilities that may make oil and gas production from other producing areas competitive for our customers to use; and
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Our ability to maintain and increase our current level of production over the long term.
| | - |  | ----------------------------------------------------------------------------------------



Competition for the Acquisition of New Properties and Successful Integration



As part of the Companys growth strategy, the Company may make
additional acquisitions of businesses and properties. However, suitable acquisition candidates may not be available on terms and conditions it finds acceptable, and acquisitions pose substantial risks to the Companys business, financial
condition and results of operations. The oil and gas industry is very competitive. Other exploration and production companies compete with us for the acquisition of new properties. Among them are some of the largest oil companies in the United
States and other substantial independent oil and gas companies. Many of these companies have greater financial and other resources than we do. Our ability to increase our reserves in the future will depend upon our ability to select and acquire
suitable oil and gas properties in this competitive environment. Risks involved with this strategy include:



| |  |  | The acquired businesses or properties may not produce revenues, earnings or cash flow at anticipated levels;
| | - |  | ------------------------------------------------------------------------------------------------------------



| |  |  | The Company may assume liabilities that were not disclosed or that exceed the Companys estimates;
| | - |  | --------------------------------------------------------------------------------------------------



| |  |  | The Company may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in
substantial costs and delays or other operational, technical or financial problems;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Acquisitions could disrupt the Companys ongoing business, distract management, divert resources and make it difficult to maintain the Companys current business
standards, controls and procedures;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The Company may finance future acquisitions by issuing Common Stock for some or all of the purchase price, which could dilute the ownership interests of the Companys
stockholders; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The Company may incur additional debt related to future acquisitions.
| | - |  | ---------------------------------------------------------------------



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Fluctuations in Profitability of the Oil and Gas Industry



The oil and gas industry is highly cyclical and historically has experienced
severe downturns characterized by oversupply and weak demand. Many factors affect our industry, including general economic conditions, consumer preferences, personal discretionary spending levels, interest rates and the availability of credit and
capital to pursue new production opportunities. We cannot guarantee that our industry will not experience sustained periods of decline in the future. Any such decline could have a material adverse affect on our business.



Operating Risks of Oil and Gas Operations



The oil and gas business involves certain operating hazards such as well
blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pollution, releases of toxic gas and other environmental hazards and risks. As customary with industry practice, we
maintain insurance against some, but not all, of these hazards and risks. The occurrence of such an event or events not fully covered by insurance could have a material adverse affect on our business. In addition, our operations are dependent upon
the availability of certain resources, including drilling rigs, water, chemicals, tubulars and other materials necessary to support our capital development plans and maintenance requirements. The lack of availability of one or more of these
resources at an acceptable price could have a material adverse affect on our business.



The Effect of Regulation



Our business is
heavily regulated by federal, state and local lawmaking bodies and regulatory agencies. This regulation increases our cost of doing business, decreases our flexibility to respond to changes in the market and lengthens the time it may take for us to
gain approval of and complete capital projects. We may be subject to substantial penalties if we fail to comply with any law, statute or regulation. In particular, the Colorado Oil & Gas Conservation Commission has promulgated regulations to
protect ground water, conserve soil, provide for site reclamation, ensure setbacks in urban areas, generally promote safety concerns and mandate financial assurance for companies in the industry. To date, these rules and regulations have not
adversely affected us. We continue to take an active role in the development of rules and regulations that directly impact our operations. However, we cannot assure you that regulatory changes enacted by the Colorado Oil & Gas Conservation
Commission or other regulatory agencies that have jurisdiction over us will not increase our operating costs or otherwise negatively impact the results of our operations.



The Potential for Environmental Liabilities



We are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental
protection. We currently own or lease numerous properties that have been used for many years for oil and natural gas production. Although we believe that we and previous owners used operating and disposal practices that were standard in the industry
at the time, hydrocarbons and other waste products may have been disposed of or released on or under the properties owned or leased by us. In connection with our most significant acquisitions, we have conducted environmental assessments and have
found no instances of material environmental non-compliance or any material clean-up liabilities requiring action in the near future. However, we have not performed such environmental assessments on all of our properties. As to all of our
properties, we cannot assure you that past disposal practices, including those that were state-of-the-art at the time employed, will not result in significant future environmental liabilities. In addition, we cannot assure you that in the future
regulatory agencies with jurisdiction over us will not enact additional environmental regulations that will negatively affect properties we currently own or acquire in the future.



We also operate exploration and production waste management facilities that enable us to treat, bioremediate and otherwise
dispose of tank sludge and contaminated soil generated from our operations. We cannot assure you that these facilities or other commercial disposal facilities operated by third parties that we have used from time to time will not in the future give
rise to environmental liabilities for which we will be responsible. The trend toward stricter standards in environmental regulation could have a significant adverse impact on our operating costs as well as our industry in general.



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Hedging of Oil and Natural Gas Prices



We enter into hedging arrangements covering a portion of our future production to limit volatility and increase the
predictability of cash flow. Hedging instruments are generally fixed price swaps but have at times included or may include collars, puts and options on futures. While hedging limits our exposure to adverse price movements, hedging limits the benefit
of price increases and is subject to a number of risks, including the risk the counterparty to the hedge may not perform. The Company may be required to provide margin deposits to its counterparties if the unrealized losses on its oil and gas hedges
exceed the credit thresholds established by its counterparties. Such deposits may reduce the Companys financial flexibility.



Estimates of Oil and Gas Reserves, Production Replacement



The information on proved oil and gas reserves included in this document are simply estimates. The accuracy of any reserve estimate is a function of the
quality of available data, engineering and geological interpretation and judgment, assumptions used regarding quantities of oil and gas in place, recovery rates and future prices for oil and gas. Actual prices, production, development expenditures,
operating expenses and quantities of recoverable oil and gas reserves will vary from those assumed in our estimates, and such variances may be significant. If the assumptions used to estimate reserves later prove incorrect, the actual quantity of
reserves and future net cash flow could be materially different from the estimates used herein. In addition, results of drilling, testing and production along with changes in oil and gas prices may result in substantial upward or downward revisions.



Without success in exploration, development or acquisitions,
our reserves, production and revenues from the sale of oil and gas will decline over time. Exploration, the continuing development of our properties and acquisitions all require significant expenditures as well as expertise. If cash flow from
operations proves insufficient for any reason, we may be unable to fund exploration, development and acquisitions at levels we deem advisable.



Key Members Of Management



The Companys success is highly dependent on its senior management personnel, of which only one is currently subject to an employment contract. The
loss of one or more of these individuals could have a material adverse effect on the Company.



Office and Operations Facilities



The Company leases its principal executive offices at 1625 Broadway, Denver, Colorado 80202. The lease covers approximately 57,000 square feet and expires in October 2008. The monthly rent is approximately $115,000.
The Company owns an 11,000 square foot production facility in Platteville, Colorado used to support its Wattenberg Field operations. Elysium maintains five field offices in the areas of its operations. The Company owns an 11,000 square foot field
office in Velma, Oklahoma, a 3,000 square foot field office in Weatherford, Oklahoma, and a 16,000 square foot field office in Canadian, Texas used to support its Mid Continent operations. The Company also owns a 2,600 square foot field office in
Farmington, New Mexico used to support its San Juan Basin operations.



Employees



On December 31, 2004, the Company
had 434 employees, including 286 that work in its field offices. None of these employees are represented by a labor union. The Company believes its relationships with its employees are satisfactory.



Available Information



Our internet address is www.patinaoil.com. We make available free of charge through our website our annual report on Form
10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material
with, or furnish it to, the Securities and Exchange Commission.



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|ITEM 2. | PROPERTIES
|------- | ----------



General



During 2004,
the Companys production averaged 322.2 MMcfe per day, of which 195.9 MMcfe per day or 61% was attributed to the Wattenberg Field of Colorados D-J Basin. Accordingly, the Companys proved reserves at December 31, 2004 were
concentrated primarily in Wattenberg. The Company also has proven reserves associated with its Elysium acquisition made in late 2000, and the Le Norman, Bravo, LNP, and Cordillera acquisitions made in 2002 and 2003 which comprise the Companys
Mid Continent assets. The following table sets forth summary information with respect to estimated proved reserves at December 31, 2004.



|                  |  |                     |           |   |     |   |            |        |                   |           |              |           |   |     |  
|----------------- |  | ------------------- | --------- | - | --- | - | ---------- | ------ | ----------------- | --------- | ------------ | --------- | - | --- | -
|                  |  | PV10% Value (a)     |           |   |     |   |            |        |                   |           |              |          
|                  |  | Amount(Inthousands) |           | % |     |   | Oil(MBbls) |        | Natural Gas(MMcf) |           | Total(MMcfe) |           | % |    
|Wattenberg        |  | $                   | 1,959,197 |   | 63  |   |            | 44,454 |                   | 676,415   |              | 943,137   |   | 58  |  
|Mid Continent     |  |                     | 901,788   |   | 29  |   |            | 29,021 |                   | 314,393   |              | 488,522   |   | 30  |  
|San Juan          |  |                     | 93,985    |   | 3   |   |            | 290    |                   | 94,041    |              | 95,780    |   | 6   |  
|Central and Other |  |                     | 174,602   |   | 5   |   |            | 14,520 |                   | 4,446     |              | 91,564    |   | 6   |  
|                  |  |                     |           |   |     |   |            |        |                   |           |              |           |   |     |  
|Total             |  | $                   | 3,129,572 |   | 100 | % |            | 88,285 |                   | 1,089,295 |              | 1,619,003 |   | 100 | %
|                  |  |                     |           |   |     |   |            |        |                   |           |              |           |   |     |  



|(a) | PV10% is a non-GAAP measure as it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net
cash flows. See reconciliation of PV10% to standardized measure more fully described in Note (12) Unaudited Supplemental Oil and Gas Reserve Information to the accompanying consolidated financial statements.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The following table sets forth summary information with respect to oil and
natural gas production for the year ended December 31, 2004.



|                  |  |            |  |                   |  |              |  |     |  
|----------------- |  | ---------- |  | ----------------- |  | ------------ |  | --- | -
|                  |  | Oil(MBbls) |  | Natural Gas(MMcf) |  | Total(MMcfe) |  | %   |  
|Wattenberg        |  | 3,167      |  | 52,683            |  | 71,685       |  | 61  |  
|Mid Continent     |  | 1,923      |  | 21,424            |  | 32,960       |  | 28  |  
|San Juan          |  | 20         |  | 3,494             |  | 3,614        |  | 3   |  
|Central and Other |  | 1,496      |  | 689               |  | 9,666        |  | 8   |  
|                  |  |            |  |                   |  |              |  |     |  
|Total             |  | 6,606      |  | 78,290            |  | 117,925      |  | 100 | %
|                  |  |            |  |                   |  |              |  |     |  



Wattenberg



The Companys reserves are primarily concentrated in the Wattenberg
Field, which is located in the D-J Basin of north central Colorado. Discovered in 1970, the field is located approximately 35 miles northeast of Denver and stretches over portions of Adams, Boulder, Broomfield and Weld counties. One of the most
attractive features of Wattenberg is the presence of multiple productive formations. In a section only 4,500 feet thick, there are up to eight potentially productive formations. Three of the formations, the Codell, Niobrara and J-Sand, are
considered blanket zones in the area of the Companys holdings, while others, such as the D-Sand, Dakota and the shallower Shannon, Sussex and Parkman, are more localized. While these zones may be present, any particular
propertys productivity is dependent on the reservoir properties peculiar to its location. Such productivity may be uneconomic.



Drilling in Wattenberg is considered low risk from the perspective of finding oil and gas reserves, with over 98% of the wells drilled encountering
sufficient quantities of reserves to be completed as economic producers. In May 1998, the COGCC adopted new spacing rules for the Wattenberg Field that greatly enhanced the Companys ability to more efficiently develop its properties. The rule
also eliminated costly and time-consuming procedures required for certain development activities. All formations in Wattenberg can now be drilled, produced and commingled from any or all of ten potential drilling locations on a 320 acre
parcel.



15



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In 2004, development expenditures in Wattenberg totaled $112.2 million. The Companys current
Wattenberg activities are primarily focused on the development of J-Sand reserves through drilling new wells or deepening within existing wellbores, refracing or trifracing existing Codell wells and refracing or recompleting the Niobrara formation
within existing Codell wells. A refrac consists of the restimulation of a producing formation within an existing wellbore to enhance production and add incremental reserves. These projects and continued success with the production enhancement
program allowed the Company to increase its production and to add proved reserves in 2004 in what is considered a mature field.



During 2004, the Company drilled or deepened 47 wells to the J-Sand formation in Wattenberg. The cost of drilling and completing a J-Sand well
approximates $400,000 while a completed deepening within an existing wellbore costs roughly $225,000. The reserves associated with a typical J-Sand well are more prolific than those of a Codell/Niobrara, with over 95% of such per well reserves
comprised of natural gas. Consequently, the economics of a J-Sand project are more dependent on gas prices. At December 31, 2004, the Company had over 275 proven J-Sand drilling locations or deepening projects in inventory. The Company plans to
drill or deepen approximately 45 wells to the J-Sand in 2005.



The Company performed 334 Codell refracs in Wattenberg during 2004. A typical Codell refrac costs approximately $145,000. At December 31, 2004, the Company had approximately 1,650 proven Codell refrac projects. The Company plans to perform
approximately 340 Codell refrac projects in 2005.



The Company
performed 32 Codell trifracs in Wattenberg during 2004. The trifrac program, which is effectively a refrac of a refrac, was initiated in 2003 with encouraging results. A typical Codell trifrac costs approximately $135,000. The Company is in the
early stages of evaluating the trifrac program and expects to perform approximately 80 trifracs in 2005. At December 31, 2004, the Company had approximately 400 proven Codell trifrac projects in inventory.



The Company performed 84 Niobrara refracs or recompletions in Wattenberg
during 2004. A typical Niobrara refrac/recomplete costs approximately $140,000. At December 31, 2004, the Company had approximately 685 proven Niobrara projects. The Company plans to perform approximately 210 Niobrara refrac/recomplete projects in
2005.



The Company also performed five Codell and two J-Sand
recompletions and drilled 67 Codell wells in the D-J Basin in 2004. The Company had an additional 325 Codell / J-Sand / Sussex proven recompletion opportunities and over 800 Codell new drill opportunities at December 31, 2004. The Company plans to
drill 110 Codell wells in 2005. During 2004, numerous well workovers, reactivations, and commingling of zones were performed. These projects, combined with the new drills, deepenings and refracs, were an integral part of the 2004 capital development
program. The Company estimates it had over 400 of these minor projects in inventory at year-end 2004.



At December 31, 2004, the Company had working interests in approximately 3,500 gross (3,300 net) producing oil and gas wells in the D-J Basin with
estimated proved reserves of 943.1 Bcfe, including 44.5 million barrels of oil and 676.4 Bcf of gas. Daily production from these properties averaged 195,861 Mcfe, comprised of 8,653 barrels and 143,942 Mcf per day in 2004. Based on a capital budget
of $300.0 million, the Company anticipates spending approximately $145.0 million in Wattenberg in 2005.



Mid Continent



In November 2002, Patina acquired the stock of Le Norman Energy Corporation for $62.0 million and the issuance of 513,200 shares of the Companys Common Stock. Le Normans properties are located primarily in the Anadarko and
Ardmore-Marietta Basins of Oklahoma. The Le Norman properties primarily produce oil. At the date of the acquisition, Le Norman held a 30% interest in an affiliated entity, Le Norman Partners (LNP). In December 2002, Patina acquired the
stock of Bravo Natural Resources, Inc., a Delaware corporation, for $119.0 million. Bravos properties are primarily located in Hemphill County, Texas and Custer and Caddo Counties of western Oklahoma, within the Anadarko Basin. The Bravo
properties primarily produce natural gas. In March 2003, the Company acquired the remaining 70% interest in LNP for $39.7 million. LNPs properties are located in Stephens, Garvin, and Carter Counties of Southern Oklahoma and produce primarily
oil. In October 2003, the Company acquired Cordillera Energy Partners, LLC (Cordillera) for $243.0 million, comprised of $239.0 million and the issuance of five year



16



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warrants to purchase 1,000,000 shares of Patina Common Stock for $22.50 per share. The Cordillera properties are primarily located in the Mid Continent and
the San Juan Basin, and primarily produce natural gas. Together the Le Norman, Bravo, LNP, and certain Cordillera properties comprise the Companys Mid Continent assets.



The Loco Field is comprised of 14 contiguous sections located in Stephens and Jefferson Counties, Oklahoma. The Field was
discovered in 1913, producing from shallow oil formations at depths ranging from 60 feet to 1,300 feet. Secondary recovery operations were implemented in the Field beginning with the unitization of the Loco Unit in 1956. The sediments draped over
this anticline include productive intervals on more than 20 lenticular sandstone intervals. Based on the average net pay of other completed wells in the area, a typical infill well will encounter in excess of 100 feet of net productive pay, although
not necessarily assured on a single well basis. The Company acquired interests in the Field as part of the Le Norman acquisition. The Company drilled 32 wells in the Field in 2004 with plans to drill approximately 15 wells in 2005. Simultaneously,
an expansion of the secondary recovery operations is underway with the installation of new injection facilities at the central tank batteries, along with the conversion of numerous producers to water injectors.



The Santa Fe Field, located in Stephens County, Oklahoma, was discovered in
1917. The Field covers approximately 13 contiguous sections, targeting shallow oil formations with productive sediments at depths ranging from 100 feet up to 1,200 feet. Certain portions of the Field are under secondary recovery while others remain
on primary production. The productive intervals are comprised of over 20 lenticular sands, routinely exhibiting porosities greater than 30% with an average well exhibiting approximately 90 feet of net pay. Interests in the Field were acquired as
part of the Le Norman acquisition. The Company also holds various rights to certain deeper horizons in the Field. The Company drilled five wells in the Field in 2004 and plans to drill six wells and to continue to evaluate additional exploitation
opportunities in the Field in 2005. The Company will continue to optimize and implement secondary recovery operations in the Field where permitted by the Oklahoma Corporation Commission.



The Company acquired interests in the Buffalo Wallow Field as part of the Bravo acquisition. The Field is located in
Hemphill County in the Texas Panhandle. The primary producing horizons, which generally produce natural gas, are comprised of various intervals in the Granite Wash sequence at approximately 11,000 feet. The productive intervals are comprised of a
series of stratigraphically trapped sands with an average gross interval of 700 feet. Based on the average net pay of other completed wells in the area, an average well will contain 100 feet to 250 feet of net pay, although not necessarily assured
on a single well basis. The Field has historically been developed on 40 acre spacing. In late 2004, the Texas Railroad Commission approved down spacing of the Field to allow development on 20 acre locations. The Company drilled 74 wells in the Field
in 2004 and plans to drill approximately 70 wells in 2005.



Based on the knowledge and expertise gained in the Companys Buffalo Wallow Field, approximately 10,000 net acres were leased in the last half of 2003 southeast of Buffalo Wallow for additional Granite Wash gas potential in an area
known as Billy Rose. This area offsets mature Granite Wash producing wells. The Company has applied evaluation and stimulation techniques, similar to those used in Buffalo Wallow, to determine and establish commercial gas production from the Granite
Wash pay zones extending from as shallow as 6,000 feet to greater than 12,000 feet within the block. In addition, Billy Rose is believed to hold additional potential in deeper horizons such as the Morrow and Hunton formations. In the last half of
2004, three wells were drilled and three of the older mature wells were recompleted into new pay zones. The Company plans to drill approximately ten wells in Billy Rose in 2005.



The Eakly-Weatherford Field is located in western Oklahoma in Caddo and Custer Counties within the Anadarko Basin.
Productive intervals include the Skinner, Red Fork, and Morrow producing sands ranging at depths of 10,000 feet to 14,000 feet. The deeper Springer series sands are also productive in the area at depths of approximately 15,000 feet. Interests in the
Field were acquired as part of the Bravo acquisition and were increased with the Cordillera acquisition. The Company drilled nine wells in the Field in 2004 and plans to drill approximately three wells in the Field during 2005 while continuing its
evaluation of the acreage position. Various wells in the Field exhibit productive behind pipe intervals that are expected to eventually be exploited.



In the fourth quarter of 2003, the Company acquired interests in the Elm Grove Field as part of the Cordillera acquisition. The Field is located within
the central part of the Anadarko Basin in Caddo and Blaine Counties of Oklahoma. The two main producing reservoirs in the Field are the Red Fork and Springer Sandstones ranging at



17



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depths of 11,000 feet to 13,000 feet. Additionally, the Company is currently evaluating future potential in several horizons in the Field, including the
Marchand, Skinner, and Hunton formations. The Company drilled five wells in the Field in 2004 and plans to drill approximately two wells in the Field during 2005.



During 2004, development expenditures for the Mid Continent region totaled $104.5 million for the drilling or deepening of
195 wells, three refracs, and 25 recompletions. At December 31, 2004, estimated proved reserves attributed to the Mid Continent region totaled 488.5 Bcfe, including 29.0 million barrels of oil and 314.4 Bcf of gas. Daily production from these
properties averaged 90,054 Mcfe, comprised of 5,253 barrels and 58,535 Mcf per day in 2004. Based on a capital budget of $300.0 million, the Company anticipates spending approximately $115.0 million in the Mid Continent region in 2005.



San Juan



As a result of the Cordillera acquisition in October 2003, the Company established a presence in the San Juan Basin which is
located in northwestern New Mexico and southwestern Colorado. The Basin is believed to contain the second largest deposit of natural gas reserves in North America. Within the Basin, gas production has been established across a broad area from
multiple Cretaceous sandstone reservoirs and coalbeds occurring at depths ranging from 1,500 feet to 9,000 feet. Most of the gas is produced from the Dakota Sandstone, the Mesaverde Group, the Pictured Cliffs Sandstone, and from coals in the
Fruitland Formation. The Companys assets consist of two relatively large consolidated acreage blocks in the northwestern and eastern parts of the Basin, with scattered acreage in the south-central portion, all in New Mexico. In each of these
areas, natural gas is being produced from multiple reservoirs within one or more of the main gas producing formations.



The La Plata Field is in the northwestern part of the San Juan Basin and gas production is generally limited to the Mesaverde Group between 4,000 feet and
5,000 feet, and the Dakota Sandstone between 6,600 feet and 7,500 feet. Natural gas production in the Dakota Sandstone occurs across the entire block, whereas the Mesaverde Group gas production is confined mostly to the northeastern two-thirds of
the acreage. Future gas production from these formations will come from additional development locations and possible infill drilling. Some coalbed methane is being produced from the Fruitland coals, and additional Fruitland coal development
locations are possible within the La Plata acreage block.



The
Jicarilla Field is located in the eastern part of the San Juan Basin on the Jicarilla Apache Reservation. Across this acreage block, natural gas is being produced from the Pictured Cliffs Sandstone at 3,900 feet, the Mesaverde Group between 5,500
feet and 6,200 feet, the Gallup Sandstone at 7,300 feet, and the Dakota Sandstone between 8,200 feet and 8,500 feet. Additional development locations and possible infill drilling targeting the main producing reservoirs may add gas reserves to the
Jicarilla acreage block.



During 2004, development expenditures
for the San Juan Basin totaled $16.0 million for the drilling of 12 wells, one refrac, and nine recompletions. At December 31, 2004, estimated proved reserves attributed to the San Juan Basin totaled 95.8 Bcfe, including 290,000 barrels of oil and
94.0 Bcf of gas. Daily production from these properties averaged 9,874 Mcfe, comprised of 55 barrels and 9,547 Mcf per day in 2004. Based on a capital budget of $300.0 million, the Company anticipates spending approximately $20.0 million in the San
Juan Basin in 2005 for the drilling of 30 wells and performing various recompletions.



Central and Other



In late 2000, Patina
acquired various property interests out of a bankruptcy through Elysium Energy, L.L.C., a New York limited liability company, in which the Company initially held a 50% interest. The Elysium properties primarily produce oil. In January 2003, the
Company acquired the remaining 50% interest of the joint venture. In late 2003, the Company sold its interests in various Louisiana fields for approximately $8.6 million. The Company formed a new ventures group in 2004, targeting non-conventional
tight gas reservoirs, including shale formations. Approximately 60,000 net acres were acquired by year-end 2004 with plans to accumulate over 100,000 net acres related to these prospects. At December 31, 2004, the oil and gas properties were located
primarily in central Kansas and the Illinois Basin, with minor interests remaining in Louisiana and Texas.



These properties comprise the Companys Central and Other areas of operations. During 2004 development expenditures for the Central and
Other properties totaled $21.2 million for the drilling or deepening of 73 wells and performing 68 recompletions, primarily in the Illinois Basin, Kansas and Texas. Daily



18



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production from these properties averaged 26,410 Mcfe, comprised of 4,088 barrels and 1,882 Mcf per day in 2004. At December 31, 2004, estimated proved
reserves totaled 91.6 Bcfe, including 14.5 million barrels of oil and 4.4 Bcf of gas. Based on a capital budget of $300.0 million, the Company anticipates spending approximately $20.0 million on these properties in 2005.



Proved Reserves



The following table sets forth estimated net proved reserves for the three years ended December 31, 2004.



|                                   |  |              |           |      |   |           |  |   |          
|---------------------------------- |  | ------------ | --------- | ---- | - | --------- |  | - | ---------
|                                   |  | December 31,
|                                   |  | 2002         |           | 2003 |   | 2004     
|Oil (MBbl)                         |  |              |           |      |   |           |  |   |          
|Developed                          |  |              |           |      |   |           |  |   |          
|Producing                          |  |              | 26,185    |      |   | 43,653    |  |   | 47,245   
|Non-producing                      |  |              | 15,648    |      |   | 14,475    |  |   | 18,210   
|                                   |  |              |           |      |   |           |  |   |          
|Total Developed                    |  |              | 41,833    |      |   | 58,128    |  |   | 65,455   
|Undeveloped                        |  |              | 15,495    |      |   | 23,819    |  |   | 22,830   
|                                   |  |              |           |      |   |           |  |   |          
|Total                              |  |              | 57,328    |      |   | 81,947    |  |   | 88,285   
|                                   |  |              |           |      |   |           |  |   |          
|Natural gas (MMcf)                 |  |              |           |      |   |           |  |   |          
|Developed                          |  |              |           |      |   |           |  |   |          
|Producing                          |  |              | 361,000   |      |   | 516,577   |  |   | 554,521  
|Non-producing                      |  |              | 161,227   |      |   | 179,672   |  |   | 213,082  
|                                   |  |              |           |      |   |           |  |   |          
|Total Developed                    |  |              | 522,227   |      |   | 696,249   |  |   | 767,603  
|Undeveloped                        |  |              | 235,295   |      |   | 328,085   |  |   | 321,692  
|                                   |  |              |           |      |   |           |  |   |          
|Total                              |  |              | 757,522   |      |   | 1,024,334 |  |   | 1,089,295
|                                   |  |              |           |      |   |           |  |   |          
|Total MMcfe                        |  |              | 1,101,491 |      |   | 1,516,014 |  |   | 1,619,003
|                                   |  |              |           |      |   |           |  |   |          
|PV10% Value (a) (non-GAAP measure) |  | $            | 1,484,936 |      | $ | 2,704,461 |  | $ | 3,129,572
|                                   |  |              |           |      |   |           |  |   |          
|Standardized Measure               |  | $            | 1,010,350 |      | $ | 1,781,019 |  | $ | 2,099,301
|                                   |  |              |           |      |   |           |  |   |          
|Oil price (Bbl)                    |  | $            | 30.51     |      | $ | 31.16     |  | $ | 41.48    
|Gas price (Mcf)                    |  | $            | 3.67      |      | $ | 5.54      |  | $ | 5.61     



The following table
sets forth the estimated pretax future net revenues as of year-end 2004 from the production of proved reserves and the PV10% value of such revenues, net of estimated future capital costs, including an estimate of $292.5 million of future development
costs (comprised of $110.3 of expenditures on proved developed non-producing properties and $182.2 million in expenditures on proved undeveloped properties) in 2005 (in thousands):



|                                 |  |                   |           |             |   |           |       |  |   |          
|-------------------------------- |  | ----------------- | --------- | ----------- | - | --------- | ----- |  | - | ---------
|                                 |  | December 31, 2004
|Future Net Revenues              |  | Developed         |           | Undeveloped |   |           | Total
|2005                             |  | $                 | 464,994   |             | $ | (103,916  | )     |  | $ | 361,078  
|2006                             |  |                   | 432,963   |             |   | 8,687     |       |  |   | 441,650  
|2007                             |  |                   | 398,791   |             |   | 54,733    |       |  |   | 453,524  
|Remainder                        |  |                   | 3,352,937 |             |   | 1,566,932 |       |  |   | 4,919,869
|                                 |  |                   |           |             |   |           |       |  |   |          
|Total                            |  | $                 | 4,649,685 |             | $ | 1,526,436 |       |  | $ | 6,176,121
|                                 |  |                   |           |             |   |           |       |  |   |          
|PV10% Value(a)(non-GAAP measure) |  | $                 | 2,581,818 |             | $ | 547,754   |       |  | $ | 3,129,572
|                                 |  |                   |           |             |   |           |       |  |   |          

---

|(a) | PV10% is a non-GAAP measure. See the reconciliation of PV10% to standardized measure (the
after tax present value discounted at 10% of the proved reserves, which totaled $2.1 billion at year-end 2004) at Note 12 to the accompanying consolidated financial statements.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



19



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The quantities and values in the preceding tables are based on constant prices in effect at December 31,
2004, which averaged $41.48 per barrel of oil and $5.61 per Mcf of gas. These wellhead average prices were based on year-end NYMEX prices of $43.45 per barrel and $6.15 per MMBtu. Price declines decrease reserve values by lowering the future net
revenues attributable to the reserves and reducing the quantities of reserves that are recoverable on an economic basis. Price increases have the opposite effect. A significant decline in the prices of oil and/or natural gas could have a material
adverse effect on the Companys financial condition and results of operations.



Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods under current economic conditions. Proved undeveloped reserves are
proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells where a
relatively major expenditure is required to establish production.



Future prices received from production and future production costs will vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. There can be no assurance that the proved reserves will be developed
within the periods indicated or that prices and costs will remain constant. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections.



The PV10% values shown should not be construed as the current market value of
the reserves. The quantities and values shown in the preceding tables are based on oil and natural gas prices in effect on December 31, 2004. The value of the Companys assets is in part dependent on the prices the Company receives for oil and
natural gas, and a significant decline in the price of oil or gas could have a material adverse effect on the Companys financial condition and results of operations. The 10% discount factor used to calculate PV10% value, which is specified by
the Securities and Exchange Commission (the SEC), is not necessarily the most appropriate discount rate, and present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production,
which may prove to be inaccurate. For properties operated by the Company, an allocation of certain overhead charges has been included in operating costs. In addition, the calculation of estimated future net revenues does not take into account the
effect of various cash outlays, including, among other things all general and administrative overhead costs and interest expense.



There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of
development expenditures. The data in the above tables represent estimates only. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Results of drilling, testing and production after the date of the estimate may justify revisions.
Accordingly, reserve estimates are often materially different from the quantities of oil and natural gas that are ultimately recovered.



The proved oil and gas reserves and future revenues as of December 31, 2004 were audited by Netherland, Sewell & Associates, Inc. (NSAI).
On an annual basis, the Company files the Department of Energy Form EIA-23, Annual Survey of Oil and Gas Reserves, as required by operators of domestic oil and gas properties. There are differences between the reserves as reported on
Form EIA-23 and reserves as reported herein. Form EIA-23 requires that operators report on total proved developed reserves for operated wells only and that the reserves be reported on a gross operated basis rather than on a net interest basis.



20



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Producing Wells



The following table sets forth the producing wells in which the Company owned a working interest at December 31, 2004. Wells are classified as oil or
natural gas wells according to their predominant production stream.



|                           |  |  |  |  |            |  |         
|-------------------------- |  |  |  |  | ---------- |  | --------
|PrincipalProduction Stream |  |  |  |  | GrossWells |  | NetWells
|Wattenberg                 |  |  |  |  |            |  |         
|Oil                        |  |  |  |  | 2,922      |  | 2,787   
|Natural gas                |  |  |  |  | 603        |  | 504     
|                           |  |  |  |  |            |  |         
|Total                      |  |  |  |  | 3,525      |  | 3,291   
|                           |  |  |  |  |            |  |         
|Mid Continent              |  |  |  |  |            |  |         
|Oil                        |  |  |  |  | 2,117      |  | 1,013   
|Natural gas                |  |  |  |  | 970        |  | 436     
|                           |  |  |  |  |            |  |         
|Total                      |  |  |  |  | 3,087      |  | 1,449   
|                           |  |  |  |  |            |  |         
|San Juan                   |  |  |  |  |            |  |         
|Oil                        |  |  |  |  |           |  |        
|Natural gas                |  |  |  |  | 183        |  | 147     
|                           |  |  |  |  |            |  |         
|Total                      |  |  |  |  | 183        |  | 147     
|                           |  |  |  |  |            |  |         
|Central and Other          |  |  |  |  |            |  |         
|Oil                        |  |  |  |  | 1,006      |  | 918     
|Natural gas                |  |  |  |  | 14         |  | 14      
|                           |  |  |  |  |            |  |         
|Total                      |  |  |  |  | 1,020      |  | 932     
|                           |  |  |  |  |            |  |         
|Total                      |  |  |  |  |            |  |         
|Oil                        |  |  |  |  | 6,045      |  | 4,718   
|Natural gas                |  |  |  |  | 1,770      |  | 1,101   
|                           |  |  |  |  |            |  |         
|Total                      |  |  |  |  | 7,815      |  | 5,819   
|                           |  |  |  |  |            |  |         



The Company had 227
wells (219 net) in Wattenberg, 763 wells (518 net) in the Mid Continent region, four wells (four net) in the San Juan Basin, and 739 wells (680 net) in the Central and Other areas that were shut-in at December 31, 2004. The Companys average
working interest in the Wattenberg wells was approximately 93%, the average working interest in the Mid Continent wells was approximately 47%, the average working interest in the San Juan wells was 80%, and the average working interest in the
Central and Other wells was 91%. As of December 31, 2004, the Company operated approximately 5,800 gross (5,500 net) producing wells.



21



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Drilling Results



The following table sets forth the number of wells drilled or deepened by the Company during the past three years. During 2002, the Company drilled or
deepened 66 development wells (62 net) in Wattenberg, drilled 24 development wells (12 net) in the Illinois Basin, drilled or deepened 16 development wells (eight net) in Kansas, and two wells (one net) in California, drilled 33 development wells
(31 net) in the Mid Continent region, and drilled four wells on its other projects (four net). The Company also drilled five exploratory coalbed methane wells (five net) in northwest Colorado. During 2003, the Company drilled or deepened 80
development wells (75 net) in Wattenberg, drilled 190 development wells (170 net) in the Mid Continent region, drilled one well (zero net) in the San Juan Basin, and drilled 74 development wells (73 net) in the Central and Other areas. During 2004,
the Company drilled or deepened 114 development wells (110 net) in Wattenberg, drilled 195 development wells (151 net) in the Mid Continent region, drilled 12 wells (10 net) in the San Juan Basin, and drilled 73 development wells (73 net) in the
Central and Other areas. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or
economic value. Productive wells are those that produce commercial quantities of hydrocarbons whether or not they produce a reasonable rate of return.



|           |  |       |  |       |  |      
|---------- |  | ----- |  | ----- |  | -----
|           |  | 2002  |  | 2003  |  | 2004 
|Productive |  |       |  |       |  |      
|Gross      |  | 140.0 |  | 345.0 |  | 388.0
|Net        |  | 114.0 |  | 318.0 |  | 339.0
|Dry        |  |       |  |       |  |      
|Gross      |  | 4.0   |  | 5.0   |  | 6.0  
|Net        |  | 2.0   |  | 5.0   |  | 5.0  



At December 31, 2004,
the Company had 11 wells (10 net) in Wattenberg, 29 wells (22 net) in the Mid Continent region, three wells (three net) in San Juan, and one well (one net) in the Central and Other areas waiting on completion.



Acreage



The following table sets forth the leasehold acreage held by the Company at December 31, 2004. Undeveloped acreage is
acreage held under lease, permit, contract or option that is not in a spacing unit for a producing well, including leasehold interests identified for development or exploratory drilling. Developed acreage is acreage assigned to producing wells.



|                    |  |           |  |             |  |         |  |        
|------------------- |  | --------- |  | ----------- |  | ------- |  | -------
|                    |  | Developed |  | Undeveloped
|                    |  | Gross     |  | Net         |  | Gross   |  | Net    
|Colorado            |  | 200,800   |  | 179,300     |  | 49,300  |  | 42,500 
|Oklahoma            |  | 259,700   |  | 83,400      |  | 79,900  |  | 31,500 
|Texas               |  | 58,800    |  | 31,800      |  | 25,800  |  | 14,900 
|Illinois / Indiana  |  | 45,400    |  | 37,400      |  | 8,100   |  | 8,100  
|New Mexico          |  | 30,800    |  | 18,400      |  | 10,000  |  | 3,500  
|Louisiana           |  | 13,200    |  | 5,400       |  |        |  |       
|Kansas              |  | 11,300    |  | 10,800      |  | 5,900   |  | 5,400  
|Wyoming             |  | 10,000    |  | 1,000       |  | 14,200  |  | 9,200  
|Alabama/Mississippi |  | 1,000     |  | 400         |  | 172,000 |  | 35,300 
|Arkansas            |  | 800       |  | 300         |  | 13,200  |  | 12,900 
|Michigan            |  |          |  |            |  | 28,200  |  | 28,100 
|Other               |  | 10,000    |  | 8,000       |  | 17,200  |  | 5,600  
|                    |  |           |  |             |  |         |  |        
|Total               |  | 641,800   |  | 376,200     |  | 423,800 |  | 197,000
|                    |  |           |  |             |  |         |  |        



22



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|ITEM 3. | LEGAL PROCEEDINGS
|------- | -----------------



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 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.



|ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
|------- | ---------------------------------------------------



There were no matters submitted to a vote of security holders during the fourth quarter of the year ended December 31, 2004.



23



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PART II



|ITEM 5. | MARKET FOR THE REGISTRANTS COMMON EQUITY, RELATED SECURITY HOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|------- | --------------------------------------------------------------------------------------------------------------------



The Companys Common Stock is listed on the New York Stock Exchange
(NYSE) under the symbol POG. In June 2002 and June 2004, 5-for-4 stock splits were effected in the form of a 25% stock dividends to common stockholders. In March 2004, a 2-for-1 stock split was paid 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 5-for-4 and 2-for-1 stock dividends and split. The following represent the high and low sales prices
of the Companys Common Stock during the respective periods.



|               |  |              |       |     |   |      
|-------------- |  | ------------ | ----- | --- | - | -----
|               |  | Common Stock
|               |  | High         |       | Low
|2003           |  |              |       |    
|First Quarter  |  | $            | 13.95 |     | $ | 11.92
|Second Quarter |  |              | 16.72 |     |   | 12.83
|Third Quarter  |  |              | 19.00 |     |   | 14.21
|Fourth Quarter |  |              | 25.38 |     |   | 18.23
|2004           |  |              |       |    
|First Quarter  |  | $            | 26.79 |     | $ | 20.76
|Second Quarter |  |              | 30.96 |     |   | 24.62
|Third Quarter  |  |              | 31.68 |     |   | 24.76
|Fourth Quarter |  |              | 37.56 |     |   | 28.02



On February 24, 2005,
the closing price of the Common Stock was $39.34.



Holders of Record



As of February 24, 2005, there were 120 holders of record
of the Common Stock and 71.2 million shares outstanding, exclusive of the 2.1 million common shares held in treasury stock through the Companys deferred compensation plan.



Dividends



Adjusted for the stock dividends and split, following is a schedule of quarterly cash dividends per share paid on the Common Stock since the dividend was
initiated in December 1997:



|     |  |         |        |        |   |        |  |        |        |       |   |        |  |   |       
|---- |  | ------- | ------ | ------ | - | ------ |  | ------ | ------ | ----- | - | ------ |  | - | ------
|     |  | Quarter |        |       
|     |  | First   |        | Second |   | Third  |  | Fourth |        | Total
|1997 |  | $       |       |        | $ |       |  | $      |       |       | $ | 0.0032 |  | $ | 0.0032
|1998 |  |         | 0.0032 |        |   | 0.0032 |  |        | 0.0032 |       |   | 0.0032 |  |   | 0.0128
|1999 |  |         | 0.0032 |        |   | 0.0032 |  |        | 0.0032 |       |   | 0.0064 |  |   | 0.0160
|2000 |  |         | 0.0064 |        |   | 0.0064 |  |        | 0.0064 |       |   | 0.0128 |  |   | 0.0320
|2001 |  |         | 0.0128 |        |   | 0.0128 |  |        | 0.0128 |       |   | 0.0160 |  |   | 0.0544
|2002 |  |         | 0.0160 |        |   | 0.0200 |  |        | 0.0200 |       |   | 0.0240 |  |   | 0.0800
|2003 |  |         | 0.0240 |        |   | 0.0300 |  |        | 0.0300 |       |   | 0.0400 |  |   | 0.1240
|2004 |  |         | 0.0500 |        |   | 0.0500 |  |        | 0.0500 |       |   | 0.0600 |  |   | 0.2100



The continuation of
cash dividends and the amounts thereof will depend upon the Companys earnings, financial condition, capital requirements and other factors. Under the terms of its bank credit agreement, the Company had $125.5 million available for dividends
and or other restricted payments as of December 31, 2004. The amount available for dividends and other restricted payments increases quarterly by 20% of cash flow, as defined.



24



---

Securities Authorized for Issuance under Equity Compensation Plans



The following table includes information regarding the Companys equity
compensation plans as of the year ended December 31, 2004 (a):



|                                                                           |  |                                                                     |  |                                                       |       |                                                                                            |          
|-------------------------------------------------------------------------- |  | ------------------------------------------------------------------- |  | ----------------------------------------------------- | ----- | ------------------------------------------------------------------------------------------ | ---------
|Plan category                                                              |  | Number ofsecurities to beissued uponexercise of outstanding options |  | Weighted-averageexercise price of outstanding options |       | Number ofsecurities remaining availablefor future issuance under equity compensation plans
|Equity compensation plans approved by security holders (stock option plan) |  | 6,243,200                                                           |  | $                                                     | 14.66 |                                                                                            | 3,131,800
|Equity compensation plans not approved by security holders                 |  |                                                                    |  |                                                       |      |                                                                                            |         
|                                                                           |  |                                                                     |  |                                                       |       |                                                                                            |          
|Total                                                                      |  | 6,243,200                                                           |  | $                                                     | 14.66 |                                                                                            | 3,131,800
|                                                                           |  |                                                                     |  |                                                       |       |                                                                                            |          



(a) Although the Company does not
maintain a formal plan, Common Stock may be issued to officers and key employees in lieu of cash for bonuses and to non-employee directors in lieu of cash retainers. All such issuances are approved by the Compensation Committee, which is comprised
of three independent directors, or the entire Board of Directors. See Notes (7) and (8) to the accompanying consolidated financial statements for more information on such issuances.



Recent Sales of Unregistered Securities



The following table includes information regarding securities issued under the Companys Stock Purchase Plan:



|     |  |                       |  |                            |      |              |   |          
|---- |  | --------------------- |  | -------------------------- | ---- | ------------ | - | ---------
|Year |  | Numberof sharesissued |  | Weighted-averageshareprice |      | Cashproceeds
|2004 |  |                      |  | $                          |     |              | $ |         
|2003 |  |                      |  | $                          |     |              | $ |         
|2002 |  | 557,500               |  | $                          | 8.94 |              | $ | 4,985,000



Shares issued under
the Companys Stock Purchase Plan are made available to officers and directors of the Company at a discount to market (generally the purchase price has been set at 75% of market price). The number of shares made available for purchase is
approved by the Companys Compensation Committee of the Board of Directors on an annual basis. All such shares are restricted from any sale for a period of one year from the date of purchase. The Stock Purchase Plan was suspended as of December
31, 2002. For further information see Note (8) to the accompanying consolidated financial statements.



In conjunction with the Le Norman acquisition in November 2002, the Company issued 513,200 shares of Common Stock to the sellers. In conjunction with the
Cordillera acquisition in October 2003, the Company issued 1.0 million five year warrants to purchase the Companys Common Stock for $22.50 per share. No cash proceeds were received by the Company for either of these two issuances.



Effective May 2004, the Board of Directors suspended the automatic
restricted stock grant provisions of the Companys 1996 Stock Plan for Non-Employee Directors (the Directors Plan). In June 2004, the Board of Directors 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. On July 19, 2004, the Board of Directors issued 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. All of such shares were issued pursuant to the exemption from the registration requirements of the Securities Act of 1933, as amended, provided by Section 4(2) of such
Act.



25



---

|ITEM 6. | SELECTED FINANCIAL DATA
|------- | -----------------------



The following table presents selected historical financial data of the Company for the five-year period ended December 31, 2004. All share and per share
amounts for all periods presented have been restated to reflect the 5-for-4 stock splits which were effected in the form of a stock dividend to common stockholders of record in June 2002 and June 2003 and the 2-for-1 stock split in February 2004.
Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines, the pending merger with Noble Energy, and other factors. This information should be read in conjunction with
the financial statements and notes thereto and Managements Discussion and Analysis of Financial Condition and Results of Operations, presented elsewhere herein. The data reflects the acquisition of 50% of Elysium in November 2000, Le Norman in
November 2002, Bravo in December 2002, the remaining 50% of Elysium in January 2003, Le Norman Partners in March 2003, and Cordillera Energy Partners in October 2003.



|                                          |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|----------------------------------------- |  | ---------------------------------------- | ------- | - | ---- | - | ------- | ---- |  | - | -------- | - |  | ---- | --------- | - |  | - | --------- | -
|                                          |  | As of or for the Year Ended December 31, |        
|                                          |  | 2000                                     |         |   | 2001 |   |         | 2002 |  |   | 2003     |   |  | 2004 |          
|                                          |  | (In thousands except per share data)     |        
|Statement of Operations Data              |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Revenues                                  |  | $                                        | 150,342 |   |      | $ | 214,173 |      |  | $ | 222,407  |   |  | $    | 406,717   |   |  | $ | 561,001   |  
|Expenses                                  |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Lease operating                           |  |                                          | 13,426  |   |      |   | 25,356  |      |  |   | 27,986   |   |  |      | 54,082    |   |  |   | 71,596    |  
|Production taxes                          |  |                                          | 10,628  |   |      |   | 13,462  |      |  |   | 11,751   |   |  |      | 28,726    |   |  |   | 46,034    |  
|Exploration                               |  |                                          | 293     |   |      |   | 513     |      |  |   | 2,171    |   |  |      | 6,207     |   |  |   | 2,058     |  
|General and administrative                |  |                                          | 7,165   |   |      |   | 10,994  |      |  |   | 12,714   |   |  |      | 19,034    |   |  |   | 26,390    |  
|Interest                                  |  |                                          | 10,012  |   |      |   | 7,016   |      |  |   | 2,299    |   |  |      | 8,817     |   |  |   | 12,563    |  
|Impairment of hedges                      |  |                                          |        |   |      |   | 6,370   |      |  |   |         |   |  |      |          |   |  |   |          |  
|Loss on sale of oil and gas properties    |  |                                          |        |   |      |   |        |      |  |   |         |   |  |      | 7,223     |   |  |   |          |  
|Other                                     |  |                                          | 105     |   |      |   | 18      |      |  |   | 463      |   |  |      | 578       |   |  |   | 301       |  
|Deferred compensation adjustments         |  |                                          | 12,734  |   |      |   | 3,236   |      |  |   | 9,983    |   |  |      | 33,110    |   |  |   | 31,722    |  
|Depletion, depreciation and amortization  |  |                                          | 40,600  |   |      |   | 49,916  |      |  |   | 66,162   |   |  |      | 98,119    |   |  |   | 126,849   |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Total expenses                            |  |                                          | 94,963  |   |      |   | 116,881 |      |  |   | 133,529  |   |  |      | 255,896   |   |  |   | 317,513   |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Pretax income                             |  |                                          | 55,379  |   |      |   | 97,292  |      |  |   | 88,878   |   |  |      | 150,821   |   |  |   | 243,488   |  
|Provision for income taxes                |  |                                          | 12,953  |   |      |   | 35,025  |      |  |   | 31,171   |   |  |      | 57,312    |   |  |   | 92,525    |  
|Cumulative effect of accounting change    |  |                                          |        |   |      |   |        |      |  |   |         |   |  |      | 2,613     |   |  |   |          |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Net income                                |  | $                                        | 42,426  |   |      | $ | 62,267  |      |  | $ | 57,707   |   |  | $    | 90,896    |   |  | $ | 150,963   |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Net income per share                      |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Basic                                     |  | $                                        | 0.75    |   |      | $ | 1.00    |      |  | $ | 0.88     |   |  | $    | 1.33      |   |  | $ | 2.15      |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Diluted                                   |  | $                                        | 0.61    |   |      | $ | 0.93    |      |  | $ | 0.84     |   |  | $    | 1.28      |   |  | $ | 2.05      |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Weighted average shares outstanding       |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Basic                                     |  |                                          | 52,325  |   |      |   | 62,392  |      |  |   | 65,933   |   |  |      | 68,170    |   |  |   | 70,234    |  
|Diluted                                   |  |                                          | 68,433  |   |      |   | 67,290  |      |  |   | 68,970   |   |  |      | 71,062    |   |  |   | 73,473    |  
|                                          |  |                                          |         |   |     
|Cash dividends per common share           |  | $                                        | 0.032   |   |      | $ | 0.054   |      |  | $ | 0.080    |   |  | $    | 0.124     |   |  | $ | 0.210     |  
|                                          |  |                                          |         |   |     
|Balance Sheet Data                        |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Current assets                            |  | $                                        | 39,368  |   |      | $ | 40,671  |      |  | $ | 49,222   |   |  | $    | 102,032   |   |  | $ | 181,220   |  
|Oil and gas properties, net               |  |                                          | 355,904 |   |      |   | 378,011 |      |  |   | 637,258  |   |  |      | 1,068,660 |   |  |   | 1,211,675 |  
|Total assets                              |  |                                          | 422,578 |   |      |   | 455,524 |      |  |   | 719,090  |   |  |      | 1,196,291 |   |  |   | 1,429,039 |  
|Current liabilities                       |  |                                          | 30,867  |   |      |   | 45,065  |      |  |   | 69,072   |   |  |      | 142,544   |   |  |   | 285,469   |  
|Debt                                      |  |                                          | 177,000 |   |      |   | 77,000  |      |  |   | 200,000  |   |  |      | 416,000   |   |  |   | 297,000   |  
|Stockholders equity                      |  |                                          | 160,151 |   |      |   | 249,574 |      |  |   | 298,580  |   |  |      | 330,512   |   |  |   | 410,819   |  
|                                          |  |                                          |         |   |     
|Cash Flow Data                            |  |                                          |         |   |      |   |         |      |  |   |          |   |  |      |           |   |  |   |           |  
|Net cash provided by operating activities |  | $                                        | 109,384 |   |      | $ | 172,777 |      |  | $ | 152,157  |   |  | $    | 271,825   |   |  | $ | 396,569   |  
|Net cash used in investing activities     |  |                                          | (86,134 | ) |      |   | (82,357 | )    |  |   | (282,392 | ) |  |      | (470,881  | ) |  |   | (258,641  | )
|Net cash from financing activities        |  |                                          | (21,223 | ) |      |   | (92,823 | )    |  |   | 131,905  |   |  |      | 197,681   |   |  |   | (135,449  | )



26



---

The following tables set forth unaudited summary financial results on a quarterly basis for the last two
years.



|                                         |  |       |         |        |   |         |  |   |         |   |  |   |        
|---------------------------------------- |  | ----- | ------- | ------ | - | ------- |  | - | ------- | - |  | - | -------
|                                         |  | 2003 
|(In thousands, except per share data)    |  | First |         | Second |   | Third   |  |   | Fourth 
|Revenues                                 |  | $     | 89,967  |        | $ | 92,418  |  | $ | 99,180  |   |  | $ | 125,153
|Lease operating expenses                 |  |       | 10,698  |        |   | 13,948  |  |   | 14,420  |   |  |   | 15,016 
|Production taxes                         |  |       | 6,485   |        |   | 6,407   |  |   | 7,155   |   |  |   | 8,679  
|General and administrative               |  |       | 4,446   |        |   | 4,237   |  |   | 4,355   |   |  |   | 5,997  
|Deferred compensation adjustment         |  |       | 1,058   |        |   | 8,861   |  |   | 5,966   |   |  |   | 17,226 
|Depletion, depreciation and amortization |  |       | 21,087  |        |   | 23,270  |  |   | 24,571  |   |  |   | 29,191 
|Cumulative effect of accounting change   |  |       | 2,613   |        |   |        |  |   |        |   |  |   |       
|Net income                               |  |       | 23,982  |        |   | 20,288  |  |   | 25,019  |   |  |   | 21,607 
|Net income per share(1)                  |  |       |         |        |   |         |  |   |         |   |  |   |        
|Basic                                    |  | $     | 0.35    |        | $ | 0.30    |  | $ | 0.37    |   |  | $ | 0.31   
|Diluted                                  |  |       | 0.34    |        |   | 0.29    |  |   | 0.35    |   |  |   | 0.30   
|                                         |  |       |         |       
|Average daily production                 |  |       |         |        |   |         |  |   |         |   |  |   |        
|Oil (Bbl)                                |  |       | 13,385  |        |   | 16,165  |  |   | 15,777  |   |  |   | 17,505 
|Gas (Mcf)                                |  |       | 160,516 |        |   | 168,274 |  |   | 179,880 |   |  |   | 209,367
|Equivalent Mcfe                          |  |       | 240,824 |        |   | 265,264 |  |   | 274,542 |   |  |   | 314,398
|                                         |  |       |         |       
|Average realized prices                  |  |       |         |        |   |         |  |   |         |   |  |   |        
|Oil (Bbl)                                |  | $     | 26.73   |        | $ | 25.60   |  | $ | 25.45   |   |  | $ | 25.60  
|Gas (Mcf)                                |  |       | 3.97    |        |   | 3.48    |  |   | 3.68    |   |  |   | 4.11   
|Equivalent Mcfe                          |  |       | 4.13    |        |   | 3.77    |  |   | 3.87    |   |  |   | 4.16   
|                                         | 
|                                         |  | 2004 
|(In thousands, except per share data)    |  | First |         | Second |   | Third   |  |   | Fourth 
|Revenues                                 |  | $     | 137,926 |        | $ | 128,403 |  | $ | 138,015 |   |  | $ | 156,657
|Lease operating expenses                 |  |       | 15,738  |        |   | 17,551  |  |   | 17,681  |   |  |   | 20,626 
|Production taxes                         |  |       | 10,536  |        |   | 11,222  |  |   | 12,597  |   |  |   | 11,680 
|General and administrative               |  |       | 5,334   |        |   | 5,889   |  |   | 6,281   |   |  |   | 8,885  
|Deferred compensation adjustment         |  |       | 4,708   |        |   | 8,749   |  |   | (498    | ) |  |   | 18,763 
|Depletion, depreciation and amortization |  |       | 29,411  |        |   | 30,097  |  |   | 31,365  |   |  |   | 35,976 
|Net income                               |  |       | 42,751  |        |   | 31,751  |  |   | 41,442  |   |  |   | 35,018 
|Net income per share(1)                  |  |       |         |        |   |         |  |   |         |   |  |   |        
|Basic                                    |  | $     | 0.62    |        | $ | 0.45    |  | $ | 0.59    |   |  | $ | 0.50   
|Diluted                                  |  |       | 0.59    |        |   | 0.43    |  |   | 0.54    |   |  |   | 0.47   
|                                         |  |       |         |       
|Average daily production                 |  |       |         |        |   |         |  |   |         |   |  |   |        
|Oil (Bbl)                                |  |       | 17,744  |        |   | 17,768  |  |   | 18,004  |   |  |   | 18,673 
|Gas (Mcf)                                |  |       | 204,771 |        |   | 211,575 |  |   | 217,582 |   |  |   | 221,571
|Equivalent Mcfe                          |  |       | 311,237 |        |   | 318,183 |  |   | 325,606 |   |  |   | 333,607
|                                         |  |       |         |       
|Average realized prices                  |  |       |         |        |   |         |  |   |         |   |  |   |        
|Oil (Bbl)                                |  | $     | 26.62   |        | $ | 26.31   |  | $ | 26.90   |   |  | $ | 27.95  
|Gas (Mcf)                                |  |       | 4.62    |        |   | 4.37    |  |   | 4.58    |   |  |   | 5.14   
|Equivalent Mcfe                          |  |       | 4.56    |        |   | 4.38    |  |   | 4.55    |   |  |   | 4.98   



|(1) | Adjusted for the June 2002 and June 2003 25% stock dividends (5-for-4 splits) and the
February 2004 2-for-1 stock split.
|--- | ------------------------------------------------------------------------------------------------------------------------



The total of the earnings per
share for each quarter does not equal the earnings per share for the full year, either because the calculations are based on the weighted average shares outstanding during each of the individual periods or rounding.



27



---

|ITEM 7. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|------- | -------------------------------------------------------------------------------------



Overview



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, 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 stockholders of Patina and Noble Energy. The transaction is expected to close in the second quarter of 2005. For more information regarding the proposed merger, please refer to the section entitled Business  Pending
Merger with Noble Energy, Inc. above and the joint proxy statement/ prospectus of Noble Energy and Patina that is included in the registration statement on Form S-4 filed by Noble Energy with the SEC on January 25, 2005, and other relevant
materials that may be filed by Patina or Noble Energy with the SEC, including any amendments to such registration statement. The following discussion relates to our plans for the year 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 recently acquired Mid Continent and San Juan Basin properties; (iii) selective pursuit of
further consolidation and acquisition opportunities, and (iv) generation and exploitation of exploration and development projects with a focus on projects near currently owned productive properties.



Following are highlights of the Companys 2004 performance in several
key areas:



| |  |  | Daily production increased 18% from 274.0 MMcfe per day in 2003 to 322.2 MMcfe per day in 2004. The Companys Wattenberg properties contributed 10% of this increase, while the
full year benefit of production from San Juan and Mid Continent properties acquired in 2003 contributed 49%. Extensive development of the Companys Mid Continent properties also contributed to the increase.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Revenues increased 38% from $406.7 million in 2003 to $561.0 million in 2004 primarily due to the 18% increase in production and a 16% increase in realized oil and gas prices. Net
income increased 66% from $90.9 million in 2003 to $151.0 million in 2004. Cash flow from operations increased 46% from $271.8 million in 2003 to $396.6 million in 2004.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Proved Reserves increased 7% from 1.5 Tcfe to 1.6 Tcfe, with ongoing development and performance revisions contributing 212 Bcfe and acquisitions of 22 Bcfe, respectively. In
addition, the change in oil and gas prices and costs increased reserves 10 Bcfe. The reserve increases were offset by 118 Bcfe of production and 23 Bcfe of reserves sold. The Company replaced 187% of production in 2004 at a finding and development
cost of $1.17 per Mcfe.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The Company spent $253.9 million on the further development of its properties, as follows:
| | - |  | ------------------------------------------------------------------------------------------



|                  |  |              |       |                      |     |         |     |          |    |               |   
|----------------- |  | ------------ | ----- | -------------------- | --- | ------- | --- | -------- | -- | ------------- | --
|                  |  | Expenditures |       | Drillings/Deepenings |     | Refracs |     | Trifracs |    | Recompletions
|Wattenberg        |  | $            | 112.2 |                      | 114 |         | 369 |          | 32 |               | 56
|Mid Continent     |  |              | 104.5 |                      | 195 |         | 3   |          |   |               | 25
|San Juan          |  |              | 16.0  |                      | 12  |         | 1   |          |   |               | 9 
|Central and Other |  |              | 21.2  |                      | 73  |         |    |          |   |               | 68
|                  |  |              |       |                      |     |         |     |          |    |               |   
|Total             |  | $            | 253.9 |                      |     |         |     |          |    |               |   
|                  |  |              |       |                      |     |         |     |          |    |               |   



The Company
anticipates incurring approximately $300.0 million on the further development of its properties in 2005.



28



---

Critical Accounting Policies and Estimates



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  All of the proved reserve data in this Form 10-K are estimates. 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.



29



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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, 2003 and 2004, the Companys balance sheet included a liability for ARO of $27.6 million and $31.5 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.



30



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Factors Affecting Financial Condition and Liquidity



Liquidity and Capital Resources



During 2004, the Company spent $253.9 million on the further development of properties and $29.3 million on acquisitions. Acquisition expenditures were
primarily comprised of $20.2 million for developed property acquisitions and $9.1 million for unproven property acquisitions, primarily leasehold acreage. Development expenditures included $112.2 million in Wattenberg for the drilling or deepening
of 47 J-Sand wells, the drilling of 67 Codell wells, and performing 334 Codell refracs, 35 Niobrara refracs, 32 Codell trifracs and 56 recompletions, $104.5 million on the further development of the Mid Continent (Le Norman, Le Norman Partners,
Bravo, and certain Cordillera properties) for the drilling or deepening of 195 wells, and performing three refracs and 25 recompletions, $16.0 million in the San Juan Basin for the drilling or deepening of 12 wells and performing one refrac and nine
recompletions, and $21.2 million on other properties (primarily in Illinois and Kansas), primarily for drilling or deepening 73 wells and performing 68 recompletions. These acquisitions and projects, and the continued success in production
enhancement allowed production to increase 18% over the prior year. The decision to increase or decrease development activity is heavily dependent on the prices being received for production.



At December 31, 2004, the Company had $1.4 billion of assets. Total
capitalization was $707.8 million, of which 58% was represented by stockholders equity and 42% by bank debt. During 2004, net cash provided by operations totaled $396.6 million, as compared to $271.8 million in 2003. At December 31, 2004,
there were no significant commitments for capital expenditures. Based upon a $300.0 million capital budget for 2005, the Company expects production to continue to increase in the coming year. The level of these and other future expenditures is
largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. The Company plans to finance its ongoing development, acquisition
and exploration expenditures and additional equity repurchases using 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 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
December 31, 2004 and the effect such obligations are expected to have on its liquidity and cash flow in future periods (in thousands):



|                                |  |                   |         |            |   |            |  |              |       |       |   |        |  |   |        
|------------------------------- |  | ----------------- | ------- | ---------- | - | ---------- |  | ------------ | ----- | ----- | - | ------ |  | - | -------
|                                |  | Less thanOne Year |         | 1  3Years |   | 3  5Years |  | After 5Years |       | Total
|Long term debt                  |  | $                 |        |            | $ | 297,000    |  | $            |      |       | $ |       |  | $ | 297,000
|Firm transportation agreement   |  |                   | 582     |            |   | 1,164      |  |              | 1,164 |       |   | 8,194  |  |   | 11,104 
|Non-cancelable operating leases |  |                   | 1,448   |            |   | 3,105      |  |              | 1,258 |       |   |       |  |   | 5,811  
|Asset retirement obligation     |  |                   |        |            |   | 4,045      |  |              | 1,546 |       |   | 25,870 |  |   | 31,461 
|Derivative obligations(a)       |  |                   | 144,256 |            |   | 66,167     |  |              |      |       |   |       |  |   | 210,423
|                                |  |                   |         |            |   |            |  |              |       |       |   |        |  |   |        
|Total obligations               |  | $                 | 146,286 |            | $ | 371,481    |  | $            | 3,968 |       | $ | 34,064 |  | $ | 555,799
|                                |  |                   |         |            |   |            |  |              |       |       |   |        |  |   |        



|(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 December 31, 2004. The ultimate settlement amounts of these hedges are unknown because they are subject to continuing market risk. See Item 7A. 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.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



31



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Banking



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



|                          |  |                   |         |             |   |           |  |   |        
|------------------------- |  | ----------------- | ------- | ----------- | - | --------- |  | - | -------
|                          |  | December 31, 2004
|                          |  | BorrowingBase     |         | Outstanding |   | Available
|Revolving Credit Facility |  | $                 | 500,000 |             | $ | 297,000   |  | $ | 203,000
|                          |  |                   |         |             |   |           |  |   |        



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 December 31, 2004. A total of $203.0 million was available under the Credit Agreement at December 31, 2004.



The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the LIBOR rate for one, two, three or six months
plus a margin which fluctuates from 1.25% to 1.90%, or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.65%. The margins are determined by a debt to EBITDA ratio, as defined. The weighted average interest rate under the facility
was 2.9% during 2004 and 3.6% at December 31, 2004.



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 December 31, 2003 and 2004, the Company
was in compliance with the covenants. Borrowings under the Credit Agreement mature in January 2007, but may be prepaid at anytime. The Company had a restricted payment basket under the Credit Agreement of $125.5 million as of December 31, 2004,
which may be used to repurchase equity securities, pay dividends or make other restricted payments.



Cash Flow



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 $253.9 million of development expenditures for 2004 were funded entirely with cash flow from operations. The $29.3 million of acquisition expenditures were
largely funded by bank borrowings, somewhat offset by current year 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 December 31, 2004, the Company had $297.0 million outstanding under its bank facility. As such, exclusive of any
other acquisitions or significant equity repurchases, management expects to reduce long-term debt and fund the development program with cash flow from operations.



32



---

Net cash provided by operating activities in 2002, 2003 and 2004 was $152.2 million, $271.8 million and
$396.6 million, respectively. Cash flow from operations decreased in 2002 due to the decline in average oil and gas prices, partially offset by increased production. Cash flow from operations increased in 2003 due to the 44% increase in oil and gas
equivalent production and the 29% increase in average oil and gas prices received. Lease operating expenses, production taxes, general and administrative expenses and interest expense all increased as a result of the acquisitions made in the fourth
quarter of 2002 (Le Norman and Bravo), the first quarter of 2003 (Elysium and Le Norman Partners), and the fourth quarter of 2003 (Cordillera). Cash flows from operations increased in 2004 due to the 18% increase in oil and gas equivalent production
and the 16% increase in average oil and gas prices received. Operating cash flows in 2002, 2003 and 2004 were benefited by $3.5 million, $10.6 million and $10.7 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 2002, 2003 and 2004 totaled $282.4 million, $470.9 million and $258.6 million, respectively. The increase in expenditures in 2003 was primarily due to incurring $307.3 million of acquisition costs primarily related to Elysium, Le Norman Partners,
and Cordillera acquisitions, the $52.5 million increase in development expenditures on the Mid Continent properties, the $9.9 million increase in development expenditures in Wattenberg, and the $15.0 million increase in development expenditures on
the Central and Other properties. The decrease in expenditures in 2004 was primarily due to a decrease in acquisition expenditures of $278.0 million, offset by the increase in development expenditures of $77.7 million. The increase in development
expenditures was comprised of $20.1 million, $47.4 million, and $14.7 million in Wattenberg, Mid Continent, and San Juan, respectively, somewhat offset by a decrease of $4.4 million on the Central and Other properties.



Net cash provided by financing activities was $131.9 million and $197.7
million in 2002 and 2003, respectively, while net cash used in financing activities was $135.4 million in 2004. Sources of financing have been primarily bank borrowings. In 2002, the Company borrowed $123.0 million of bank debt. These borrowings
were used in conjunction with operating cash flow and proceeds of $14.4 million from Stock Purchase Plan purchases and the exercise of Company stock options to fund the Le Norman and Bravo acquisitions and capital development expenditures of $97.4
million. During 2003, the combination of operating cash flow, bank borrowings of $216.0 million and $9.3 million in proceeds from the issuance of Common Stock, allowed the Company to fund net capital development and acquisition expenditures of
$466.5 million, repurchase $17.2 million in Common Stock and pay Common Stock dividends of $8.8 million. During 2004, the combination of operating cash flow and $13.5 million in proceeds from the issuance of Common Stock allowed the Company to fund
net capital development and acquisition expenditures of $254.2 million, repay $119.0 million of bank debt, repurchase $14.7 million in Common Stock and pay Common Stock dividends of $15.3 million.



Capital Requirements



During 2004, $254.2 million of capital, net of $29.0 million of property sales, was expended, including $253.9 million on
development projects and $29.3 million on acquisitions. Development expenditures represented 64% 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 acquisitions or significant equity repurchases, management expects 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.



33



---

Hedging



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 December 31, 2004, the net unrealized pretax gains on these contracts totaled $952,000 ($590,000
gain net of $362,000 of deferred taxes) based on LIBOR futures prices at December 31, 2004.



The Company regularly enters into hedging agreements to reduce the impact on its operations of fluctuations in oil and gas prices. All such contracts are entered into solely to hedge prices and limit volatility. The
Companys current policy is to hedge between 50% and 75% of its production, when futures prices justify, on a rolling 12 to 24 month basis. At December 31, 2004, hedges were in place covering 68.5 Bcf at prices averaging $4.54 per MMBtu and 8.6
million barrels of oil averaging $25.57 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 $211.4 million ($131.1 million loss net
of $80.3 million of deferred taxes) at December 31, 2004. 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 $7.3 million, a current liability of
$151.5 million, and a non-current liability of $66.2 million based on contract expiration. Both the gas contracts and oil 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. A net realized pretax gain relating to these derivatives totaled $20.4 million in 2002, with net realized pretax losses of $50.4 million and $145.9 million in 2003
and 2004, respectively. Effective January 1, 2001, the unrealized gains (losses) on open hedging positions were recorded at an estimate of fair value which the Company based on a comparison of the contract price and a reference price, generally
NYMEX, CIG, ANR, PEPL or EPSJ on the Companys balance sheet in Accumulated other comprehensive income (loss), a component of Stockholders Equity.



34



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Inflation and Changes in Prices



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



The following table
indicates the average oil and gas prices received over the last five years and highlights the price fluctuations by quarter for 2003 and 2004. Average price computations exclude hedging gains and losses and other nonrecurring items to provide
comparability. Average prices per Mcfe indicate the composite impact of changes in oil and natural gas prices. Oil production is converted to natural gas equivalents at the rate of one barrel per six Mcf.



|          |  |                |  |            |  |              
|--------- |  | -------------- |  | ---------- |  | -------------
|          |  | Average Prices
|          |  | Oil            |  | NaturalGas |  | EquivalentMcf
|          |  | (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 |  |                |  |            |  |              
|          |  |                | 
|2003      |  |                |  |            |  |              
|First     |  | $33.33         |  | $4.26      |  | $4.69        
|Second    |  | 28.18          |  | 4.02       |  | 4.27         
|Third     |  | 29.40          |  | 4.27       |  | 4.49         
|Fourth    |  | 30.30          |  | 4.27       |  | 4.53         
|          |  |                | 
|2004      |  |                |  |            |  |              
|First     |  | $34.01         |  | $4.98      |  | $5.22        
|Second    |  | 37.15          |  | 5.16       |  | 5.51         
|Third     |  | 42.62          |  | 5.40       |  | 5.97         
|Fourth    |  | 46.88          |  | 6.09       |  | 6.67         



35



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Results of Operations



Comparison of 2004 to 2003. Revenues for 2004 totaled $561.0 million, a 38% increase from the prior year. Net income for 2004 totaled $151.0
million compared to $90.9 million in 2003. The increases in revenues and net income were due to higher oil and gas prices and production.



Average daily oil and gas production in 2004 totaled 18,049 barrels and 213.9 MMcf (322.2 MMcfe), an increase of 18% on an equivalent basis from 2003. The
rise in production was due to the continued development activity in Wattenberg, and the full year benefits of the Le Norman Partners and Cordillera acquisitions made in 2003. During 2004, the Company drilled or deepened 114 wells, performed 369
refracs, 32 trifracs and 56 recompletions in Wattenberg, compared to 80 new wells or deepenings, 433 refracs, 51 trifracs and 14 recompletions in Wattenberg in 2003. During 2004, the Company drilled or deepened 195 wells, performed three refracs and
25 recompletions on its Mid Continent properties, compared to 190 new drills or deepenings, eight refracs and 12 recompletions for 2003. During 2004, the Company drilled 12 wells, performed one refrac and nine recompletions on its San Juan
properties, compared to one new drill and three recompletions for 2003. During 2004, the Company drilled or deepened 73 wells and performed 68 recompletions on its Central and Other properties, compared to 79 new drills or deepenings and 91
recompletions for 2003. 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
years ended December 31, 2003 and 2004:



|                  |  |                   |  |                   |  |        |                     |         |  |         |  |        |   |  |         |  |         |  |        |  
|----------------- |  | ----------------- |  | ----------------- |  | ------ | ------------------- | ------- |  | ------- |  | ------ | - |  | ------- |  | ------- |  | ------ | -
|                  |  | Oil(Bbls per day) |  | Gas(Mcfs per day) |  |        | Total(Mcfe per day) |        
|                  |  | 2003              |  | 2004              |  | Change |                     | 2003    |  | 2004    |  | Change |   |  | 2003    |  | 2004    |  | Change |  
|Wattenberg        |  | 7,797             |  | 8,653             |  | 856    |                     | 144,423 |  | 143,942 |  | (481   | ) |  | 191,201 |  | 195,861 |  | 4,660  |  
|Mid Continent     |  | 4,067             |  | 5,253             |  | 1,186  |                     | 29,316  |  | 58,535  |  | 29,219 |   |  | 53,718  |  | 90,054  |  | 36,336 |  
|San Juan          |  | 15                |  | 55                |  | 40     |                     | 2,474   |  | 9,547   |  | 7,073  |   |  | 2,564   |  | 9,874   |  | 7,310  |  
|Central and Other |  | 3,841             |  | 4,088             |  | 247    |                     | 3,431   |  | 1,882   |  | (1,549 | ) |  | 26,477  |  | 26,410  |  | (67    | )
|                  |  |                   |  |                   |  |        |                     |         |  |         |  |        |   |  |         |  |         |  |        |  
|Total             |  | 15,720            |  | 18,049            |  | 2,329  |                     | 179,644 |  | 213,906 |  | 34,262 |   |  | 273,960 |  | 322,199 |  | 48,239 |  
|                  |  |                   |  |                   |  |        |                     |         |  |         |  |        |   |  |         |  |         |  |        |  



Average realized oil
prices increased 4% from $25.80 per barrel in 2003 to $26.96 in 2004. Average realized gas prices increased 23% from $3.82 per Mcf in 2003 to $4.68 in 2004. Average oil prices include hedging losses of $25.1 million or $4.37 per barrel and $88.0
million or $13.32 per barrel in 2003 and 2004, respectively. Average gas prices included hedging losses of $25.3 million or $0.39 per Mcf in 2003 and hedging losses of $57.9 million or $0.74 per Mcf in 2004. The following table sets forth summary
information with respect to oil and natural gas prices for the years ended December 31, 2003 and 2004.



|                  |  |           |       |   |          |   |        |             |  |   |       |   |  |      |       |   |        |   |       |      |  |   |       |   |  |        |       |   |  |   |       |   |  |   |       |  
|----------------- |  | --------- | ----- | - | -------- | - | ------ | ----------- |  | - | ----- | - |  | ---- | ----- | - | ------ | - | ----- | ---- |  | - | ----- | - |  | ------ | ----- | - |  | - | ----- | - |  | - | ----- | -
|                  |  | Oil$/Bbls |       |   | Gas$/Mcf |   |        | Total$/Mcfe | 
|                  |  | 2003      |       |   | 2004     |   |        | Change      |  |   | 2003  |   |  | 2004 |       |   | Change |   |       | 2003 |  |   | 2004  |   |  | Change |      
|Wattenberg        |  | $         | 31.42 |   |          | $ | 41.28  |             |  | $ | 9.86  |   |  | $    | 4.02  |   |        | $ | 5.23  |      |  | $ | 1.21  |   |  | $      | 4.32  |   |  | $ | 5.67  |   |  | $ | 1.35  |  
|Mid Continent     |  |           | 28.28 |   |          |   | 39.05  |             |  |   | 10.77 |   |  |      | 5.12  |   |        |   | 5.82  |      |  |   | 0.70  |   |  |        | 4.94  |   |  |   | 6.06  |   |  |   | 1.12  |  
|San Juan          |  |           | 25.11 |   |          |   | 37.80  |             |  |   | 12.69 |   |  |      | 4.16  |   |        |   | 6.08  |      |  |   | 1.92  |   |  |        | 4.17  |   |  |   | 6.09  |   |  |   | 1.92  |  
|Central and Other |  |           | 29.66 |   |          |   | 39.79  |             |  |   | 10.13 |   |  |      | 4.23  |   |        |   | 4.90  |      |  |   | 0.67  |   |  |        | 4.85  |   |  |   | 6.51  |   |  |   | 1.66  |  
|                  |  |           |       |   |          |   |        |             |  |   |       |   |  |      |       |   |        |   |       |      |  |   |       |   |  |        |       |   |  |   |       |   |  |   |       |  
|Subtotal          |  |           | 30.17 |   |          |   | 40.28  |             |  |   | 10.11 |   |  |      | 4.21  |   |        |   | 5.42  |      |  |   | 1.21  |   |  |        | 4.49  |   |  |   | 5.86  |   |  |   | 1.37  |  
|Hedging           |  |           | (4.37 | ) |          |   | (13.32 | )           |  |   | (8.95 | ) |  |      | (0.39 | ) |        |   | (0.74 | )    |  |   | (0.35 | ) |  |        | (0.50 | ) |  |   | (1.24 | ) |  |   | (0.74 | )
|                  |  |           |       |   |          |   |        |             |  |   |       |   |  |      |       |   |        |   |       |      |  |   |       |   |  |        |       |   |  |   |       |   |  |   |       |  
|Total             |  | $         | 25.80 |   |          | $ | 26.96  |             |  | $ | 1.16  |   |  | $    | 3.82  |   |        | $ | 4.68  |      |  | $ | 0.86  |   |  | $      | 3.99  |   |  | $ | 4.62  |   |  | $ | 0.63  |  
|                  |  |           |       |   |          |   |        |             |  |   |       |   |  |      |       |   |        |   |       |      |  |   |       |   |  |        |       |   |  |   |       |   |  |   |       |  



Gain on sale of oil
and gas properties in 2004 totaled $7.9 million, primarily related to the sale of Adams Baggett properties in West Texas for $15.2 million.



Lease operating expenses totaled $71.6 million or $0.61 per Mcfe for 2004 compared to $54.1 million or $0.54 per Mcfe in the prior year. The increase in
operating expenses was primarily attributed to additional operating expenses incurred as a result of the 18% increase in production and a general rise in operating costs. Production taxes totaled $46.0 million or $0.39 per Mcfe in 2004 compared to
$28.7 million or $0.29 per Mcfe in 2003. The $17.3 million increase was a result of higher oil and gas prices and production.



36



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General and administrative expenses in 2004 totaled $26.4 million, an increase of $7.4 million or 39%
from 2003. The increase was largely attributed to additional employees hired in conjunction with the prior year acquisitions.



Interest expense increased to $12.6 million in 2004, an increase of 42% from the prior year. Interest expense increased as a result of higher average debt
balances in conjunction with the acquisitions made in late 2003, and slightly higher average interest rates. The Companys average interest rate in 2004 was 2.9% compared to 2.7% in 2003.



Deferred compensation adjustment totaled $31.7 million in 2004, a decrease of
$1.4 million from the prior year. The decrease was due to fewer average shares held in the deferred compensation plan, partially offset by a larger increase in value of the Companys Common Stock and other investments held in the plan compared
to 2003. The Companys Common Stock price appreciated by 53% or $13.00 per share in 2004 versus an increase of 93% or $11.84 per share in 2003.



Depletion, depreciation and amortization expense for 2004 totaled $126.8 million, an increase of $28.7 million or 29% from 2003. Depletion expense totaled
$122.5 million or $1.04 per Mcfe for 2004 compared to $94.1 million or $0.94 per Mcfe for 2003. The increase in depletion expense resulted from the 18% increase in oil and gas production in 2004 and a higher depletion rate. The depletion rate was
increased in the fourth quarter of 2004 in conjunction with the completion of the year-end 2004 reserve report. Depreciation and amortization expense for 2004 totaled $2.8 million or $0.02 per Mcfe compared to $2.7 million or $0.03 per Mcfe in 2003.
Accretion expense related to the adoption of SFAS No. 143 totaled $1.5 million in 2004 compared to $1.3 million in 2003.



Provision for income taxes for 2004 totaled $92.5 million, an increase of $35.2 million from the same period in 2003. The increase was due to higher
earnings. The Company recorded a 38% tax provision for 2003 and 2004, respectively. The Company expects to record a 37% provision for income taxes in 2005.



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



Comparison of 2003 to 2002. Revenues for 2003
totaled $406.7 million, an 83% increase from the prior year. Net income for 2003 totaled $90.9 million compared to $57.7 million in 2002. The increases in revenues and net income were due to higher oil and gas prices and production.



Average daily oil and gas production in 2003 totaled 15,720 barrels and 179.6
MMcf (274.0 MMcfe), an increase of 44% on an equivalent basis from 2002. The rise in production was due to the continued development activity in Wattenberg, the benefits of the Le Norman and Bravo acquisitions made in late 2002, and the Elysium,
LNP, and Cordillera acquisitions made in 2003, respectively. During 2003, the Company drilled or deepened 80 wells, performed 433 refracs, 51 trifracs and 14 recompletions in Wattenberg, compared to 66 new wells or deepenings and 447 refracs and 11
recompletions in Wattenberg in 2002. During the 2003, the Company drilled or deepened 190 wells and performed eight refracs and 12 recompletions on its Mid Continent properties, compared to 33 new drills or deepenings and no recompletions for 2002.
The following table sets forth summary information with respect to oil and natural gas production for the years ended December 31, 2002 and 2003:



|                  |  |                   |  |                   |  |                     |  |         |  |         |  |        |  |         |  |         |  |       
|----------------- |  | ----------------- |  | ----------------- |  | ------------------- |  | ------- |  | ------- |  | ------ |  | ------- |  | ------- |  | ------
|                  |  | Oil(Bbls per day) |  | Gas(Mcfs per day) |  | Total(Mcfe per day)
|                  |  | 2002              |  | 2003              |  | Change              |  | 2002    |  | 2003    |  | Change |  | 2002    |  | 2003    |  | Change
|Wattenberg        |  | 6,405             |  | 7,797             |  | 1,392               |  | 132,177 |  | 144,423 |  | 12,246 |  | 170,602 |  | 191,201 |  | 20,599
|Mid Continent     |  | 365               |  | 4,067             |  | 3,702               |  | 1,844   |  | 29,316  |  | 27,472 |  | 4,029   |  | 53,718  |  | 49,689
|San Juan          |  |                  |  | 15                |  | 15                  |  |        |  | 2,474   |  | 2,474  |  |        |  | 2,564   |  | 2,564 
|Central and Other |  | 2,195             |  | 3,841             |  | 1,646               |  | 2,355   |  | 3,431   |  | 1,076  |  | 15,535  |  | 26,477  |  | 10,942
|                  |  |                   |  |                   |  |                     |  |         |  |         |  |        |  |         |  |         |  |       
|Total             |  | 8,965             |  | 15,720            |  | 6,755               |  | 136,376 |  | 179,644 |  | 43,268 |  | 190,166 |  | 273,960 |  | 83,794
|                  |  |                   |  |                   |  |                     |  |         |  |         |  |        |  |         |  |         |  |       



37



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Average realized oil prices increased 5% from $24.52 per barrel in 2002 to $25.80 in 2003. Average
realized gas prices increased 40% from $2.72 per Mcf in 2002 to $3.82 in 2003. Average oil prices include hedging losses of $3.9 million or $1.19 per barrel and $25.1 million or $4.37 per barrel in 2002 and 2003, respectively. Average gas prices
included hedging gains of $24.3 million or $0.49 per Mcf in 2002 and hedging losses of $25.3 million or $0.39 per Mcf in 2003. The following table sets forth summary information with respect to oil and natural gas prices for the years ended December
31, 2002 and 2003:



|                  |  |           |       |   |          |   |       |             |  |   |       |   |      |   |      |        |   |       |      |  |      |       |   |        |   |      |  |   |       |   |  |   |       |  
|----------------- |  | --------- | ----- | - | -------- | - | ----- | ----------- |  | - | ----- | - | ---- | - | ---- | ------ | - | ----- | ---- |  | ---- | ----- | - | ------ | - | ---- |  | - | ----- | - |  | - | ----- | -
|                  |  | Oil$/Bbls |       |   | Gas$/Mcf |   |       | Total$/Mcfe | 
|                  |  | 2002      |       |   | 2003     |   |       | Change      |  |   | 2002  |   | 2003 |   |      | Change |   |       | 2002 |  | 2003 |       |   | Change |  
|Wattenberg        |  | $         | 26.29 |   |          | $ | 31.42 |             |  | $ | 5.13  |   |      | $ | 2.20 |        | $ | 4.02  |      |  | $    | 1.82  |   |        | $ | 2.69 |  | $ | 4.32  |   |  | $ | 1.63  |  
|Mid Continent     |  |           | 26.12 |   |          |   | 28.28 |             |  |   | 2.16  |   |      |   | 4.12 |        |   | 5.12  |      |  |      | 1.00  |   |        |   | 4.25 |  |   | 4.94  |   |  |   | 0.69  |  
|San Juan          |  |           |      |   |          |   | 25.11 |             |  |   | 25.11 |   |      |   |     |        |   | 4.16  |      |  |      | 4.16  |   |        |   |     |  |   | 4.17  |   |  |   | 4.17  |  
|Central and Other |  |           | 23.95 |   |          |   | 29.66 |             |  |   | 5.71  |   |      |   | 2.48 |        |   | 4.23  |      |  |      | 1.75  |   |        |   | 3.76 |  |   | 4.85  |   |  |   | 1.09  |  
|                  |  |           |       |   |          |   |       |             |  |   |       |   |      |   |      |        |   |       |      |  |      |       |   |        |   |      |  |   |       |   |  |   |       |  
|Subtotal          |  |           | 25.71 |   |          |   | 30.17 |             |  |   | 4.46  |   |      |   | 2.23 |        |   | 4.21  |      |  |      | 1.98  |   |        |   | 2.81 |  |   | 4.49  |   |  |   | 1.68  |  
|Hedging           |  |           | (1.19 | ) |          |   | (4.37 | )           |  |   | (3.18 | ) |      |   | 0.49 |        |   | (0.39 | )    |  |      | (0.88 | ) |        |   | 0.29 |  |   | (0.50 | ) |  |   | (0.79 | )
|                  |  |           |       |   |          |   |       |             |  |   |       |   |      |   |      |        |   |       |      |  |      |       |   |        |   |      |  |   |       |   |  |   |       |  
|Total             |  | $         | 24.52 |   |          | $ | 25.80 |             |  | $ | 1.28  |   |      | $ | 2.72 |        | $ | 3.82  |      |  | $    | 1.10  |   |        | $ | 3.10 |  | $ | 3.99  |   |  | $ | 0.89  |  
|                  |  |           |       |   |          |   |       |             |  |   |       |   |      |   |      |        |   |       |      |  |      |       |   |        |   |      |  |   |       |   |  |   |       |  



Lease operating
expenses totaled $54.1 million or $0.54 per Mcfe for 2003 compared to $28.0 million or $0.40 per Mcfe in the prior year. The increase in operating expenses was primarily attributed to additional operating expenses incurred as a result of increasing
oil production associated with the recent acquisitions. Production taxes totaled $28.7 million or $0.29 per Mcfe in 2003 compared to $11.8 million or $0.17 per Mcfe in 2002. The $16.9 million increase was a result of higher oil and gas prices and
production.



General and administrative expenses in 2003
totaled $19.0 million, an increase of $6.3 million or 50% from 2002. The increase was largely attributed to additional employees hired in conjunction with the recent acquisitions.



Interest expense increased to $8.8 million in 2003, an increase of 284% from the prior year. Interest expense increased as a
result of higher average debt balances in conjunction with the acquisitions made in late 2002 and early 2003, somewhat offset by lower average interest rates. The Companys average interest rate in 2003 was 2.7% compared to 2.9% in 2002.



Loss on sale of oil and gas properties for 2003 totaled $7.2
million and related to the sale of the Companys non-operated interests in a coalbed methane project in Utah.



Deferred compensation adjustment totaled $33.1 million in 2003, an increase of $23.1 million from the prior year. The increase relates to the increase in
value of the Companys Common Stock and other investments held in a deferred compensation plan over 2002. The Companys Common Stock price appreciated by 93% or $11.84 per share in 2003 versus an increase of 44% or $3.86 per share in 2002.



Depletion, depreciation and amortization expense for 2003
totaled $98.1 million, an increase of $32.0 million or 48% from 2002. Depletion expense totaled $94.1 million or $0.94 per Mcfe for 2003 compared to $64.7 million or $0.93 per Mcfe for 2002. The increase in depletion expense resulted from the 44%
increase in oil and gas production in 2003. Depreciation and amortization expense for 2003 totaled $2.7 million or $0.03 per Mcfe compared to $1.4 million or $0.02 per Mcfe in 2002. Accretion expense related to the adoption of SFAS No. 143 totaled
$1.3 million in 2003 compared to zero in 2002, as the statement was not effective until January 1, 2003.



Provision for income taxes for 2003 totaled $57.3 million, an increase of $26.1 million from the same period in 2002. The increase was due to higher
earnings and an increase in the effective tax rate. The Company recorded a 38% tax provision for 2003 compared to a 35% tax provision in 2002. The increase in the effective tax rate was due to the expiration of Section 29 tax credits on December 31,
2002.



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



38



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Recent Accounting Pronouncements



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



In November 2002, the FASB
issued Interpretation No. 45 (FIN 45), Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN 45 requires a guarantor to recognize a liability for the fair
value of the obligation it assumes under certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure
under the guarantee, the current carrying amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are
effective for financial statements for both interim and annual periods ending after December 15, 2002. The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002.
The adoption of this Statement did not have a material impact on the Companys financial position or results of operations.



In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation  Transition and Disclosure  an amendment of SFAS
No. 123. SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure
requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. SFAS No. 148 was
effective for the Companys year ended December 31, 2002 and for interim financial statements commencing in 2003. The adoption of this pronouncement did not have an impact on the Companys financial condition or results of operations.



In April 2003, the FASB issued SFAS No. 149, Amendment
of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for
hedging activities under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003 and for hedging relationships
designated after June 30, 2003. The adoption of this pronouncement did not have an impact on the Companys financial condition or results of operations.



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



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 the third quarter of 2005. 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,



39



---

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 2004, 2003, and 2002 were $10.7 million, $10.6 million, and $3.5 million, respectively.



40



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|ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|-------- | ----------------------------------------------------------



Commodity Price Risk



The Companys major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the
prevailing domestic price for oil and spot prices applicable to the Rocky Mountain and Mid Continent regions for its natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable. Pricing
volatility is expected to continue. Natural gas price realizations during 2004, 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 $51.56 per barrel during 2004. A significant decline in prices of oil or natural gas could have a material adverse effect on the Companys financial condition and results of operations.



In 2004, a 10% reduction in oil and gas prices, excluding oil and gas
quantities that were fixed through hedging transactions, would have reduced revenues by $17.1 million. If oil and gas future prices at December 31, 2004 had declined by 10%, the net unrealized hedging losses at that date would have decreased by
$74.3 million (from $211.4 million to $137.1 million).



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, recognizing losses of $3.9 million, $25.1 million, and $88.0 million in
2002, 2003 and 2004, 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, recognizing a gain of $24.3 million in 2002, and losses of $25.3 million and $57.9 million in 2003 and 2004, respectively, related to these contracts.



At December 31, 2004, the Company was a party to swap contracts for oil based
on NYMEX prices covering approximately 13,700 barrels of oil per day for 2005 at fixed prices ranging from $23.51 to $26.95 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts
is $24.78 per barrel for 2005. The Company also entered into swap contracts for oil for 2006 as of December 31, 2004, which are summarized in the table below. The net unrealized losses on these contracts totaled $139.0 million based on NYMEX futures
prices at December 31, 2004.



At December 31, 2004, the Company
was a party to swap contracts for natural gas based on CIG, EPSJ, ANR and PEPL index prices covering approximately 132,400 MMBtus per day for 2005 at fixed prices ranging from $2.83 to $8.07 per MMBtu. The overall weighted average hedged price
for the swap contracts is $4.44 per MMBtu for 2005. The Company also entered into natural gas swap contracts for 2006 as of December 31, 2004, which are summarized in the table below. The net unrealized losses on these contracts totaled $72.4
million based on futures prices at December 31, 2004.



41



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At December 31, 2004, the Company was a party to the fixed price swaps summarized below:



|                    |  |                                      |  |         |                                |                                     |         |   |                  |        |         |      |                                    |   |         |  
|------------------- |  | ------------------------------------ |  | ------- | ------------------------------ | ----------------------------------- | ------- | - | ---------------- | ------ | ------- | ---- | ---------------------------------- | - | ------- | -
|                    |  | Oil Swaps (NYMEX)                    |  |         | Natural Gas Swaps (CIG Index)  |                                    
|Time Period         |  | DailyVolumeBbl                       |  | $/Bbl   |                                | UnrealizedGain (Loss)($/thousands)  |         |   | DailyVolumeMMBtu |        | $/MMBtu |      | UnrealizedGain (Loss)($/thousands) |  
|01/01/05 - 03/31/05 |  | 13,700                               |  | 25.07   |                                | $                                   | (22,720 | ) |                  | 90,000 |         | 4.85 |                                    | $ | (5,242  | )
|04/01/05 - 06/30/05 |  | 13,700                               |  | 24.80   |                                |                                     | (22,636 | ) |                  | 80,000 |         | 3.83 |                                    |   | (10,612 | )
|07/01/05 - 09/30/05 |  | 13,700                               |  | 24.67   |                                |                                     | (22,195 | ) |                  | 80,700 |         | 3.84 |                                    |   | (12,393 | )
|10/01/05 - 12/31/05 |  | 13,700                               |  | 24.60   |                                |                                     | (21,527 | ) |                  | 80,700 |         | 4.13 |                                    |   | (12,428 | )
|                    |  |                                      |  |         |                                |                                    
|2006                |  | 9,900                                |  | 26.66   |                                |                                     | (49,912 | ) |                  | 35,000 |         | 4.67 |                                    |   | (10,526 | )
|                    |  |                                     
|                    |  | Natural Gas Swaps (ANR/PEPL Indexes) |  |         | Natural Gas Swaps (EPSJ Index) |                                    
|Time Period         |  | DailyVolumeMMBtu                     |  | $/MMBtu |                                | UnrealizedGain (Loss) ($/thousands) |         |   | DailyVolumeMMBtu |        | $/MMBtu |      | UnrealizedGain (Loss)($/thousands) |  
|01/01/05 - 03/31/05 |  | 48,100                               |  | 5.88    |                                | $                                   | 865     |   |                  | 9,050  |         | 4.71 |                                    | $ | (613    | )
|04/01/05 - 06/30/05 |  | 38,100                               |  | 4.63    |                                |                                     | (3,379  | ) |                  | 9,050  |         | 3.97 |                                    |   | (1,098  | )
|07/01/05 - 09/30/05 |  | 38,100                               |  | 4.58    |                                |                                     | (4,015  | ) |                  | 9,050  |         | 3.99 |                                    |   | (1,298  | )
|10/01/05 - 12/31/05 |  | 38,100                               |  | 4.77    |                                |                                     | (4,571  | ) |                  | 9,050  |         | 4.22 |                                    |   | (1,345  | )
|                    |  |                                      |  |         |                                |                                    
|2006                |  | 16,700                               |  | 5.02    |                                |                                     | (4,508  | ) |                  | 3,650  |         | 4.61 |                                    |   | (1,220  | )



The Company is
required to provide margin deposits to its counterparties when the unrealized losses on its oil and gas hedges exceed the credit thresholds established by its counterparties. At December 31, 2003 and 2004, the Company had $9.9 million and $11.9
million, respectively, on deposit with its counterparties. These amounts are included in Inventory and other in the accompanying consolidated balance sheets.



Basis Differentials



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 averaged $1.25 per MMBtu discount from NYMEX in 2002, ranging from
a discount of $0.30 per MMBtu in January 2002 to a discount of $2.49 per MMBtu in October 2002. The CIG basis differential for 2003 averaged $1.35 per MMBtu discount from NYMEX, ranging from a discount of $0.42 per MMBtu in December 2003 to a
discount of $4.12 per MMBtu in March 2003. 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
futures prices as of December 31, 2004, the CIG basis differential for 2005 averaged a $0.74 per MMBtu discount, ranging from a discount of $0.62 per MMBtu in January 2005 to a discount of $0.83 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.



Interest Rate Risk



At December 31, 2004, the Company had $297.0 million outstanding under its
credit facility with an average interest rate of 3.6%. The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) LIBOR for one, two, three or six months plus a margin which fluctuates from 1.25% to
1.90% or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.65%. The weighted average interest rate under the facility approximated 2.9% during 2004. Assuming no change in the amount outstanding at December 31, 2004, the annual
impact on interest expense of a ten percent change in the average interest rate would be approximately $528,000, net of tax. As the interest rate is variable and is reflective of current market conditions, the carrying value approximates the fair
value.



42



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|ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|------- | -------------------------------------------



Reference is made to the Index to Consolidated Financial Statements on page F-1 for a listing of the Companys financial statements and notes thereto
and for the financial statement schedules contained herein.



Management
Responsibility for Financial Statements



The financial
statements have been prepared by management in conformity with generally accepted accounting principles. Management is responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the
preparation of the financial statements, it is necessary to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.



The Company maintains accounting and other controls which management believes
provide reasonable assurance that financial records are reliable, assets are safeguarded and transactions are properly recorded. However, limitations exist in any system of internal control based upon the recognition that the cost of the system
should not exceed benefits derived.



|ITEM 9. | CHANGE IN ACCOUNTANTS AND DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
|------- | ------------------------------------------------------------------------------



None.



|ITEM 9A. | CONTROLS AND PROCEDURES
|-------- | -----------------------



Disclosure Controls and Procedures



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 Annual Report on Form 10-K. 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.



Internal Control over Financial Reporting



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.



43



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Managements Annual Report on Internal Control over Financial Reporting



The management of the Company is responsible for establishing and
maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended. The Companys internal control system is designed to provide reasonable assurance to the
Companys management and board of directors regarding the preparation and fair presentation of published financial statements.



All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide
only reasonable assurance with respect to financial statement preparation and presentation.



The Companys management assessed the effectiveness of the Companys internal control over financial reporting as of December 31, 2004. In making this assessment, it used the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control Integrated Framework. Based on our assessment we believe that, as of December 31, 2004, the Companys internal control over financial reporting
is effective based on those criteria.



Deloitte & Touche
LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued a report on managements assessment of the effectiveness of the
Companys internal control over financial reporting as of December 31, 2004. The report, which expresses an unqualified opinion on managements assessment and on the effectiveness of the Companys internal control over financial
reporting as of December 31, 2004, is included below in this Item under the heading Report of Independent Registered Public Accounting Firm.



Report of Independent Registered Public Accounting Firm



To the Board of Directors and Stockholders of

Patina Oil & Gas
Corporation

Denver, Colorado



We have audited managements assessment, included in the accompanying Managements Annual Report on Internal Control Over Financial Reporting,
that Patina Oil & Gas Corporation and subsidiaries (the Company) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal ControlIntegrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Companys management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on managements assessment and an opinion on the effectiveness of the Companys internal control over financial reporting based on our
audit.



We conducted our audit in accordance with the standards
of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating managements assessment, testing and evaluating the design and operating effectiveness of internal control, and performing
such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.



A companys internal control over financial reporting is a process designed by, or under the supervision of, the companys principal executive
and principal financial officers, or persons performing similar functions, and effected by the companys board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with



44



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generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial
statements.



Because of the inherent limitations of internal
control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies
or procedures may deteriorate.



In our opinion,
managements assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2004, based on the criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.



We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated financial statements as of and for the year ended December 31, 2004 of the Company and our report dated February 23, 2005 expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding the
Companys adoption of Statement of Financial Accounting Standards No. 143 in 2003.



/s/ DELOITTE & TOUCHE LLP



Denver, Colorado

February 23, 2005



|ITEM 9B. | OTHER INFORMATION
|-------- | -----------------



None.



45



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PART III



|ITEM 10. | DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
|-------- | -----------------------------------------------



The directors and officers are listed below with a description of their experience and certain other information. Each director was elected for a one-year
term at the Companys 2004 annual stockholders meeting of stockholders. Officers are appointed by the Board of Directors.



Directors and Executive Officers



The following table sets forth certain information about the officers and directors of the Company:



|                         |  |     |  |                                                                       
|------------------------ |  | --- |  | ----------------------------------------------------------------------
|Name                     |  | Age |  | Position                                                              
|Thomas J. Edelman        |  | 54  |  | Chairman, Chief Executive Officer, President and Chairman of the Board
|David J. Kornder         |  | 44  |  | Executive Vice President, Chief Financial Officer and Director        
|Andrew M. Ashby          |  | 49  |  | Senior Vice President  Operations                                    
|Ted D. Brown             |  | 49  |  | Senior Vice President  Operations                                    
|Barton R. Brookman       |  | 42  |  | Vice President                                                        
|Marianne N. Hallinan     |  | 32  |  | Vice President                                                        
|James A. Lillo           |  | 50  |  | Vice President                                                        
|Scott R. Reasoner        |  | 44  |  | Vice President                                                        
|Terry L. Ruby            |  | 46  |  | Vice President                                                        
|Donald R. Shaw           |  | 46  |  | Vice President                                                        
|David W. Siple           |  | 45  |  | Vice President                                                        
|Michael N. Stefanoudakis |  | 33  |  | Vice President and General Counsel                                    
|Michael J. Wendling      |  | 50  |  | Vice President                                                        
|Charles E. Bayless       |  | 62  |  | Director                                                              
|Jeffrey L. Berenson      |  | 54  |  | Director                                                              
|Robert J. Clark          |  | 60  |  | Director                                                              
|Elizabeth K. Lanier      |  | 53  |  | Director                                                              
|Alexander P. Lynch       |  | 52  |  | Director                                                              
|Paul M. Rady             |  | 51  |  | Director                                                              
|Jon R. Whitney           |  | 60  |  | Director                                                              



Thomas J.
Edelman founded the Company and has served as Chairman of the Board, Chairman and Chief Executive Officer since its formation. Mr. Edelman was appointed President in December 2004. He co-founded SOCO and was its President from 1981 through early
1997. From 1980 to 1981, he was with The First Boston Corporation and from 1975 through 1980, with Lehman Brothers Kuhn Loeb Incorporated. Mr. Edelman received his Bachelor of Arts Degree from Princeton University and his Masters Degree in Finance
from Harvard Universitys Graduate School of Business Administration. Mr. Edelman serves as Chairman of Bear Cub Investments LLC.



David J. Kornder was appointed a director in February 2005 and has served as Executive Vice President and Chief Financial Officer since 1996. Prior
to that time, he served as Vice PresidentFinance of Gerrity Oil & Gas Corporation (Gerrity) beginning in early 1993. From 1989 through 1992, Mr. Kornder was an Assistant Vice President of Gillett Group Management, Inc. Prior to
that, Mr. Kornder was an accountant with the independent accounting firm of Deloitte & Touche LLP for five years. Mr. Kornder received his Bachelor of Arts Degree in Accounting from Montana State University. Mr. Kornder serves as a Director of
the Colorado Oil & Gas Association.



46



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Andrew M. Ashby has served as Senior Vice President since November 2001. From 2000 to 2001, Mr.
Ashby served as Executive Vice President and Chief Operating officer for Omega Oil Company. From 1997 to 2000, Mr. Ashby served as the Vice President of Operations for Westport Oil and Gas, a public independent oil company. From 1989 to 1997, Mr.
Ashby worked as a drilling consultant on various international oil projects. Prior to that, Mr. Ashby worked for Amoco Production Company as a petroleum engineer and an exploration geologist. Mr. Ashby received his Bachelor of Science Degree in
Geological Engineering from the Colorado School of Mines.



Ted D. Brownhas served as Senior Vice President since joining the Company in July 2004. From 1993 to 2004, Mr. Brown was a Director of the Piceance Basin Project and Engineering Manager for Barrett Resources Corporation until it was
acquired by Williams Production Company in August 2001. From 1985 to 1993, Mr. Brown worked in various engineering and business development capacities at Union Pacific Resources Corporation. Prior to that, Mr. Brown was employed by Amoco Production
Company as a petroleum engineer. Mr. Brown received his Bachelor of Science Degree in Mechanical Engineering from the University of Wyoming.



Barton R. Brookman has served as a Vice President since January 2001. From 1996 to 2000, Mr. Brookman was the District Operations Manager for the
Company. From 1988 to 1996, Mr. Brookman was a District Operations Manager for SOCO. From 1986 to 1988, Mr. Brookman was a petroleum engineer for Ladd Petroleum Corporation, an affiliate of General Electric. Mr. Brookman received his Bachelor of
Science Degree in Petroleum Engineering from the Colorado School of Mines and his Master of Science  Finance Degree from the University of Colorado, Denver.



Marianne N. Hallinan has served as Vice President Human Resources and Associate General Counsel since joining the
Company in May 2004. From 2002 to 2004, Ms. Hallinan was an associate with Hogan & Hartson L.L.P., from 2000 to 2001, Ms. Hallinan was an associate with Cooley Godward LLP, and from 1999 to 2000 she was an associate with Skadden, Arps, Slate,
Meagher & Flom LLP. During her legal career, Ms. Hallinan has focused on employment litigation and counseling and benefits law. Ms. Hallinan received Bachelor of Arts Degrees in Psychology and Sociology from the University of Nebraska-Lincoln, a
Masters in Social Psychology from the University of Michigan and a Juris Doctor from the University of Michigan. Ms. Hallinan is a member of the Colorado Bar.



James A. Lillo has served as a Vice President since 1998. From 1995 to 1998, Mr. Lillo was President of James Engineering, Inc., an independent
petroleum engineering consulting firm. Previously, he served as Vice President of Engineering for Consolidated Oil & Gas, Inc., until its merger into Hugoton Energy Corporation, and President of a predecessor operating company since 1989. Prior
to 1989, Mr. Lillo worked as an engineering consultant and as Manager of Reservoir Engineering for Hart Exploration and in various engineering capacities with Champlin Petroleum Company and Shell Oil Company. Mr. Lillo received his Bachelor of
Science Degree in Chemical and Petroleum Refining Engineering from the Colorado School of Mines and is a Registered Professional Engineer.



Terry L. Ruby has served as a Vice President since 1996. Prior to that time, Mr. Ruby served as a senior landman of Gerrity beginning in 1992 and
was appointed Vice PresidentLand in 1995. From 1990 to 1992, Mr. Ruby worked for Apache Corporation and from 1982 to 1990, he was employed by Baker Exploration Company. Mr. Ruby received his Bachelor of Science Degree in Minerals Land
Management from the University of Colorado and his M.B.A. from the University of Denver.



Donald R. Shaw has served as a Vice President  Asset Development since December 2003. From 1996 to 2002, he has served the Company in various engineering capacities. From 2002 to 2003, he served the
Company as Asset Development Manager. From 1988 to 1996, he served in various engineering capacities, including Asset Development Manager and DJ Basin Team Leader for SOCO. Prior to that, he worked for several independent consulting firms. Mr. Shaw
received his Bachelor of Science Degree in Geological Engineering from the Colorado School of Mines.



David W. Siple has served as a Vice President since 1996. He joined SOCOs land department in 1994 and was appointed a Land Manager in 1995.
From 1990 through May 1994, Mr. Siple was the Land Manager of Gerrity. From 1981 through 1989, Mr. Siple was employed by PanCanadian Petroleum Company in the Land Department. Mr. Siple received his Bachelor of Science Degree in Minerals Land
Management from the University of Colorado.



47



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Michael N. Stefanoudakis has served as Vice President and General Counsel since joining the
Company in April 2004. From 2003 to 2004, Mr. Stefanoudakis was an associate with Hogan & Hartson L.L.P., focusing on corporate and securities matters, and was a member of the firms Corporate, Securities and Finance Group. From 2000 to
2003, Mr. Stefanoudakis was an associate with Brobeck, Phleger & Harrison LLP, and from 1996 to 2000 he was an associate with Davis, Graham & Stubbs LLP. Mr. Stefanoudakis received a Bachelor of Arts Degree in Economics from the University
of San Diego and a Juris Doctor from Harvard University. Mr. Stefanoudakis is a member of the Colorado Bar.



Michael J. Wendling has served as a Vice President since March 2004. He served as Manager, Reservoir Engineering for the Company from 1997 to 2004.
From 1993 to 1997, he was President of Wendling & Associates, an oil and gas prospect origination and consulting firm. From 1991 to 1993, Mr. Wendling managed Chuska Energys reserves. From 1978 to 1991, he worked for Ladd Petroleum
Corporation, a subsidiary of General Electric, primarily as Manager, Reservoir Engineering. Mr. Wendling began his career in 1976 as a Production Engineer for Conoco. He received a Bachelor of Science Degree in Chemical Engineering from the South
Dakota School of Mines & Technology.



Charles E.
Bayless has served as a Director since March 2004. From 2000 to 2004, Mr. Bayless has worked on various start-up business ventures. From 1998 until late 1999, Mr. Bayless served as Chairman and Chief Executive Officer of Illinova Corporation, an
electric utility merged into Dynegy, Inc. From 1989 to 1998, Mr. Bayless served as Chief Financial Officer, becoming President one year later for Tucson Electric Power Company. From 1981 until 1989, Mr. Bayless served as Senior Vice President and
Chief Financial Officer of Public Service Company of New Hampshire. Mr. Bayless also currently serves as a Director of Dynegy. Mr. Bayless received a Bachelor of Arts Degree from West Virginia Institute of Technology, a Masters of Business
Administration from the University of Michigan and a Juris Doctor and Masters in electrical engineering from West Virginia University.



Jeffrey L. Berenson has served as a Director since December 2002. Mr. Berenson is President and Chief Executive Officer of Berenson & Company,
a private investment banking firm in New York City that he co-founded in 1990. From 1978 until founding Berenson & Company, Mr. Berenson was with Merrill Lynchs Mergers and Acquisitions department and was head of Merrill Lynchs
Mergers and Acquisitions department and co-head of its Merchant Banking unit from 1986. Mr. Berenson serves as a member of the National Council of Environmental Defense and is also a member of the International Conservation Committee of the Wildlife
Conservation Society. Mr. Berenson received his Bachelor of Arts Degree from Princeton University.



Robert J. Clark has served as a Director since 1996. Mr. Clark has served as the President of Bear Cub Investments LLC, a private gas gathering and
processing company, since 2001. In 1995, Mr. Clark formed a predecessor company, Bear Paw Energy LLC, which was sold in early 2001. From 1988 to 1995, he was President of SOCO Gas Systems, Inc. and Vice PresidentGas Management for SOCO. Mr.
Clark was Vice President Gas Gathering, Processing and Marketing of Ladd Petroleum Corporation, an affiliate of General Electric from 1985 to 1988. Prior to 1985, Mr. Clark held various management positions with NICOR, Inc. and its affiliate NICOR
Exploration, Northern Illinois Gas and Reliance Pipeline Company. Mr. Clark received his Bachelor of Science Degree from Bradley University and his M.B.A. from Northern Illinois University.



Elizabeth K. Lanier has served as a Director since 1998. Ms. Lanier
has been an Executive Vice President  Corporate Affairs, General Counsel and Corporate Secretary for US Airways Group, Inc. since April 2003. From April 2002 through December 2002, Ms. Lanier served as Senior Vice President, General Counsel of
Trizec Properties, Inc., a public real estate investment trust. Ms. Lanier served as Vice President and General Counsel of General Electric Power Systems from 1998 until March 2002. From 1996 to 1998, Ms. Lanier served as Vice President and Chief of
Staff of Cinergy Corp. Ms. Lanier received her Bachelor of Arts Degree with honors from Smith College and her Juris Doctor from Columbia Law School where she was a Harlan Fiske Stone Scholar. Ms. Lanier was awarded an Honorary Doctorate of Technical
Letters by Cincinnati Technical College and an Honorary Doctorate of Letters from the College of Mt. St. Joseph. From 1982 to 1984 she was an associate with Frost & Jacobs, a law firm in Cincinnati, Ohio and a partner from 1984 to 1996. From
1977 to 1982 she was with the law firm of Davis Polk & Wardwell in New York City. She is past Chair of the Ohio Board of Regents.



48



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Alexander P. Lynch has served as a Director since 1996. Mr. Lynch has been a Managing Director of
J.P. Morgan Securities, Inc., a subsidiary of JPMorganChase, Inc., since July 2000. From 1997 to July 2000, Mr. Lynch was a General Partner of The Beacon Group, a private investment and financial advisory firm, which was merged with Chase Securities
in July 2000. From 1995 to 1997, Mr. Lynch was Co-President and Co-Chief Executive Officer of The Bridgeford Group, a financial advisory firm, which was merged into the Beacon Group. From 1991 to 1994, he served as Senior Managing Director of
Bridgeford. From 1985 until 1991, Mr. Lynch was a Managing Director of Lehman Brothers, a division of Shearson Lehman Brothers Inc. Mr. Lynch received his Bachelor of Arts Degree from the University of Pennsylvania and his M.B.A. from the Wharton
School of Business at the University of Pennsylvania.



Paul
M. Rady has served as a Director since April 2001. Mr. Rady is the Chairman and Chief Executive Officer of Antero Resources Corporation, a private independent oil and gas company formed in late 2002. Mr. Rady previously served as Chief Executive
Officer, President, and Chairman of the Board of Directors of Pennaco Energy, Inc., an oil and gas exploration company. Pennaco was sold to Marathon Oil Company in early 2001. He joined Pennaco in June 1998 as its Chief Executive Officer, President
and Director. Mr. Rady was with Barrett Resources Corporation, an oil and gas exploration and production company, for approximately eight years. During his tenure at Barrett, Mr. Rady held various executive positions including his most recent
position as Chief Executive Officer, President and Director. Other positions held by Mr. Rady were Chief Operating Officer, Executive Vice President-Exploration, and Chief Geologist-Exploration Manager. Prior to his employment at Barrett, Mr. Rady
was with Amoco Production Company based in Denver, Colorado for approximately ten years. Mr. Rady received his Bachelor of Science Degree in Geology from Western States College of Colorado and his Master of Science Degree in Geology from Western
Washington University.



Jon R. Whitney has served as a
Director since March 2004. Mr. Whitney serves as the managing member of Peak Energy Ventures, LLC, a private company engaged in the mid-stream sector of the natural gas business in the Rocky Mountains. Prior to 2001, he served as President and Chief
Executive Officer of Colorado Interstate Gas Company (CIG), the principal transporter of natural gas in the Rocky Mountain region, until it merged into El Paso Corporation. Mr. Whitney was with CIG for 34 years, the last twelve as its
Chief Executive. Mr. Whitney received a Bachelor of Arts Degree in accounting from Colorado State University.



49



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Compliance with Section 16(a) of the Securities Exchange Act of 1934



Based solely on a review of such forms furnished to the Company and certain
written representations from the Executive Officers and Directors, the Company believes that all Section 16(a) filing requirements applicable to its Executive Officers, Directors and greater than ten percent beneficial owners were complied with on a
timely basis.



Board Committees



The Board has established four committees to assist it in the discharge of
its responsibilities.



Audit Committee. The Audit
Committee reviews the professional services provided by independent public accountants and the independence of such accountants from management. This Committee also reviews the scope of the audit coverage, the quarterly and annual financial
statements and such other matters with respect to the accounting, auditing and financial reporting practices and procedures as it may find appropriate or as have been brought to its attention. The members of the Audit Committee are Charles Bayless,
Elizabeth Lanier and Alexander Lynch.



Compensation
Committee. The Compensation Committee reviews and approves officers salaries and administers the bonus, incentive compensation and stock option plans. The Committee advises and consults with management regarding benefits and significant
compensation policies and practices. This Committee also considers nominations of candidates for officer positions. The members of the Compensation Committee are Jeffrey Berenson, Robert Clark and Alexander Lynch.



Governance and Nominating Committee. The Governance and Nominating
Committee identifies, reviews and recommends candidates for Board membership, determines the composition of the Board and its committees, develops corporate governance guidelines and oversees compliance with them, and monitors Board and management
effectiveness. The members of the Governance and Nominating Committee are Elizabeth Lanier, Paul Rady and Jon Whitney.



Executive Committee. The Executive Committee reviews and authorizes actions required in the management of the business and affairs of Patina, which
would otherwise be determined by the Board, where it is not practicable to convene the full Board. The members of the Executive Committee are Thomas Edelman, Robert Clark and Alexander Lynch.



Code of Business Conduct and Ethics



The Company has adopted a Code of Business Conduct and Ethics that
applies to our Directors and to all of our employees, including the Chief Executive Officer and the Chief Financial Officer. This Code of Business Conduct and Ethics is posted on our web site at www.patinaoil.com. A hard copy will also be delivered
free of charge at the request of any stockholder. Any waivers of, or amendments to, our Code of Business Conduct and Ethics will be posted on our web site.



Corporate Governance Guidelines



The Board of Directors of the Company has adopted Corporate Governance Guidelines that govern the responsibilities and requirements applicable to
our Directors. These Corporate Governance Guidelines are posted on our web site at www.patinaoil.com. A hard copy will also be delivered free of charge at the request of any stockholder.



50



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|ITEM 11. | EXECUTIVE COMPENSATION
|-------- | ----------------------



Information with respect to executive compensation is incorporated herein by reference to the Companys definitive Proxy Statement relating to the
2005 annual meeting of stockholders, or an amendment to this Form 10-K, which in either case, will be filed with the SEC no later than April 30, 2005.



|ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|-------- | ----------------------------------------------------------------------------------------------



Information with respect to security ownership of certain beneficial owners and management is incorporated herein by
reference to the Companys definitive Proxy Statement relating to the 2005 annual meeting of stockholders, or an amendment to this Form 10-K, which in either case, will be filed with the SEC no later than April 30, 2005.



|ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
|-------- | ----------------------------------------------



None.



|ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES
|-------- | --------------------------------------



Information with respect to principal accountant fees and services is incorporated herein by reference to the Companys definitive Proxy Statement
relating to the 2005 annual meeting of stockholders, or an amendment to this Form 10-K, which in either case, will be filed with the SEC no later than April 30, 2005.



51



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PART IV



|ITEM 15. | EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
|-------- | -------------------------------------------------------------------------------------



| | (a) | 1. and 2. Financial Statements and Financial Statement Schedules
| | --- | ----------------------------------------------------------------



The items listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.



3. Exhibits.



The following documents are filed herewith or incorporated by reference as exhibits to this Annual Report on Form 10-K:



|      |  |                                                                                                                                                                                                                                                                                                                        
|----- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|      | 
|2.1   |  | Amended and Restated Agreement and Plan of Merger dated as of January 16, 1996 as amended and restated as of March 20, 1996 (Incorporated herein by reference to Exhibit 2.1 to Amendment No. 1
to the Registration Statement on Form S-4 of the Company (Registration No. 333-572))                                   
|      | 
|2.2   |  | Agreement and Plan of Merger among Patina Oil & Gas Corporation, Patina Bravo Corporation, Bravo Natural Resources, Inc., and Certain of the Stockholders of Bravo Natural Resources, Inc.
dated November 6, 2002 (Incorporated herein by reference to Exhibit 2.1 to the Companys Form 8-K filed on December 9, 2002)
|      | 
|2.3   |  | Purchase and Sale Agreement between Cordillera Energy Partners, LLC and Patina Oil & Gas Corporation dated August 25, 2003 (Incorporated herein by reference to Exhibit 2.1 to the
Companys Form 8-K filed on October 2, 2003)                                                                                        
|      | 
|2.4   |  | Agreement and Plan of Merger, dated as of December 15, 2004 by and among Noble Energy, Inc., Noble Energy Production, Inc. and Patina Oil & Gas Corporation (Incorporated herein by
reference to Exhibit 2.1 to Form 8-K filed December 21, 2004)                                                                      
|      | 
|3.1   |  | Certificate of Incorporation (Incorporated herein by reference to the Exhibit 3.1 to the Companys Registration Statement on Form S-4 (Registration No. 333-572))                                                                                                                                                      
|      | 
|3.2   |  | Amended and Restated Bylaws of Patina Oil & Gas Corporation. (Incorporated herein by reference to Exhibit 3(ii) of the Companys Form 8-K filed on May 25, 2001)                                                                                                                                                       
|      | 
|3.3   |  | Certificate of Ownership and Merger of Gerrity Oil & Gas Corporation with and into the Company, effective March 21, 1997 (Incorporated herein by reference to Exhibit 4.3 of the
Companys Form 10-Q for the quarter ended March 31, 1997)                                                                             
|      | 
|4.1   |  | Rights Agreement, dated as of May 25, 2001 between the Company and Mellon Investor Services LLC, a Rights Agent (Incorporated herein by reference to Exhibit 4.1 of the Companys Form
8-A/A filed on June 12, 2001 (Registration No. 001-14344))                                                                      
|      | 
|4.1.1 |  | Amendment to Rights Agreement, dated as of December 15, 2004 between Patina Oil & Gas Corporation and Mellon Investor Services, LLC (Incorporated herein by reference to Exhibit 4.1 to
Form 8-K filed on December 20, 2004)                                                                                           
|      | 
|4.2   |  | Certificate of Designations of Series A Junior Participating Preferred Stock (included as Exhibit A to the Rights Agreement listed above as Exhibit 4.1)                                                                                                                                                               



52



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|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|------ |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|       | 
|4.3    |  | Form of Warrant to Purchase Shares of Common Stock of Patina Oil & Gas Corporation dated March 8, 2004 (Incorporated herein by reference to Exhibit 4.1 to Amendment No. 1 to Form S-3
filed March 17, 2004 (Registration No. 333-110708))                                                                                                                                                                                                                                      
|       | 
|10.1   |  | Third Amended and Restated Credit Agreement dated January 28, 2003 by and among the Company, as Borrower, and Bank One, NA, as Administrative Agent, Wachovia Bank, National Association and
Wells Fargo Bank, N.A., as Syndication Agents, Bank of America, N.A. and Credit Lyonnais New York Branch, as Documentation Agents, and certain commercial lending institutions (Incorporated herein by reference to Exhibit 10.1 of the Companys
Form 10-K filed on March 5, 2003)
|       | 
|10.1.1 |  | First Amendment to the Third Amended and Restated Credit Agreement dated May 1, 2003 by and among the Company, as borrower, Bank One, NA, as Administrative Agent, and certain other financial
institutions (Incorporated herein by reference to Exhibit 10.1.2 of the Companys Form 10-Q filed on August 1, 2003)                                                                                                                                                             
|       | 
|10.1.2 |  | Second Amendment to the Third Amended and Restated Credit Agreement dated October 1, 2003 by and among the Company, as Borrower, and Bank One, NA, as Administrative Agent, and certain other
financial institutions (Incorporated herein by reference to Exhibit 10.1.3 to the Companys Form 8-K filed on October 2, 2003)                                                                                                                                                    
|       | 
|10.2   |  | Agreement and Plan of Reorganization by and among Patina Oil & Gas Corporation, Le Norman Energy Corporation, Patina Oklahoma Corp., and The Le Norman Shareholders dated October 23, 2002
(Incorporated herein by reference to Exhibit 10.1 of the Companys Form 8-K filed on November 7, 2002)                                                                                                                                                                               
|       | 
|10.3   |  | Patina Oil & Gas Corporation Profit Sharing and Savings Plan and Trust, effective January 1, 1997 (Incorporated herein by reference to Exhibit 10.3 of the Companys Form 10-K for the
year ended, December 31, 1997)                                                                                                                                                                                                                                                           
|       | 
|10.4   |  | Amended and Restated Patina Oil & Gas Corporation Deferred Compensation Plan for Select Employees as adopted May 1, 1996 and amended as of September 30, 1997 and further amended as of
August 1, 2001 (Incorporated herein by reference to Exhibit 10.1 of the Companys Form 10-Q for the quarter ended September 30, 2001)                                                                                                                                                   
|       | 
|10.4.1 |  | Amendment to the Amended and Restated Patina Oil & Gas Corporation Deferred Compensation Plan For Select Employees (Incorporated herein by reference to Exhibit 10.3 to Form 8-K filed
September 20, 2004)                                                                                                                                                                                                                                                                      
|       | 
|10.5   |  | Patina Oil & Gas Corporation 1998 Stock Purchase Plan (Incorporated herein by reference to Exhibit 10.3.3 of the Companys Form 10-K for the year ended December 31,
1997)                                                                                                                                                                                                                                                                                                      
|       | 
|10.5.1 |  | Amendment No. 1 to the Patina Oil & Gas Corporation 1998 Stock Purchase Plan (Incorporated herein by reference to Exhibit 10.3 of the Companys Form 10-Q for the quarter ended June
30, 1999)                                                                                                                                                                                                                                                                                  
|       | 
|10.6   |  | Patina Oil & Gas Corporation 1996 Employee Stock Option Plan (Incorporated herein by reference to Exhibit 10.20 of the Companys Registration Statement on Form S-4 (Registration No.
333-572))                                                                                                                                                                                                                                                                                 
|       | 
|10.6.1 |  | Amendment No. 1 to the 1996 Employee Stock Option Plan of Patina Oil & Gas Corporation (Incorporated herein by reference to Exhibit 10.2 of the Companys Form 10-Q for the quarter
ended June 30, 1999)                                                                                                                                                                                                                                                                        
|       | 
|10.6.2 |  | Amendment to Patina Oil & Gas Corporation 1996 Employee Stock Option Plan (Incorporated herein by reference to Exhibit 10.1 to Form 8-K filed September 20, 2004)                                                                                                                                                                                                                                                                                                               



53



---

|        |  |                                                                                                                                                                                                                                                   
|------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|        | 
|10.7    |  | Lease Agreement dated as of December 21, 2000 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant (Incorporated herein by reference to Exhibit 10.5.1 of the
Companys Form 10-K for the year ended December 31, 2000)
|        | 
|10.7.1  |  | Amendment of Lease Agreement dated November 19, 2001 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant (Incorporated herein by reference to Exhibit 10.6.1 of the
Companys Form 10-K filed on March 5, 2003)       
|        | 
|10.7.2  |  | Second Amendment of Lease Agreement dated January 16, 2003 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant (Incorporated herein by reference to Exhibit 10.6.2
of the Companys Form 10-K filed on March 5, 2003) 
|        | 
|10.7.3  |  | Third Amendment of Lease Agreement dated November 7, 2003 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant (Incorporated herein by reference to Exhibit 10.6.3
of the Companys Form 10-K filed on March 9, 2004)  
|        | 
|10.8    |  | Sale and Purchase Agreement by and between Wynn-Crosby 1998, Ltd. And Wynn-Crosby 1999, Ltd. And Patina Oklahoma Corp. dated February 19, 2003 (Incorporated herein by reference to Exhibit
10.1 to Form 8-K filed March 18, 2003)                
|        | 
|10.9    |  | Patina Oil & Gas Corporation 2005 Deferred Compensation Plan for Select Employees (Incorporated herein by reference to Exhibit 10.1 to Form 8-K filed December 30, 2004)                                                                          
|        | 
|10.10   |  | Letter Agreement dated July 19, 2004 between the Company and Ted D. Brown (Incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed October 28, 2004)                                                                                  
|        | 
|10.11   |  | Patina Oil & Gas Corporation Profit Sharing & 401(k)  Scudder Trust Company Prototype Defined Contribution Plan, adopted June 18, 2004 (Incorporated herein by reference to
Exhibit 10.1 to Form 10-Q filed July 29, 2004)                       
|        | 
|10.12   |  | Patina Oil & Gas Corporation Profit Sharing & 401(k)  Scudder Trust Company Prototype Defined Contribution Plan Adoption Agreement, dated June 18, 2004 (Incorporated herein by
reference to Exhibit 10.2 to Form 10-Q filed July 29, 2004)      
|        | 
|10.13   |  | Separation and Consulting Agreement dated December 22, 2004 between Patina Oil & Gas Corporation and Jay W. Decker (Incorporated herein by reference to Exhibit 10.1 to Form 8-K filed
December 22, 2004)                                         
|        | 
|10.14   |  | Patina Oil & Gas Corporation Amended and Restated Change in Control Plan (Incorporated herein by reference to Exhibit 10.5 to Form 8-K filed September 20, 2004)                                                                                  
|        | 
|10.14.1 |  | Amendment to the Amended and Restated Patina Oil & Gas Change in Control Plan (Incorporated herein by reference to Exhibit 10.1 to Form 8-K filed December 21, 2004)                                                                              
|        | 
|10.15   |  | Patina Oil & Gas Corporation 1996 Stock Plan for Non-Employee Directors (Incorporated herein by reference to Exhibit 10.21 of the Companys Registration Statement on Form S-4
(Registration No. 333-572))                                        
|        | 
|10.15.1 |  | Amendment to Patina Oil & Gas Corporation 1996 Stock Plan for Non-Employee Directors (Incorporated herein by reference to Exhibit 10.2 to Form 8-K filed September 20,
2004)                                                                      
|        | 
|10.16   |  | Form of Patina Oil & Gas Corporation Director/Officer Indemnification Agreement (Incorporated herein by reference to Exhibit 10.4 to Form 8-K filed September 20, 2004)                                                                           
|        | 
|10.17   |  | Patina Oil & Gas Corporation Long Term Incentive Program for Chief Executive Officer (Incorporated herein by reference to Exhibit 10.1 to Form 8-K filed December 16,
2004)                                                                       



54



---

|        |  |                                                                                                                                                                                                                   
|------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|        | 
|10.18   |  | Employment Agreement dated July 31, 1997 by and between the Company and Thomas J. Edelman (Incorporated herein by reference to Exhibit 10.7 of the Companys Form 10-Q for the quarter
ended September 30, 1997)  
|        | 
|10.18.1 |  | Amendment to Employment Agreement, dated as of December 15, 2004 between Patina Oil & Gas Corporation and Thomas J. Edelman (Incorporated herein by reference to Exhibit 10.2 to Form 8-K
filed December 21, 2004)
|        | 
|21.1    |  | Subsidiaries of Registrant *                                                                                                                                                                                      
|        | 
|23.1    |  | Consent of independent auditors *                                                                                                                                                                                 
|        | 
|23.2    |  | Consent of independent reservoir engineers *                                                                                                                                                                      
|        | 
|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 the Chief Executive Officer, dated February 25, 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 the Chief Financial Officer, dated February 25, 2005, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.*                                 



* - Filed herewith



| | (b) | Reports on Form 8-K.
| | --- | --------------------



The Company filed a current report on Form 8-K on October 21, 2004 to furnish the information required under Item 12 related to the October 19, 2004 press
release providing an operational update and announcing the Companys third quarter conference call.



The Company filed a current report on Form 8-K on October 28, 2004 to furnish the information required under Item 12 related to the October 27, 2004 press
release announcing the Companys financial results for the three and nine months ended September 30, 2004.



The Company filed a current report on Form 8-K on December 16, 2004 to incorporate by reference a press release dated December 16, 2004 announcing the
entry into a definitive agreement and plan of merger by and among Noble Energy, Inc., Noble Energy Production, Inc. and the Company.



The Company filed a current report on Form 8-K on December 16, 2004 to announce entry into a material definitive agreement and approval of the Long Term
Incentive Program for Chief Executive Officer.



The Company
filed a current report on Form 8-K on December 21, 2004 to furnish the information required under Item 1 related to the December 16, 2004 press release announcing the Companys entry into a material definitive agreement and plan of merger by
and among Noble Energy, Inc., Noble Energy Production, Inc. and the Company.



The Company filed a current report on Form 8-K on December 22, 2004 to furnish the information required under Item 5 related to the Companys December 22, 2004 press release announcing the Companys entry
into a material definitive agreement and departure of directors or principal officers.



55



---

The Company filed a current report on Form 8-K on December 30, 2004 to announce entry into a material
definitive agreement including adoption of the 2005 Deferred Compensation Plan for Select Employees of the Company.



| | (c) | Exhibits required by Item 601 of Regulation S-K
| | --- | -----------------------------------------------



Exhibits required to be filed pursuant to Item 601 of Regulation S-K are filed as part of this Annual Report on Form 10-K.



| | (d) | Financial Statement Schedules Required by Regulation S-X.
| | --- | ---------------------------------------------------------



None.



56



---



SIGNATURES



Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



|                        |  |  |  |                              |  |                       |  |                                      
|----------------------- |  |  |  | ---------------------------- |  | --------------------- |  | -------------------------------------
|                        |  |  |  | PATINA OIL & GAS CORPORATION
|                        |  |  | 
|Date: February 25, 2005 |  |  |  | By:                          |  | /s/ Thomas J. Edelman
|                        |  |  |  |                              |  |                       |  | Thomas J. Edelman                    
|                        |  |  |  |                              |  |                       |  | Chairman, Chief Executive Officer and
|                        |  |  |  |                              |  |                       |  | President                            



Pursuant to the
requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



|                                           |  |                                                                                                             |  |                  
|------------------------------------------ |  | ----------------------------------------------------------------------------------------------------------- |  | -----------------
|                                           |  |                                                                                                            
|/s/ Thomas J. EdelmanThomas J. Edelman     |  | Chairman, Chief Executive Officer and President (Principal Executive Officer)                               |  | February 25, 2005
|                                           |  |                                                                                                            
|/s/ David J. KornderDavid J. Kornder       |  | Executive Vice President, Chief Financial Officer and
Director (Principal Financial and Accounting Officer) |  | February 25, 2005
|                                           |  |                                                                                                            
|/s/ Charles E. BaylessCharles E. Bayless   |  | Director                                                                                                    |  | February 25, 2005
|                                           |  |                                                                                                            
|/s/ Jeffrey L. BerensonJeffrey L. Berenson |  | Director                                                                                                    |  | February 25, 2005
|                                           |  |                                                                                                            
|/s/ Robert J. ClarkRobert J. Clark         |  | Director                                                                                                    |  | February 25, 2005
|                                           |  |                                                                                                            
|/s/ Elizabeth K. LanierElizabeth K. Lanier |  | Director                                                                                                    |  | February 25, 2005
|                                           |  |                                                                                                            
|/s/ Alexander P. LynchAlexander P. Lynch   |  | Director                                                                                                    |  | February 25, 2005
|                                           |  |                                                                                                            
|/s/ Paul M. RadyPaul M. Rady               |  | Director                                                                                                    |  | February 25, 2005
|                                           |  |                                                                                                            
|/s/ Jon R. WhitneyJon R. Whitney           |  | Director                                                                                                    |  | February 25, 2005



57



---



GLOSSARY



The terms defined in this glossary are used throughout this Form 10-K.



Barrel or Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.



Bcf. One billion
cubic feet.



Bcfe. One billion cubic feet of natural gas equivalents,
based on a ratio of six Mcf for each barrel of oil, which reflects the relative energy content.



Credit Facility.The Patina Oil & Gas Corporation $500.0 million revolving bank facility.



Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.



Deepening. The re-entry into an existing wellbore and drilling to a
deeper target formation.



Dry hole. A well found to be incapable of
producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well.



EBITDA. Earnings before interest, taxes, depletion, depreciation and amortization, as defined in the Companys bank Credit Agreement.



Elysium Energy, L.L.C. A New York limited liability company in which Patina holds a 100% interest. Elysium is engaged in the
development, exploration and acquisition of oil and gas properties primarily located in the Illinois Basin and in central Kansas.



Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or
gas in another reservoir, or to extend a known reservoir.



Gross acres or
gross wells. The total acres or wells, as the case may be, in which a working interest is owned.



Infill well. A well drilled between known producing wells to better exploit the reservoir.



LIBOR.London Interbank Offer Rate, the rate of interest at which banks offer to lend to one another in the wholesale money markets in the City of London. This
rate is a yardstick for lenders involved in high value transactions.



MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.



Mcf.One thousand cubic feet.



Mcfe. One thousand cubic
feet of natural gas equivalents, based on a ratio of six Mcf for each barrel of oil, which reflects the relative energy content.



MMBbl. One million barrels of crude oil or other liquid hydrocarbons.



MMBtu. One million British thermal units. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5
degrees Fahrenheit.



MMcf. One million cubic feet.



58



---

MMcfe. One million cubic feet of natural gas equivalents.



Net acres or net wells. The sum of the fractional working interests owned in gross
acres or gross wells.



Net oil and gas sales. Oil and natural gas sales
less oil and natural gas production expenses.



PV10%. The present value,
discounted at 10%, of future net cash flows from estimated proved reserves, using constant prices and costs in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions).



Productive well. A well that is producing oil or gas or that is capable of production.



Proved developed non-producing reserves. Reserves that consist of (i)
proved reserves from wells that have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which
are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.



Proved developed producing reserves. Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present
operating methods.



Proved developed reserves. Proved reserves that can
be expected to be recovered through existing wells with existing equipment and operating methods. See Regulation S-X, Rule 4-10(a)(3) of the Exchange Act of 1934.



Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. See Regulation S-X, Rule 4-10(a)(2) of the Exchange Act of 1934.



Proved undeveloped reserves. Proved reserves that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. See Regulation S-X, Rule 4-10(a)(4) of the Exchange Act of 1934.



Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has previously
been completed.



Refrac. The restimulation of a producing formation
within an existing wellbore to enhance existing production and add incremental reserves.



Reserve life index. The presentation of proved reserves defined in number of years of annual production.



Royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and natural gas production free of costs of production.



Standardized Measure. The present value, discounted at 10%, of future net cash
flows from estimated proved reserves after income taxes calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise
in accordance with the Commissions rules for inclusion of oil and gas reserve information in financial statements filed with the Securities and Exchange Commission.



Trifrac. The restimulation of a producing formation which has been previously refraced within an existing wellbore to enhance
existing production and add incremental reserves.



Working interest. The
operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration,
development and operations and all risks in connection therewith.



59



---

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                                                                                  |  |     
|----------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                                                                                  |  | Page
|PATINA OIL & GAS CORPORATION                                                                                                                                      |  |     
|                                                                                                                                                                  | 
|Report of Independent Registered Public Accounting Firm                                                                                                           |  | F-2 
|                                                                                                                                                                  | 
|Consolidated Balance Sheets as of December 31, 2003 and 2004                                                                                                      |  | F-3 
|                                                                                                                                                                  | 
|Consolidated Statements of Operations for the years ended December 31, 2002, 2003 and 2004                                                                        |  | F-4 
|                                                                                                                                                                  | 
|Consolidated Statements of Changes in Stockholders Equity and Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2002, 2003 and 2004 |  | F-5 
|                                                                                                                                                                  | 
|Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2003 and 2004                                                                        |  | F-6 
|                                                                                                                                                                  | 
|Notes to Consolidated Financial Statements                                                                                                                        |  | F-7 



F-1



---



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Stockholders of

Patina Oil & Gas Corporation:



We have audited the accompanying consolidated balance sheets of Patina Oil & Gas Corporation (a Delaware corporation) and its subsidiaries (the
Company) as of December 31, 2003 and 2004, and the related consolidated statements of operations, changes in stockholders equity and accumulated other comprehensive income (loss) and cash flows for each of the three years in the
period ended December 31, 2004. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.



We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.



In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Patina Oil & Gas Corporation and its subsidiaries as of December 31, 2003 and 2004, and the
results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.



As discussed in Note 3 to the consolidated financial statements, on January 1, 2003, the
Company changed its method of accounting for asset retirement obligations to conform to Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.



We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of the Companys internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control  Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2005 expressed an unqualified opinion on managements assessment of the effectiveness of the Companys internal control over financial
reporting and an unqualified opinion on the effectiveness of the Companys internal control over financial reporting.



/s/ DELOITTE & TOUCHE LLP



Denver, Colorado

February 23, 2005



F-2



---



PATINA OIL & GAS CORPORATION



CONSOLIDATED BALANCE SHEETS

(In thousands except share data)



|                                                                                                               |  |              |           |   |      |   |           |  
|-------------------------------------------------------------------------------------------------------------- |  | ------------ | --------- | - | ---- | - | --------- | -
|                                                                                                               |  | December 31, |          
|                                                                                                               |  | 2003         |           |   | 2004 |  
|ASSETS                                                                                                         |  |              |           |   |      |   |           |  
|Current assets                                                                                                 |  |              |           |   |      |   |           |  
|Cash and equivalents                                                                                           |  | $            | 545       |   |      | $ | 3,024     |  
|Accounts receivable                                                                                            |  |              | 59,973    |   |      |   | 83,444    |  
|Inventory and other                                                                                            |  |              | 17,736    |   |      |   | 25,542    |  
|Income taxes receivable                                                                                        |  |              |          |   |      |   | 7,137     |  
|Deferred income taxes                                                                                          |  |              | 23,641    |   |      |   | 54,817    |  
|Unrealized hedging gains                                                                                       |  |              | 137       |   |      |   | 7,256     |  
|                                                                                                               |  |              |           |   |      |   |           |  
|                                                                                                               |  |              | 102,032   |   |      |   | 181,220   |  
|                                                                                                               |  |              |           |   |      |   |           |  
|Unrealized hedging gains                                                                                       |  |              | 1,867     |   |      |   |          |  
|                                                                                                               |  |             
|Oil and gas properties, successful efforts method                                                              |  |              | 1,628,750 |   |      |   | 1,893,069 |  
|Accumulated depletion, depreciation and amortization                                                           |  |              | (560,090  | ) |      |   | (681,394  | )
|                                                                                                               |  |              |           |   |      |   |           |  
|                                                                                                               |  |              | 1,068,660 |   |      |   | 1,211,675 |  
|                                                                                                               |  |              |           |   |      |   |           |  
|Field equipment and other                                                                                      |  |              | 15,027    |   |      |   | 18,622    |  
|Accumulated depreciation                                                                                       |  |              | (6,506    | ) |      |   | (8,681    | )
|                                                                                                               |  |              |           |   |      |   |           |  
|                                                                                                               |  |              | 8,521     |   |      |   | 9,941     |  
|                                                                                                               |  |              |           |   |      |   |           |  
|Other assets, net                                                                                              |  |              | 15,211    |   |      |   | 26,203    |  
|                                                                                                               |  |              |           |   |      |   |           |  
|                                                                                                               |  | $            | 1,196,291 |   |      | $ | 1,429,039 |  
|                                                                                                               |  |              |           |   |      |   |           |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                           |  |              |           |   |      |   |           |  
|Current liabilities                                                                                            |  |              |           |   |      |   |           |  
|Accounts payable                                                                                               |  | $            | 61,329    |   |      | $ | 105,822   |  
|Accrued liabilities                                                                                            |  |              | 18,866    |   |      |   | 28,135    |  
|Unrealized hedging losses                                                                                      |  |              | 62,349    |   |      |   | 151,512   |  
|                                                                                                               |  |              |           |   |      |   |           |  
|                                                                                                               |  |              | 142,544   |   |      |   | 285,469   |  
|                                                                                                               |  |              |           |   |      |   |           |  
|Bank debt                                                                                                      |  |              | 416,000   |   |      |   | 297,000   |  
|Deferred income taxes                                                                                          |  |              | 154,480   |   |      |   | 203,473   |  
|Other noncurrent liabilities                                                                                   |  |              | 50,236    |   |      |   | 62,477    |  
|Unrealized hedging losses                                                                                      |  |              | 27,631    |   |      |   | 66,167    |  
|Deferred compensation liability                                                                                |  |              | 74,888    |   |      |   | 103,634   |  
|Commitments and contingencies                                                                                  |  |              |           |   |      |   |           |  
|Stockholders equity                                                                                           |  |              |           |   |      |   |           |  
|Preferred Stock, $.01 par, 5,000,000 shares authorized, none issued or outstanding                             |  |              |          |   |      |   |          |  
|Common Stock, $.01 par, 100,000,000 and 250,000,000 shares authorized, 71,504,986 and 72,781,701 shares issued |  |              | 715       |   |      |   | 728       |  
|Less Common Stock Held in Treasury, at cost, 2,481,820 shares and 2,097,912 shares                             |  |              | (7,850    | ) |      |   | (6,945    | )
|Capital in excess of par value                                                                                 |  |              | 187,171   |   |      |   | 207,017   |  
|Deferred compensation                                                                                          |  |              | (764      | ) |      |   | (1,011    | )
|Retained earnings                                                                                              |  |              | 205,786   |   |      |   | 341,492   |  
|Accumulated other comprehensive loss                                                                           |  |              | (54,546   | ) |      |   | (130,462  | )
|                                                                                                               |  |              |           |   |      |   |           |  
|                                                                                                               |  |              | 330,512   |   |      |   | 410,819   |  
|                                                                                                               |  |              |           |   |      |   |           |  
|                                                                                                               |  | $            | 1,196,291 |   |      | $ | 1,429,039 |  
|                                                                                                               |  |              |           |   |      |   |           |  



The accompanying notes
are an integral part of these financial statements.



F-3



---



PATINA OIL & GAS CORPORATION



CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except per share data)



|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|----------------------------------------------------------------------------------------------------- |  | ----------------------- | ------- | ---- | - | ------- | ---- |  | - | -------
|                                                                                                      |  | Year Ended December 31,
|                                                                                                      |  | 2002                    |         | 2003 |   |         | 2004
|Revenues                                                                                              |  |                         |         |      |   |         |      |  |   |        
|Oil and gas sales, net of gathering and processing costs of$7,749, $11,598, and $17,795, respectively |  | $                       | 215,430 |      | $ | 398,724 |      |  | $ | 544,815
|Gain on sale of properties                                                                            |  |                         |        |      |   |        |      |  |   | 7,938  
|Other                                                                                                 |  |                         | 6,977   |      |   | 7,993   |      |  |   | 8,248  
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|                                                                                                      |  |                         | 222,407 |      |   | 406,717 |      |  |   | 561,001
|Expenses                                                                                              |  |                         |         |      |   |         |      |  |   |        
|Lease operating                                                                                       |  |                         | 27,986  |      |   | 54,082  |      |  |   | 71,596 
|Production taxes                                                                                      |  |                         | 11,751  |      |   | 28,726  |      |  |   | 46,034 
|Exploration                                                                                           |  |                         | 2,171   |      |   | 6,207   |      |  |   | 2,058  
|General and administrative                                                                            |  |                         | 12,714  |      |   | 19,034  |      |  |   | 26,390 
|Interest                                                                                              |  |                         | 2,299   |      |   | 8,817   |      |  |   | 12,563 
|Loss on sale of oil and gas properties                                                                |  |                         |        |      |   | 7,223   |      |  |   |       
|Other                                                                                                 |  |                         | 463     |      |   | 578     |      |  |   | 301    
|Deferred compensation adjustment                                                                      |  |                         | 9,983   |      |   | 33,110  |      |  |   | 31,722 
|Depletion, depreciation and amortization                                                              |  |                         | 66,162  |      |   | 98,119  |      |  |   | 126,849
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|                                                                                                      |  |                         | 133,529 |      |   | 255,896 |      |  |   | 317,513
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Pretax income                                                                                         |  |                         | 88,878  |      |   | 150,821 |      |  |   | 243,488
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Provision for income taxes                                                                            |  |                         |         |      |   |         |      |  |   |        
|Current                                                                                               |  |                         | 8,799   |      |   | 21,492  |      |  |   | 29,608 
|Deferred                                                                                              |  |                         | 22,372  |      |   | 35,820  |      |  |   | 62,917 
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|                                                                                                      |  |                         | 31,171  |      |   | 57,312  |      |  |   | 92,525 
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Net income before change in accounting principle                                                      |  | $                       | 57,707  |      | $ | 93,509  |      |  | $ | 150,963
|Cumulative effect of change in accounting principle                                                   |  |                         |        |      |   | (2,613  | )    |  |   |       
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Net income                                                                                            |  | $                       | 57,707  |      | $ | 90,896  |      |  | $ | 150,963
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Net income per share before cumulative effect of change in accounting principle                       |  |                         |         |      |   |         |      |  |   |        
|Basic                                                                                                 |  | $                       | 0.88    |      | $ | 1.37    |      |  | $ | 2.15   
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Diluted                                                                                               |  | $                       | 0.84    |      | $ | 1.32    |      |  | $ | 2.05   
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Net loss per share from change in accounting principle                                                |  |                         |         |      |   |         |      |  |   |        
|Basic                                                                                                 |  | $                       |        |      | $ | (0.04   | )    |  | $ |       
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Diluted                                                                                               |  | $                       |        |      | $ | (0.04   | )    |  | $ |       
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Net income per share                                                                                  |  |                         |         |      |   |         |      |  |   |        
|Basic                                                                                                 |  | $                       | 0.88    |      | $ | 1.33    |      |  | $ | 2.15   
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Diluted                                                                                               |  | $                       | 0.84    |      | $ | 1.28    |      |  | $ | 2.05   
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Weighted average shares outstanding                                                                   |  |                         |         |      |   |         |      |  |   |        
|Basic                                                                                                 |  |                         | 65,933  |      |   | 68,170  |      |  |   | 70,234 
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        
|Diluted                                                                                               |  |                         | 68,970  |      |   | 71,062  |      |  |   | 73,473 
|                                                                                                      |  |                         |         |      |   |         |      |  |   |        



The accompanying notes
are an integral part of these financial statements.



F-4



---



PATINA OIL & GAS CORPORATION



CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS EQUITY

AND ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

(In thousands)



|                                         |  |                      |        |              |        |        |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                            |   |        |       |  |   |         |   |  |   |          |   |  |   |          |  
|---------------------------------------- |  | -------------------- | ------ | ------------ | ------ | ------ | ------------- | - | --- | ---------------------------- |  | - | -------------------- | - |  | ---------------- | ------- | - | ------------------------------------------ | - | ------ | ----- |  | - | ------- | - |  | - | -------- | - |  | - | -------- | -
|                                         |  | PreferredStockAmount |        | Common Stock |        |        | TreasuryStock |   |     | Capital inExcess ofPar Value |  |   | DeferredCompensation |   |  | RetainedEarnings |         |   | AccumulatedOtherComprehensiveIncome (Loss) |   |        | Total | 
|                                         |  |                      | Shares |              |        | Amount |               |   |     |                              |  |   |                     
|Balance, December 31, 2001               |  | $                    |       |              | 66,381 |        |               | $ | 663 |                              |  | $ | (5,866               | ) |  | $                | 145,903 |   |                                            | $ |       |       |  | $ | 71,513  |   |  | $ | 37,361   |   |  | $ | 249,574  |  
|Repurchase of common stock               |  |                      |       |              | (1     | )      |               |   |    |                              |  |   |                     |   |  |                  | (9      | ) |                                            |   |       |       |  |   |        |   |  |   |         |   |  |   | (9       | )
|Issuance of common stock                 |  |                      |       |              | 3,944  |        |               |   | 40  |                              |  |   |                     |   |  |                  | 22,976  |   |                                            |   |       |       |  |   |        |   |  |   |         |   |  |   | 23,016   |  
|Deferred compensation stock issued, net  |  |                      |       |              |       |        |               |   |    |                              |  |   | (951                 | ) |  |                  | 2,820   |   |                                            |   |       |       |  |   |        |   |  |   |         |   |  |   | 1,869    |  
|Tax benefit from stock options           |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  | 3,496   |   |                                            |   |       |       |  |   |        |   |  |   |         |   |  |   | 3,496    |  
|Dividends                                |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   |       |       |  |   | (5,513  | ) |  |   |         |   |  |   | (5,513   | )
|Comprehensive income:                    |  |                      |        |              |        |        |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                            |   |        |       |  |   |         |   |  |   |          |   |  |   |          |  
|Net income                               |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   |       |       |  |   | 57,707  |   |  |   |         |   |  |   | 57,707   |  
|Contract settlements reclassed to income |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   |       |       |  |   |        |   |  |   | (11,953  | ) |  |   | (11,953  | )
|Change in unrealized hedging gains       |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   |       |       |  |   |        |   |  |   | (19,607  | ) |  |   | (19,607  | )
|                                         |  |                      |        |              |        |        |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                            |   |        |       |  |   |         |   |  |   |          |   |  |   |          |  
|Total comprehensive income               |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   |       |       |  |   | 57,707  |   |  |   | (31,560  | ) |  |   | 26,147   |  
|                                         |  |                      |        |              |        |        |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                            |   |        |       |  |   |         |   |  |   |          |   |  |   |          |  
|Balance, December 31, 2002               |  |                      |       |              | 70,324 |        |               |   | 703 |                              |  |   | (6,817               | ) |  |                  | 175,186 |   |                                            |   |       |       |  |   | 123,707 |   |  |   | 5,801    |   |  |   | 298,580  |  
|Repurchase of common stock               |  |                      |       |              | (1,181 | )      |               |   | (12 | )                            |  |   |                     |   |  |                  | (17,218 | ) |                                            |   |       |       |  |   |        |   |  |   |         |   |  |   | (17,230  | )
|Issuance of common stock                 |  |                      |       |              | 2,362  |        |               |   | 24  |                              |  |   |                     |   |  |                  | 10,229  |   |                                            |   | (861   | )     |  |   |        |   |  |   |         |   |  |   | 9,392    |  
|Deferred compensation stock issued, net  |  |                      |       |              |       |        |               |   |    |                              |  |   | (1,033               | ) |  |                  | 4,398   |   |                                            |   |       |       |  |   |        |   |  |   |         |   |  |   | 3,365    |  
|Amortization of stock grant              |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   | 97     |       |  |   |        |   |  |   |         |   |  |   | 97       |  
|Issuance of warrants                     |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  | 4,000   |   |                                            |   |       |       |  |   |        |   |  |   |         |   |  |   | 4,000    |  
|Tax benefit from stock options           |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  | 10,576  |   |                                            |   |       |       |  |   |        |   |  |   |         |   |  |   | 10,576   |  
|Dividends                                |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   |       |       |  |   | (8,817  | ) |  |   |         |   |  |   | (8,817   | )
|Comprehensive income:                    |  |                      |        |              |        |        |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                            |   |        |       |  |   |         |   |  |   |          |   |  |   |          |  
|Net income                               |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   |       |       |  |   | 90,896  |   |  |   |         |   |  |   | 90,896   |  
|Contract settlements reclassed to income |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   |       |       |  |   |        |   |  |   | 29,616   |   |  |   | 29,616   |  
|Change in unrealized hedging losses      |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   |       |       |  |   |        |   |  |   | (89,963  | ) |  |   | (89,963  | )
|                                         |  |                      |        |              |        |        |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                            |   |        |       |  |   |         |   |  |   |          |   |  |   |          |  
|Total comprehensive income               |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   |       |       |  |   | 90,896  |   |  |   | (60,347  | ) |  |   | 30,549   |  
|                                         |  |                      |        |              |        |        |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                            |   |        |       |  |   |         |   |  |   |          |   |  |   |          |  
|Balance, 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 grants             |  |                      |       |              |       |        |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                            |   | 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, December 31, 2004               |  | $                    |       |              | 72,782 |        |               | $ | 728 |                              |  | $ | (6,945               | ) |  | $                | 207,017 |   |                                            | $ | (1,011 | )     |  | $ | 341,492 |   |  | $ | (130,462 | ) |  | $ | 410,819  |  
|                                         |  |                      |        |              |        |        |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                            |   |        |       |  |   |         |   |  |   |          |   |  |   |          |  



The accompanying notes
are an integral part of these financial statements.



F-5



---



PATINA OIL & GAS CORPORATION



CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|-------------------------------------------------------------------------------- |  | ----------------------- | -------- | - | ---- | - | -------- | ---- |  | - | -------- | -
|                                                                                 |  | Year Ended December 31, |         
|                                                                                 |  | 2002                    |          |   | 2003 |   |          | 2004 | 
|Operating activities                                                             |  |                         |          |   |      |   |          |      |  |   |          |  
|Net income                                                                       |  | $                       | 57,707   |   |      | $ | 90,896   |      |  | $ | 150,963  |  
|Adjustments to reconcile net income to net cash provided by operating activities |  |                         |          |   |      |   |          |      |  |   |          |  
|Cumulative effect of change in accounting principle, net of tax                  |  |                         |         |   |      |   | 2,613    |      |  |   |         |  
|Exploration expense                                                              |  |                         | 2,171    |   |      |   | 6,207    |      |  |   | 278      |  
|Depletion, depreciation and amortization                                         |  |                         | 66,162   |   |      |   | 98,119   |      |  |   | 126,849  |  
|Deferred income taxes                                                            |  |                         | 22,372   |   |      |   | 32,104   |      |  |   | 62,917   |  
|Tax benefit from exercise of stock options                                       |  |                         | 3,496    |   |      |   | 10,576   |      |  |   | 10,744   |  
|Impairment of oil and gas hedges                                                 |  |                         | (4,077   | ) |      |   |         |      |  |   |         |  
|Deferred compensation adjustment                                                 |  |                         | 9,983    |   |      |   | 33,110   |      |  |   | 31,722   |  
|Loss (gain) on deferred compensation asset                                       |  |                         | 995      |   |      |   | (1,751   | )    |  |   | (3,480   | )
|Loss (gain) on sale of oil and gas properties                                    |  |                         |         |   |      |   | 7,223    |      |  |   | (7,938   | )
|Other                                                                            |  |                         | 70       |   |      |   | 734      |      |  |   | 2,632    |  
|Changes in current and other assets and liabilities                              |  |                         |          |   |      |   |          |      |  |   |          |  
|Decrease (increase) in                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|Accounts receivable                                                              |  |                         | (11,379  | ) |      |   | (21,126  | )    |  |   | (23,470  | )
|Inventory and other                                                              |  |                         | (615     | ) |      |   | (10,421  | )    |  |   | (7,613   | )
|Increase (decrease) in                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|Accounts payable                                                                 |  |                         | 8,656    |   |      |   | 14,298   |      |  |   | 44,373   |  
|Income taxes payable                                                             |  |                         |         |   |      |   |         |      |  |   | (5,708   | )
|Accrued liabilities                                                              |  |                         | 360      |   |      |   | 1,674    |      |  |   | 9,189    |  
|Other assets and liabilities                                                     |  |                         | (3,744   | ) |      |   | 7,569    |      |  |   | 5,111    |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash provided by operating activities                                        |  |                         | 152,157  |   |      |   | 271,825  |      |  |   | 396,569  |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Investing activities                                                             |  |                         |          |   |      |   |          |      |  |   |          |  
|Development and exploration                                                      |  |                         | (99,598  | ) |      |   | (176,136 | )    |  |   | (253,862 | )
|Acquisitions, net of cash acquired                                               |  |                         | (182,509 | ) |      |   | (307,326 | )    |  |   | (29,322  | )
|Disposition of oil and gas properties                                            |  |                         | 2,303    |   |      |   | 16,943   |      |  |   | 29,003   |  
|Furniture, fixtures, and equipment                                               |  |                         | (2,588   | ) |      |   | (4,362   | )    |  |   | (4,460   | )
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash used in investing activities                                            |  |                         | (282,392 | ) |      |   | (470,881 | )    |  |   | (258,641 | )
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Financing activities                                                             |  |                         |          |   |      |   |          |      |  |   |          |  
|Proceeds from borrowings on revolving credit facility                            |  |                         | 250,375  |   |      |   | 567,625  |      |  |   | 513,000  |  
|Repayments of borrowings on revolving credit facility                            |  |                         | (127,375 | ) |      |   | (351,625 | )    |  |   | (632,000 | )
|Loan origination fees                                                            |  |                         |         |   |      |   | (1,574   | )    |  |   |         |  
|Issuance of common stock                                                         |  |                         | 14,427   |   |      |   | 9,302    |      |  |   | 13,542   |  
|Repurchase of common stock                                                       |  |                         | (9       | ) |      |   | (17,230  | )    |  |   | (14,734  | )
|Common stock dividends                                                           |  |                         | (5,513   | ) |      |   | (8,817   | )    |  |   | (15,257  | )
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash provided by (used in) financing activities                              |  |                         | 131,905  |   |      |   | 197,681  |      |  |   | (135,449 | )
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Increase (decrease) in cash                                                      |  |                         | 1,670    |   |      |   | (1,375   | )    |  |   | 2,479    |  
|Cash and equivalents, beginning of period                                        |  |                         | 250      |   |      |   | 1,920    |      |  |   | 545      |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Cash and equivalents, end of period                                              |  | $                       | 1,920    |   |      | $ | 545      |      |  | $ | 3,024    |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  



The accompanying notes
are an integral part of these financial statements.



F-6



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PATINA OIL & GAS CORPORATION



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



|(1) | ORGANIZATION AND NATURE OF BUSINESS
|--- | -----------------------------------



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. See Note (4).



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



The Companys operations currently consist of the acquisition, development, exploitation and production of oil and gas properties. Historically,
Patinas properties were primarily located in the Wattenberg Field of Colorados D-J Basin. 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 fourth quarter 2004 production, Wattenberg accounted for approximately 58%, Mid Continent for 31%, San
Juan for 3% and Central and Other for 8% of daily oil and gas production on an equivalent basis.



F-7



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|(2) | PENDING MERGER OF PATINA OIL & GAS CORPORATION WITH NOBLE ENERGY, INC.
|--- | ----------------------------------------------------------------------



On December 15, 2004, the boards of directors of Patina and Noble Energy approved Noble Energys merger with Patina. 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 27.3 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 stockholder 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 stockholder 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 merger is expected to be completed in the second quarter of 2005.



|(3) | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|--- | ------------------------------------------



Producing Activities



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 (see RecentAccountingPronouncements). 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.



F-8



---

Asset Retirement Costs and Obligations



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 Companys estimated obligations related to the future plugging and abandonment of the Companys wells. In addition, the Company recorded an addition to oil and gas properties of
approximately $17.2 million for the related asset retirement costs, and recorded a one-time, non-cash charge of approximately $2.6 million (net of $1.6 million of deferred taxes) for the cumulative effect of change in accounting principle. This
statement would not have had a material impact on the year ended December 31, 2002 assuming adoption on a pro forma basis.



At December 31, 2004 an asset retirement obligation of $31.5 million is recorded in Other noncurrent liabilities. A reconciliation of the changes in the
Companys liability from December 31, 2003 to December 31, 2004 is as follows (amounts in thousands):



|                                                    |  |   |        |  
|--------------------------------------------------- |  | - | ------ | -
|Asset retirement obligation as of December 31, 2003 |  | $ | 27,594 |  
|Liabilities incurred                                |  |   | 990    |  
|Liabilities settled                                 |  |   | (1,317 | )
|Accretion expense                                   |  |   | 1,499  |  
|Changes in estimates                                |  |   | 2,695  |  
|                                                    |  |   |        |  
|Asset retirement obligation as of December 31, 2004 |  | $ | 31,461 |  
|                                                    |  |   |        |  



Field equipment and other



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



Other Assets



At December 31, 2003, the
balance represented $14.1 million in assets held in a deferred compensation plan and $937,000 in unamortized loan origination costs. At December 31, 2004, the balance primarily represented $25.0 million in assets held in a deferred compensation
plan. See Note (8).



Revenue Recognition and Gas Imbalances



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, 2003 and 2004 were insignificant.



F-9



---

Accumulated Other Comprehensive Income (Loss)



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 income (loss) and related tax effects for the twelve months ended December 31, 2003 were as follows (in thousands):



|                                                  |  |       |          |   |            |   |         |           |  |   |         |  
|------------------------------------------------- |  | ----- | -------- | - | ---------- | - | ------- | --------- |  | - | ------- | -
|                                                  |  | Gross |          |   | Tax Effect |   |         | Net ofTax | 
|Accumulated other comprehensive income  12/31/02 |  | $     | 9,064    |   |            | $ | (3,263  | )         |  | $ | 5,801   |  
|Change in fair value of hedges                    |  |       | (144,809 | ) |            |   | 54,846  |           |  |   | (89,963 | )
|Contract settlements during the year              |  |       | 47,768   |   |            |   | (18,152 | )         |  |   | 29,616  |  
|                                                  |  |       |          |   |            |   |         |           |  |   |         |  
|Accumulated other comprehensive loss  12/31/03   |  | $     | (87,977  | ) |            | $ | 33,431  |           |  | $ | (54,546 | )
|                                                  |  |       |          |   |            |   |         |           |  |   |         |  



The components of
accumulated other comprehensive income (loss) and related tax effects for the twelve months ended December 31, 2004 were as follows (in thousands):



|                                                  |  |       |          |   |            |   |         |            |  |   |          |  
|------------------------------------------------- |  | ----- | -------- | - | ---------- | - | ------- | ---------- |  | - | -------- | -
|                                                  |  | Gross |          |   | Tax Effect |   |         | Net of Tax | 
|Accumulated other comprehensive income  12/31/03 |  | $     | (87,977  | ) |            | $ | 33,431  |            |  | $ | (54,546  | )
|Change in fair value of hedges                    |  |       | (268,012 | ) |            |   | 101,845 |            |  |   | (166,167 | )
|Contract settlements during the year              |  |       | 145,566  |   |            |   | (55,315 | )          |  |   | 90,251   |  
|                                                  |  |       |          |   |            |   |         |            |  |   |          |  
|Accumulated other comprehensive loss  12/31/04   |  | $     | (210,423 | ) |            | $ | 79,961  |            |  | $ | (130,462 | )
|                                                  |  |       |          |   |            |   |         |            |  |   |          |  



Comprehensive income for the years
ended December 31, 2002, 2003 and 2004 totaled $26.1 million, $30.5 million and $75.0 million, respectively.



Financial Instruments



The book value and estimated fair value of cash and equivalents was $545,000 and $3.0 million at December 31, 2003 and 2004, respectively. The book value and estimated fair value of the bank debt was $416.0 million and $297.0 million at
December 31, 2003 and 2004, respectively. The book value of these assets and liabilities approximates fair value due to their short maturity or floating rate structure of these instruments.



Derivative Instruments and Hedging Activities



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 December 31,
2004, the net unrealized pretax gains on these contracts totaled $952,000 ($590,000 gain net of $362,000 of deferred taxes) based on LIBOR futures prices at December 31, 2004.



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, recognizing losses of $3.9 million, $25.1 million, and $88.0 million in 2002, 2003 and 2004, respectively, related to these contracts. The Company entered into various swap contracts
for natural gas based on the Colorado Interstate Gas (CIG), ANR



F-10



---

Pipeline Oklahoma (ANR), Panhandle Eastern Pipeline (PEPL), and the El Paso San Juan (EPSJ) indexes, recognizing a gain
of $24.3 million in 2002, and losses of $25.3 million and $57.9 million in 2003 and 2004, respectively, related to these contracts.



At December 31, 2004, the Company was a party to swap contracts for oil based on NYMEX prices covering approximately 13,700 barrels of oil per day for
2005 at fixed prices ranging from $23.51 to $26.95 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $24.78 per barrel for 2005. The Company also entered into swap
contracts for oil for 2006 as of December 31, 2004, which are summarized in the table below. The net unrealized losses on these contracts totaled $139.0 million based on NYMEX futures prices at December 31, 2004.



At December 31, 2004, the Company was a party to swap contracts for natural
gas based on CIG, EPSJ, ANR and PEPL index prices covering approximately 132,400 MMBtus per day for 2005 at fixed prices ranging from $2.83 to $8.07 per MMBtu. The overall weighted average hedged price for the swap contracts is $4.44 per MMBtu
for 2005. The Company also entered into natural gas swap contracts for 2006 as of December 31, 2004, which are summarized in the table below. The net unrealized losses on these contracts totaled $72.4 million based on futures prices at December 31,
2004.



At December 31, 2004, the Company was a party to the fixed price swaps
summarized below:



|                    |  |                                      |  |         |                                |                                     |         |   |                   |        |         |      |                                     |   |         |  
|------------------- |  | ------------------------------------ |  | ------- | ------------------------------ | ----------------------------------- | ------- | - | ----------------- | ------ | ------- | ---- | ----------------------------------- | - | ------- | -
|                    |  | Oil Swaps (NYMEX)                    |  |         | Natural Gas Swaps (CIG Index)  |                                    
|Time Period         |  | DailyVolumeBbl                       |  | $/Bbl   |                                | UnrealizedGain (Loss)($/thousands)  |         |   | DailyVolumeMMBtu  |        | $/MMBtu |      | UnrealizedGain (Loss)($/thousands)  |  
|01/01/05 - 03/31/05 |  | 13,700                               |  | 25.07   |                                | $                                   | (22,720 | ) |                   | 90,000 |         | 4.85 |                                     | $ | (5,242  | )
|04/01/05 - 06/30/05 |  | 13,700                               |  | 24.80   |                                |                                     | (22,636 | ) |                   | 80,000 |         | 3.83 |                                     |   | (10,612 | )
|07/01/05 - 09/30/05 |  | 13,700                               |  | 24.67   |                                |                                     | (22,195 | ) |                   | 80,700 |         | 3.84 |                                     |   | (12,393 | )
|10/01/05 - 12/31/05 |  | 13,700                               |  | 24.60   |                                |                                     | (21,527 | ) |                   | 80,700 |         | 4.13 |                                     |   | (12,428 | )
|                    |  |                                      |  |         |                                |                                    
|2006                |  | 9,900                                |  | 26.66   |                                |                                     | (49,912 | ) |                   | 35,000 |         | 4.67 |                                     |   | (10,526 | )
|                    |  |                                     
|                    |  | Natural Gas Swaps (ANR/PEPL Indexes) |  |         | Natural Gas Swaps (EPSJ Index) |                                    
|Time Period         |  | DailyVolume MMBtu                    |  | $/MMBtu |                                | UnrealizedGain (Loss) ($/thousands) |         |   | DailyVolume MMBtu |        | $/MMBtu |      | UnrealizedGain (Loss) ($/thousands) |  
|01/01/05 - 03/31/05 |  | 48,100                               |  | 5.88    |                                | $                                   | 865     |   |                   | 9,050  |         | 4.71 |                                     | $ | (613    | )
|04/01/05 - 06/30/05 |  | 38,100                               |  | 4.63    |                                |                                     | (3,379  | ) |                   | 9,050  |         | 3.97 |                                     |   | (1,098  | )
|07/01/05 - 09/30/05 |  | 38,100                               |  | 4.58    |                                |                                     | (4,015  | ) |                   | 9,050  |         | 3.99 |                                     |   | (1,298  | )
|10/01/05 - 12/31/05 |  | 38,100                               |  | 4.77    |                                |                                     | (4,571  | ) |                   | 9,050  |         | 4.22 |                                     |   | (1,345  | )
|                    |  |                                      |  |         |                                |                                    
|2006                |  | 16,700                               |  | 5.02    |                                |                                     | (4,508  | ) |                   | 3,650  |         | 4.61 |                                     |   | (1,220  | )



The Company is
required to provide margin deposits to its counterparties when the unrealized losses on its oil and gas hedges exceed the credit thresholds established by its counterparties. At December 31, 2003 and 2004, the Company had $9.9 million and $11.9
million, respectively, on deposit with its 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



F-11



---

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 2004, net hedging losses of
$145.6 million ($90.3 million after tax) were reclassified from Accumulated other comprehensive income to earnings and the changes in the fair value of outstanding derivative net liabilities increased by $268.0 million ($166.2 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 2004.



As of December 31, 2004, the Company had
net unrealized hedging losses of $210.4 million ($130.5 million after tax), comprised of $7.3 million of current assets, $151.5 million of current liabilities and $66.2 million of non-current liabilities. Based on estimated future prices as of
December 31, 2004, the Company expects to reclassify as a decrease to earnings during the next twelve months $144.3 million ($89.4 million after tax) of net unrealized hedging losses from Accumulated other comprehensive loss.



Stock Options, Awards and Deferred Compensation Arrangements



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 (8). The Company accounts for assets held in a deferred compensation plan in accordance with EITF 97-14. See Note (8).



The Company applies APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations in
accounting for the plans. As all stock options have been issued at the market price on the date of grant, no compensation cost has been recognized for these stock option plans. Had compensation cost for the Companys stock option plans been
determined consistent with SFAS No. 123, Accounting for Stock-Based Compensation, the Companys net income (in thousands) and earnings per share would have been reduced to the pro forma amounts indicated below for the years ended
December 31, 2002, 2003, and 2004, respectively:



|                                    |  |             |  |      |        |      |   |        |  |   |        
|----------------------------------- |  | ----------- |  | ---- | ------ | ---- | - | ------ |  | - | -------
|                                    |  |             |  | 2002 |        | 2003 |   | 2004  
|Net income                          |  | As Reported |  | $    | 57,707 |      | $ | 90,896 |  | $ | 150,963
|                                    |  | Pro forma   |  |      | 54,742 |      |   | 86,726 |  |   | 145,457
|Basic net income per common share   |  | As Reported |  | $    | 0.88   |      | $ | 1.33   |  | $ | 2.15   
|                                    |  | Pro forma   |  |      | 0.83   |      |   | 1.27   |  |   | 2.07   
|Diluted net income per common share |  | As Reported |  | $    | 0.84   |      | $ | 1.28   |  | $ | 2.05   
|                                    |  | Pro forma   |  |      | 0.79   |      |   | 1.22   |  |   | 1.98   



The fair value of each option grant is
estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 2002, 2003 and 2004: dividend yield of 1%, 1% and 1%; expected volatility of 46%, 45% and 29%; risk-free
interest rate of 4.2%, 2.7% and 3.1%; and expected life of 3.8 years, 3.7 years and 3.8 years, respectively.



Per Share Data



In June 2002, the Company declared a 5-for-4 stock split which was affected in the form of a 25% stock dividend to common stockholders. In June 2003, the
Company declared another 5-for-4 stock split which was effected in the form of a 25% stock dividend to common stockholders. 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 5-for-4 stock dividends and 2-for-1 stock split.



F-12



---

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 (7).



Risks and Uncertainties



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.



Supplemental Cash Flow Information



Over the
past three years, the Company incurred the following significant non-cash costs (in thousands):



|                                                          |  |                         |       |      |   |       |  |   |    
|--------------------------------------------------------- |  | ----------------------- | ----- | ---- | - | ----- |  | - | ---
|                                                          |  | Year Ended December 31,
|                                                          |  | 2002                    |       | 2003 |   | 2004 
|Stock Purchase Plan                                       |  | $                       | 1,662 |      | $ |      |  | $ |   
|Restricted Stock Grant                                    |  |                         |      |      |   | 861   |  |   | 832
|401(k) profit sharing contribution in Common Stock        |  |                         | 801   |      |   |      |  |   |   
|Issuance of Common Stock/warrants related to acquisitions |  |                         | 5,779 |      |   | 4,000 |  |   |   



Other



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



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



Recent Accounting Pronouncements



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



In November 2002, the FASB issued Interpretation No. 45 (FIN 45),
Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN 45 requires a guarantor to recognize a liability for the fair value of the obligation it assumes under
certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure under the guarantee, the current carrying
amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are effective for financial statements for both
interim and annual periods ending after December 15, 2002. The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The adoption of this Statement did not have
a material impact on the Companys financial position or results of operations.



F-13



---

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation 
Transition and Disclosure  an amendment of SFAS No. 123. SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee
compensation. In addition, this statement amends the disclosure requirements of SFAS No. 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect
of the method used on the reported results. SFAS No. 148 is effective for the Companys year ended December 31, 2002 and for interim financial statements commencing in 2003. The Companys adoption of this pronouncement did not have an
impact on financial condition or results of operations.



In
April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain
derivative instruments embedded in other contracts and for hedging activities under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. SFAS No. 149 is generally effective for contracts entered into or
modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The adoption of this pronouncement did not have an impact on the Companys financial condition or results of operations.



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



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 the third quarter of 2005. 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 2004, 2003, and 2002 were $10.7 million, $10.6 million, and $3.5 million, respectively.



F-14



---

|(4) | ACQUISITIONS
|--- | ------------



In October 2003, the Company acquired the assets of Cordillera Energy Partners, L.L.C. (Cordillera) for $239.0 million in cash funded with
borrowings under the Companys bank facility and the issuance of five year warrants to purchase 1,000,000 shares of the Companys Common Stock for $22.50 per share. Cordilleras properties are located primarily in the Mid Continent,
the San Juan Basin, and the Permian Basin. The Cordillera properties produce primarily gas.



The Cordillera acquisition was recorded using the purchase method of accounting and the results of operations from the acquisition are included with the results of the Company from the acquisition date. The table
below summarizes the preliminary allocation of the purchase price of the transaction based upon the acquisition date fair values of the assets acquired and the liabilities assumed (in thousands):



|                              |  |            |         |  
|----------------------------- |  | ---------- | ------- | -
|                              |  | Cordillera |        
|Purchase Price:               |  |            |         |  
|Cash paid                     |  | $          | 238,969 |  
|Warrants issued               |  |            | 4,000   |  
|                              |  |            |         |  
|Total                         |  | $          | 242,969 |  
|                              |  |            |         |  
|Allocation of Purchase Price: |  |            |         |  
|Working capital               |  | $          | (676    | )
|Oil and gas properties        |  |            | 285,183 |  
|Other non-current assets      |  |            | 410     |  
|Deferred income taxes         |  |            | (39,800 | )
|Other non-current liabilities |  |            | (2,148  | )
|                              |  |            |         |  
|Total                         |  | $          | 242,969 |  
|                              |  |            |         |  



The following table
reflects the unaudited pro forma results of operations for the twelve months ended December 31, 2003 as though the Cordillera acquisition had occurred on January 1, 2003 (in thousands, except per share amounts):



|                                      |  |            |         |           |   |                       |  |   |        
|------------------------------------- |  | ---------- | ------- | --------- | - | --------------------- |  | - | -------
|Year ended December 31, 2003          |  | Historical |         | Pro Forma |   | Pro FormaConsolidated
|Revenues                              |  | $          | 406,717 |           | $ | 33,848                |  | $ | 440,565
|Net income                            |  |            | 90,896  |           |   | 5,736                 |  |   | 96,632 
|Net income per common share  basic   |  |            | 1.33    |           |   |                       |  |   | 1.42   
|Net income per common share  diluted |  |            | 1.28    |           |   |                       |  |   | 1.36   



The pro forma amounts
above are presented for information purposes only and are not necessarily indicative of the results which would have occurred had the Cordillera acquisition been consummated on January 1, 2003, nor are the pro forma amounts necessarily indicative of
the future results of operations of the Company.



F-15



---

|(5) | OIL AND GAS PROPERTIES
|--- | ----------------------



The cost of oil and gas properties at December 31, 2003 and 2004 included approximately $2.5 million and $9.1 million, respectively, in net unevaluated
leasehold 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, 2002, 2003, and 2004. The following
table sets forth costs incurred related to oil and gas properties:



|                          |  |                                         |         |   |      |   |         |      |  |   |         |  
|------------------------- |  | --------------------------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                          |  | 2002                                    |         |   | 2003 |   |         | 2004 | 
|                          |  | (In thousands, except per Mcfe amounts) |        
|Development               |  | $                                       | 97,428  |   |      | $ | 169,929 |      |  | $ | 253,862 |  
|Acquisition - proven      |  |                                         | 182,008 |   |      |   | 305,833 |      |  |   | 20,176  |  
|Acquisition - unproven    |  |                                         | 500     |   |      |   | 1,493   |      |  |   | 9,146   |  
|Exploration and other     |  |                                         | 2,171   |   |      |   | 6,207   |      |  |   | 2,058   |  
|                          |  |                                         |         |   |      |   |         |      |  |   |         |  
|                          |  | $                                       | 282,107 |   |      | $ | 483,462 |      |  | $ | 285,242 |  
|                          |  |                                         |         |   |      |   |         |      |  |   |         |  
|Asset retirement costs    |  | $                                       |        |   |      | $ | 3,761   |      |  | $ | 3,685   |  
|                          |  |                                         |         |   |      |   |         |      |  |   |         |  
|Disposition of properties |  | $                                       | (2,303  | ) |      | $ | (16,943 | )    |  | $ | (29,003 | )
|                          |  |                                         |         |   |      |   |         |      |  |   |         |  
|Depletion rate (per Mcfe) |  | $                                       | 0.93    |   |      | $ | 0.94    |      |  | $ | 1.04    |  
|                          |  |                                         |         |   |      |   |         |      |  |   |         |  



The disposition of
properties in 2003 primarily relates to the sale of Elysium properties in Louisiana for $8.4 million, $4.8 million for sales of certain Wattenberg properties, and $3.2 million for the sale of the Companys Utah properties. The disposition of
properties in 2004 primarily relates to the sale of the 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.



In conjunction with the Le Norman and Bravo acquisitions in 2002, and the Cordillera acquisition in 2003, the Company recorded additions to oil and gas
properties of $4.5 million, $40.7 million, and $39.8 million, respectively, as a result of the deferred tax liability for the difference between the tax basis of the properties acquired and the book basis attributed to the properties under the
purchase method of accounting. See Note (4). In conjunction with the acquisition of the remaining 70% interest in LNP in March 2003, $4.6 million representing the value assigned for the 30% reversionary interest in LNP which the Company acquired in
conjunction with the Le Norman acquisition was recorded in oil and gas properties. During 2003, the Company exchanged its interest in the Wyoming grassroots project for certain oil and gas properties in Wattenberg. No gain or loss was recognized on
the exchange.



During 2003, the Company recorded an addition to
oil and gas properties of approximately $17.2 million for the asset retirement costs related to the adoption of SFAS No. 143. During 2003 and 2004, additions to oil and gas properties of approximately $3.8 million and $3.7 million 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.



F-16



---

|(6) | INDEBTEDNESS
|--- | ------------



The following indebtedness was outstanding on the respective dates:



|                     |  |                |         |      |   |        
|-------------------- |  | -------------- | ------- | ---- | - | -------
|                     |  | December 31,  
|                     |  | 2003           |         | 2004
|                     |  | (In thousands)
|Bank debt            |  | $              | 416,000 |      | $ | 297,000
|Less current portion |  |                |        |      |   |       
|                     |  |                |         |      |   |        
|Bank debt, net       |  | $              | 416,000 |      | $ | 297,000
|                     |  |                |         |      |   |        



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 December 31, 2004. A total of $203.0 million was available under the Credit Agreement at December 31, 2004.



The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the LIBOR rate for one, two, three or six months
plus a margin which fluctuates from 1.25% to 1.90%, or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.65%. The margins are determined by a debt to EBITDA ratio, as defined. The weighted average interest rate under the facility
was 2.9% during 2004 and 3.6% at December 31, 2004.



The Credit
Agreement contains financial covenants, including but not limited to a maximum total debt to EBITDA ratio, as defined, and a minimum current ratio. It also contains negative covenants, including but not limited to restrictions on indebtedness;
certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers; changes in fiscal year; transactions with
affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge causes; issuance of securities; and
non-speculative commodity hedging. At December 31, 2003 and 2004, the Company was in compliance with the covenants. Borrowings under the Credit Agreement mature in January 2007, but may be prepaid at anytime. The Company had a restricted payment
basket under the Credit Agreement of $125.5 million as of December 31, 2004, which may be used to repurchase equity securities, pay dividends or make other restricted payments.



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.



Scheduled maturities of indebtedness for the next five years are zero in 2005, 2006, and $297.0 million in the first quarter of 2007 and zero in 2008 and
2009. Management intends to extend the maturity of its credit facility on a regular basis; however, there can be no assurance it will be able to do so. Cash payments for interest totaled $1.9 million, $6.6 million and $11.5 million during 2002, 2003
and 2004, respectively.



F-17



---

|(7) | STOCKHOLDERS EQUITY
|--- | --------------------



A total of 250.0 million common shares, $0.01 par value, are authorized of which 72.8 million were issued at December 31, 2004. The Common Stock is listed
on the New York Stock Exchange. In June 2002, a 5-for-4 stock split was affected in the form of a 25% stock dividend to common stockholders. In June 2003, another 5-for-4 stock split was affected in the form of a 25% stock dividend to common
stockholders. 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
5-for-4 stock dividends and 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, 2002:



|                                               |  |            |   |  |            |   |  |            |  
|---------------------------------------------- |  | ---------- | - |  | ---------- | - |  | ---------- | -
|                                               |  | 2002       |   |  | 2003       |   |  | 2004       |  
|Beginning shares                               |  | 66,381,100 |   |  | 70,324,400 |   |  | 71,505,000 |  
|Exercise of stock options                      |  | 2,524,900  |   |  | 2,214,600  |   |  | 1,925,500  |  
|Issued under Stock Purchase Plan               |  | 557,500    |   |  |           |   |  |           |  
|Issued in lieu of salaries and bonuses         |  | 246,100    |   |  | 142,200    |   |  |           |  
|Issued for directors fees                      |  | 5,800      |   |  | 5,400      |   |  | 700        |  
|Issued for Le Norman acquisition               |  | 513,200    |   |  |           |   |  |           |  
|Issued to deferred compensation plan           |  | 36,000     |   |  |           |   |  |           |  
|Vesting of stock grant                         |  |           |   |  |           |   |  | 18,300     |  
|Contributed to 401(k) plan                     |  | 60,500     |   |  |           |   |  |           |  
|                                               |  |            |   |  |            |   |  |            |  
|Total shares issued                            |  | 3,944,000  |   |  | 2,362,200  |   |  | 1,944,500  |  
|Repurchases                                    |  | (700       | ) |  | (1,181,600 | ) |  | (667,800   | )
|                                               |  |            |   |  |            |   |  |            |  
|Ending shares                                  |  | 70,324,400 |   |  | 71,505,000 |   |  | 72,781,700 |  
|Treasury shares held in deferred comp (Note 8) |  | (2,590,700 | ) |  | (2,481,800 | ) |  | (2,097,900 | )
|                                               |  |            |   |  |            |   |  |            |  
|Adjusted shares outstanding                    |  | 67,733,700 |   |  | 69,023,200 |   |  | 70,683,800 |  
|                                               |  |            |   |  |            |   |  |            |  



Adjusted for the stock
dividends and splits, following is a schedule of quarterly cash dividends paid on the Common Stock since the dividend was initiated in December 1997:



|     |  |         |        |        |   |        |  |        |        |       |   |        |  |   |       
|---- |  | ------- | ------ | ------ | - | ------ |  | ------ | ------ | ----- | - | ------ |  | - | ------
|     |  | Quarter |        |       
|     |  | First   |        | Second |   | Third  |  | Fourth |        | Total
|1997 |  | $       |       |        | $ |       |  | $      |       |       | $ | 0.0032 |  | $ | 0.0032
|1998 |  |         | 0.0032 |        |   | 0.0032 |  |        | 0.0032 |       |   | 0.0032 |  |   | 0.0128
|1999 |  |         | 0.0032 |        |   | 0.0032 |  |        | 0.0032 |       |   | 0.0064 |  |   | 0.0160
|2000 |  |         | 0.0064 |        |   | 0.0064 |  |        | 0.0064 |       |   | 0.0128 |  |   | 0.0320
|2001 |  |         | 0.0128 |        |   | 0.0128 |  |        | 0.0128 |       |   | 0.0160 |  |   | 0.0544
|2002 |  |         | 0.0160 |        |   | 0.0200 |  |        | 0.0200 |       |   | 0.0240 |  |   | 0.0800
|2003 |  |         | 0.0240 |        |   | 0.0300 |  |        | 0.0300 |       |   | 0.0400 |  |   | 0.1240
|2004 |  |         | 0.0500 |        |   | 0.0500 |  |        | 0.0500 |       |   | 0.0600 |  |   | 0.2100



During 2002, 2003 and
2004, the Company repurchased and retired shares of its Common Stock for $9,000, $17.2 million and $14.7 million, respectively. 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 December 31, 2004, all of the Warrants were
outstanding. The Warrants expire on October 1, 2008.



F-18



---

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



In September 2003,
the Compensation Committee of the Board of Directors awarded restricted stock grants totaling 47,500 shares of Common Stock to the officers and directors of the Company in lieu of the suspended Stock Purchase Plan. See Note (8). 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. On July 19, 2004, the Board of Directors issued 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):



|                                                |  |                         |        |              |        |          |   |           |  |              |        |          |        |           |   |              |  |          |         |  |        |  |   |     
|----------------------------------------------- |  | ----------------------- | ------ | ------------ | ------ | -------- | - | --------- |  | ------------ | ------ | -------- | ------ | --------- | - | ------------ |  | -------- | ------- |  | ------ |  | - | ----
|                                                |  | Year Ended December 31,
|                                                |  | 2002                    |        | 2003         |        | 2004    
|                                                |  | NetIncome               |        | CommonShares |        | PerShare |   | NetIncome |  | CommonShares |        | PerShare |        | NetIncome |   | CommonShares |  | PerShare
|Net income                                      |  | $                       | 57,707 |              | 65,933 |          |   |           |  | $            | 90,896 |          | 68,170 |           |   |              |  | $        | 150,963 |  | 70,234 |  |   |     
|                                                |  |                         |        |              |        |          |   |           | 
|Basic net income attributable to Common Stock   |  |                         | 57,707 |              | 65,933 |          | $ | 0.88      |  |              | 90,896 |          | 68,170 |           | $ | 1.33         |  |          | 150,963 |  | 70,234 |  | $ | 2.15
|                                                |  |                         |        |              |        |          |   |           |  |              |        |          |        |           |   |              |  |          |         |  |        |  |   |     
|Effect of dilutive securities:                  |  |                         |        |              |        |          |   |           |  |              |        |          |        |           |   |              |  |          |         |  |        |  |   |     
|Stock options                                   |  |                         |       |              | 3,037  |          |   |           |  |              |       |          | 2,892  |           |   |              |  |          |        |  | 2,984  |  |   |     
|Unvested stock grant                            |  |                         |       |              |       |          |   |           |  |              |       |          |       |           |   |              |  |          |        |  | 57     |  |   |     
|$22.50 Common Stock warrants                    |  |                         |       |              |       |          |   |           |  |              |       |          |       |           |   |              |  |          |        |  | 198    |  |   |     
|                                                |  |                         |        |              |        |          |   |           |  |              |        |          |        |           |   |              |  |          |         |  |        |  |   |     
|Diluted net income attributable to Common Stock |  | $                       | 57,707 |              | 68,970 |          | $ | 0.84      |  | $            | 90,896 |          | 71,062 |           | $ | 1.28         |  | $        | 150,963 |  | 73,473 |  | $ | 2.05
|                                                |  |                         |        |              |        |          |   |           |  |              |        |          |        |           |   |              |  |          |         |  |        |  |   |     



At December 31, 2004,
all stock options and warrants were included in the computation of diluted earnings per share because they were all dilutive. At December 31, 2003, all stock options were included in the computation of diluted earnings per share because they were
all dilutive. However, the 1,000,000 five year Warrants to purchase Common Stock at $22.50 per share were excluded from the 2003 computation of diluted earnings per share because they were anti-dilutive.



|(8) | EMPLOYEE BENEFIT PLANS
|--- | ----------------------



401(k) Plan



The Company maintains a profit sharing and 401(k) savings plan (the 401(k) Plan). Eligible employees may make voluntary contributions to the
401(k) Plan. In addition, the Company may, at its discretion, make matching or profit sharing contributions to the 401(k) Plan. The Company made profit sharing contributions of $801,000, $1.4 million and $1.8 million for 2002, 2003 and 2004,
respectively. The contributions in 2002 were made in Common Stock while the 2003 and 2004 contributions were made in cash. A total of 60,500 shares of Common Stock were contributed in 2002.



F-19



---

Stock Purchase Plan



The Company maintains a shareholder approved stock purchase plan (Stock Purchase Plan). Pursuant to the Stock Purchase Plan, officers and
directors are granted options to purchase shares of Common Stock at prices ranging from 50% to 85% of the closing price of the stock on the trading day prior to the date of purchase (Market Price). To date, all purchase prices have been
set at 75% of Market Price. In addition, employee participants may be granted the right to purchase shares pursuant to the Stock Purchase Plan with all or a part of their salary and bonus. A total of 1,562,500 shares of Common Stock are reserved for
possible purchase under the Stock Purchase Plan. In May 1999, an amendment to the Stock Purchase Plan was approved by the stockholders allowing for the annual renewal of the 1,562,500 shares of Common Stock reserved for possible purchase under the
Stock Purchase Plan. Plan years run from the date of the Annual Meeting through the next Annual Meeting. In 2002, the Board of Directors approved 442,500 common shares (exclusive of shares available for purchase with participants salaries and
bonuses) for possible purchase by participants during the plan year. As of December 31, 2002, participants had purchased 557,500 shares of Common Stock at an average price of $11.92 per share ($8.94 net price per share), resulting in cash proceeds
to the Company of $5.0 million. The Company recorded non-cash general and administrative expenses of $1.7 million associated with these purchases for 2002. The Stock Purchase Plan was suspended as of December 31, 2002.



Deferred Compensation Plan



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 the Common Stock. At December 31, 2004, the balance of the assets in the Trust totaled $103.6 million, including 2,097,912 shares of Common
Stock valued at $78.7 million. The Company accounts for the Deferred Compensation Plan in accordance with Emerging Issues Task Force (EITF) Abstract 97-14, Accounting for Deferred Compensation Arrangements Where Amounts Earned are
Held in a Rabbi Trust and Invested.



Assets of the Trust,
other than Common Stock of the Company, are invested in 11 mutual funds that cover 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, 2003 and 2004, was $14.1 million and $25.0 million, respectively, and is classified as Other Assets in the
accompanying consolidated balance sheets. The amounts payable to the plan participants at December 31, 2003 and 2004, including the market value of the shares of the Companys Common Stock that are reflected as treasury stock, was $74.9 million
and $103.6 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 December 31, 2004.



F-20



---

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 $10.0 million, $33.1 million,
and $31.7 million in 2002, 2003 and 2004, respectively.



Equity Plans



The Company maintains a shareholder approved stock option
plan for employees (the Employee Plan) providing for the issuance of options at prices not less than fair market value at the date of grant. Options to acquire the greater of 9.4 million shares of Common Stock or 10% of outstanding
diluted common shares may be outstanding at any time. The specific terms of grant and exercise are determinable by the Compensation Committee of the Board of Directors. The options vest 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:



|     |  |                |  |                        |  |                              |      
|---- |  | -------------- |  | ---------------------- |  | ---------------------------- | -----
|Year |  | OptionsGranted |  | Rangeof ExercisePrices |  | WeightedAverageExercisePrice
|2002 |  | 2,305,000      |  | $8.25  $12.66         |  | $                            | 8.41 
|2003 |  | 2,122,000      |  | $13.59  $17.13        |  | $                            | 13.62
|2004 |  | 1,762,000      |  | $25.84  $30.93        |  | $                            | 26.06



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 5,800 shares were issued in 2002, 5,400 in 2003, and 700 in 2004. 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:



|     |  |                |  |                        |  |                              |      
|---- |  | -------------- |  | ---------------------- |  | ---------------------------- | -----
|Year |  | OptionsGranted |  | Rangeof ExercisePrices |  | WeightedAverageExercisePrice
|2002 |  | 78,100         |  | $11.30 - $12.80        |  | $                            | 11.60
|2003 |  | 78,100         |  | $15.39                 |  | $                            | 15.39
|2004 |  | 67,500         |  | $26.23 - $26.81        |  | $                            | 26.68



F-21



---

A summary of the status of the Companys stock option plans as of December 31, 2002, 2003 and 2004
and changes during the years are presented below:



|                                                               |  |            |   |      |                              |      |        |            |   |                              |   |        |  |            |                              |  |   |      
|-------------------------------------------------------------- |  | ---------- | - | ---- | ---------------------------- | ---- | ------ | ---------- | - | ---------------------------- | - | ------ |  | ---------- | ---------------------------- |  | - | -----
|                                                               |  | 2002       |   | 2003 |                              | 2004
|                                                               |  | Shares     |   |      | WeightedAverageExercisePrice |      | Shares |            |   | WeightedAverageExercisePrice |   | Shares |  |            | WeightedAverageExercisePrice
|Outstanding at beginning of year                               |  | 6,879,000  |   |      | $                            | 3.83 |        | 6,565,000  |   |                              | $ | 5.72   |  | 6,458,000  |                              |  | $ | 9.19 
|Granted                                                        |  | 2,383,000  |   |      |                              | 8.51 |        | 2,200,000  |   |                              |   | 13.68  |  | 1,830,000  |                              |  |   | 26.09
|Exercised                                                      |  | (2,525,000 | ) |      |                              | 3.06 |        | (2,214,000 | ) |                              |   | 3.32   |  | (1,926,000 | )                            |  |   | 7.10 
|Forfeited                                                      |  | (172,000   | ) |      |                              | 7.72 |        | (93,000    | ) |                              |   | 10.18  |  | (119,000   | )                            |  |   | 16.32
|                                                               |  |            |   |      |                              |      |        |            |   |                              |   |        |  |            |                              |  |   |      
|Outstanding at end of year                                     |  | 6,565,000  |   |      | $                            | 5.72 |        | 6,458,000  |   |                              | $ | 9.19   |  | 6,243,000  |                              |  | $ | 14.66
|                                                               |  |            |   |      |                              |      |        |            |   |                              |   |        |  |            |                              |  |   |      
|Options exercisable at year-end                                |  | 2,421,000  |   |      |                              |      |        | 2,031,000  |   |                              |   |        |  | 2,133,000  |                              |  |   |      
|                                                               |  |            |   |      |                              |      |        |            |   |                              |   |        |  |            |                              |  |   |      
|Weighted-average fair value of options granted during the year |  |            |   |      | $                            | 3.18 |        |            |   |                              | $ | 4.83   |  |            |                              |  | $ | 6.56 



The following table summarizes
information about stock options outstanding at December 31, 2004:



|                   |  |                                      |  |                                       |  |                               |       |                                     |           |                               |   |      
|------------------ |  | ------------------------------------ |  | ------------------------------------- |  | ----------------------------- | ----- | ----------------------------------- | --------- | ----------------------------- | - | -----
|                   |  | Options Outstanding                  |  | Options Exercisable                  
|Exercise Price     |  | NumberOutstanding atDecember 31,2004 |  | Weighted-Avg.RemainingContractualLife |  | Weighted-AverageExercisePrice |       | NumberExercisableatDecember 31,2004 |           | Weighted-AverageExercisePrice
|$  2.94 to $  8.10 |  | 968,000                              |  | 0.7 years                             |  | $                             | 5.53  |                                     | 968,000   |                               | $ | 5.53 
|$  8.25 to $12.80  |  | 1,646,000                            |  | 2.1 years                             |  |                               | 8.62  |                                     | 787,000   |                               |   | 8.77 
|$13.59 to $15.39   |  | 1,818,000                            |  | 3.2 years                             |  |                               | 13.67 |                                     | 373,000   |                               |   | 13.70
|$17.13 to $30.93   |  | 1,811,000                            |  | 4.2 years                             |  |                               | 26.01 |                                     | 5,000     |                               |   | 17.13
|                   |  |                                      |  |                                       |  |                               |       |                                     |           |                               |   |      
|$  2.94 to $30.93  |  | 6,243,000                            |  | 2.8 years                             |  | $                             | 14.66 |                                     | 2,133,000 |                               | $ | 8.18 
|                   |  |                                      |  |                                       |  |                               |       |                                     |           |                               |   |      



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



The Company applies APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations in accounting for the plans. As
all stock options have been issued at the market price on the date of grant, no compensation cost has been recognized for these stock option plans. Had compensation cost for the Companys stock option plans been determined consistent with SFAS
No. 123, Accounting for Stock-Based Compensation, the Companys net income (in thousands) and earnings per share would have been reduced to the pro forma amounts indicated below for the years ended December 31, 2002, 2003, and 2004,
respectively:



|                                    |  |             |  |      |        |      |   |        |  |   |        
|----------------------------------- |  | ----------- |  | ---- | ------ | ---- | - | ------ |  | - | -------
|                                    |  |             |  | 2002 |        | 2003 |   | 2004  
|Net income                          |  | As Reported |  | $    | 57,707 |      | $ | 90,896 |  | $ | 150,963
|                                    |  | Pro forma   |  |      | 54,742 |      |   | 86,726 |  |   | 145,457
|Basic net income per common share   |  | As Reported |  | $    | 0.88   |      | $ | 1.33   |  | $ | 2.15   
|                                    |  | Pro forma   |  |      | 0.83   |      |   | 1.27   |  |   | 2.07   
|Diluted net income per common share |  | As Reported |  | $    | 0.84   |      | $ | 1.28   |  | $ | 2.05   
|                                    |  | Pro forma   |  |      | 0.79   |      |   | 1.22   |  |   | 1.98   



The fair value of each option grant is
estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 2002, 2003 and 2004: dividend yield of 1%, 1% and 1%; expected volatility of 46%, 45% and 29%; risk-free
interest rate of 4.2%, 2.7% and 3.1%; and expected life of 3.8 years, 3.7 years and 3.8 years, respectively.



F-22



---

|(9) | INCOME TAXES
|--- | ------------



A reconciliation of the federal statutory rate to the Companys effective rate as it applies to the tax provision for the years ended December 31,
2002, 2003 and 2004 follows:



|                                              |  |      |    |  |      |   |  |      |  
|--------------------------------------------- |  | ---- | -- |  | ---- | - |  | ---- | -
|                                              |  | 2002 |    |  | 2003 |   |  | 2004 |  
|Federal statutory rate                        |  | 35   | %  |  | 35   | % |  | 35   | %
|State income tax rate, net of federal benefit |  | 3    | %  |  | 3    | % |  | 3    | %
|Section 29 tax credits and other              |  | (3   | %) |  |     |   |  |     |  
|                                              |  |      |    |  |      |   |  |      |  
|Effective income tax rate                     |  | 35   | %  |  | 38   | % |  | 38   | %
|                                              |  |      |    |  |      |   |  |      |  



Current income tax
expense in 2004 totaled $24.6 million for federal purposes and $5.0 million for state purposes. The Company expects to utilize approximately $17.4 million of net operating loss carryforwards in 2004 to reduce current taxes.



For book purposes the components of the net deferred tax asset and liability
at December 31, 2003 and 2004 were:



|                                             |  |                |          |   |      |   |          |  
|-------------------------------------------- |  | -------------- | -------- | - | ---- | - | -------- | -
|                                             |  | 2003           |          |   | 2004 |  
|                                             |  | (In thousands) |         
|Deferred tax assets                          |  |                |          |   |      |   |          |  
|NOL and depletion carryforwards              |  | $              | 18,524   |   |      | $ | 13,080   |  
|Deferred compensation deductions             |  |                | 26,923   |   |      |   | 32,687   |  
|Alternative minimum tax credit carryforwards |  |                | 9,147    |   |      |   |         |  
|Deferred deductions and other                |  |                | 2,934    |   |      |   | 6,582    |  
|Taxes relating to unrealized hedging losses  |  |                | 33,431   |   |      |   | 82,718   |  
|Valuation allowance                          |  |                | (3,225   | ) |      |   | (3,225   | )
|                                             |  |                |          |   |      |   |          |  
|                                             |  |                | 87,734   |   |      |   | 131,842  |  
|                                             |  |                |          |   |      |   |          |  
|Deferred tax liabilities                     |  |                |          |   |      |   |          |  
|Taxes relating to unrealized hedging gains   |  |                |         |   |      |   | (2,757   | )
|Depreciable and depletable property          |  |                | (218,573 | ) |      |   | (277,741 | )
|                                             |  |                |          |   |      |   |          |  
|                                             |  |                | (218,573 | ) |      |   | (280,498 | )
|                                             |  |                |          |   |      |   |          |  
|Net deferred tax liability                   |  | $              | (130,839 | ) |      | $ | (148,656 | )
|                                             |  |                |          |   |      |   |          |  



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. In
December 2002, the Company established a $3.6 million valuation allowance against the loss carryforwards that could expire unutilized. During 2003, the valuation allowance was reduced to $3.2 million based on loss carryforwards that were able to be
utilized. No change in the valuation allowance was recorded during 2004. At December 31, 2004, the Company had depletion deduction carryforwards of approximately $13.0 million that are available indefinitely. The Company paid $4.8 million, $14.0
million and $24.6 million in federal and state taxes during 2002, 2003 and 2004, 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. Although the Company expects that the Act may result in a reduction in the Companys effective tax rate, the Company has not yet determined the full impact of this law.



F-23



---

|(10) | MAJOR CUSTOMERS
|---- | ---------------



During 2002 and 2003, major customer A accounted for 37% and 23%, and major customer B accounted for 9% and 15% of revenues, respectively. During 2004,
major customer A accounted for 18%, major customer B accounted for 13%, and major customer C accounted for 10% of revenues. Accounts receivable amounts from these customers at December 31, 2003 and 2004 totaled $25.4 million and $33.7 million,
respectively. 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.



|(11) | COMMITMENTS AND CONTINGENCIES
|---- | -----------------------------



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 the agreement, the Company buys and sells third
party gas at various delivery points on the pipeline. During 2003 and 2004, $63,000 and $94,000 were recorded as a component of other revenues in the accompanying consolidated statements of operations reflecting proceeds of $9.6 million and $19.1
million from gas sold, net of costs of $9.6 million and $19.0 million, in 2003 and 2004, 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 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.



F-24



---

|(12) | UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
|---- | ------------------------------------------------------



Netherland, Sewell & Associates, Inc., independent petroleum consultants, audited the Companys total proved reserves at December 31, 2002, 2003
and 2004. All reserve estimates are based on economic and operating conditions at that time. Future net cash flows as of each year-end were computed by applying then current prices to estimated future production less estimated future expenditures
(based on current costs) to be incurred in producing and developing the reserves. All reserves are located onshore in the United States.



Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. With respect to certain properties that historically have experienced seasonal curtailment,
the reserve estimates assume that the seasonal pattern of such curtailment will continue in the future. There can be no assurance that actual production will equal the estimated amounts used in the preparation of reserve projections.



There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and timing of development expenditures. The data in the tables below represent estimates only. Oil and gas reserve engineering must be recognized as 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 is a function of the quality of available data and engineering and geological interpretation and judgment. Results in drilling,
testing and production after the date of the estimate may justify revisions. Accordingly, reserve estimates are often materially different from the quantities of oil and gas that are ultimately recovered.



Quantities of Proved Reserves



|                                      |  |        |   |  |             |  
|------------------------------------- |  | ------ | - |  | ----------- | -
|                                      |  | Oil    |   |  | Natural Gas |  
|                                      |  | (MBbl) |   |  | (MMcf)      |  
|Balance, December 31, 2001            |  | 32,104 |   |  | 526,540     |  
|Revisions                             |  | 12,172 |   |  | 119,952     |  
|Extensions, discoveries and additions |  | 1,231  |   |  | 14,756      |  
|Production                            |  | (3,272 | ) |  | (49,777     | )
|Purchases                             |  | 15,136 |   |  | 146,253     |  
|Sales                                 |  | (43    | ) |  | (202        | )
|                                      |  |        |   |  |             |  
|Balance, December 31, 2002            |  | 57,328 |   |  | 757,522     |  
|Revisions                             |  | 731    |   |  | 37,087      |  
|Extensions, discoveries and additions |  | 7,486  |   |  | 90,487      |  
|Production                            |  | (5,737 | ) |  | (65,570     | )
|Purchases                             |  | 23,194 |   |  | 234,825     |  
|Sales                                 |  | (1,055 | ) |  | (30,017     | )
|                                      |  |        |   |  |             |  
|Balance, December 31, 2003            |  | 81,947 |   |  | 1,024,334   |  
|Revisions                             |  | 267    |   |  | (31,999     | )
|Extensions, discoveries and additions |  | 12,324 |   |  | 178,401     |  
|Production                            |  | (6,606 | ) |  | (78,290     | )
|Purchases                             |  | 1,169  |   |  | 14,882      |  
|Sales                                 |  | (816   | ) |  | (18,033     | )
|                                      |  |        |   |  |             |  
|Balance, December 31, 2004            |  | 88,285 |   |  | 1,089,295   |  
|                                      |  |        |   |  |             |  



F-25



---

Proved Developed Reserves



|                  |  |        |  |            
|----------------- |  | ------ |  | -----------
|                  |  | Oil    |  | Natural Gas
|                  |  | (MBbl) |  | (MMcf)     
|December 31, 2001 |  | 28,220 |  | 430,487    
|                  |  |        |  |            
|December 31, 2002 |  | 41,833 |  | 522,227    
|                  |  |        |  |            
|December 31, 2003 |  | 58,128 |  | 696,249    
|                  |  |        |  |            
|December 31, 2004 |  | 65,455 |  | 767,603    
|                  |  |        |  |            



Standardized Measure



|                               |  |                |            |   |      |   |            |      |  |   |            |  
|------------------------------ |  | -------------- | ---------- | - | ---- | - | ---------- | ---- |  | - | ---------- | -
|                               |  | December 31,   |           
|                               |  | 2002           |            |   | 2003 |   |            | 2004 | 
|                               |  | (In thousands) |           
|Future cash inflows            |  | $              | 4,525,670  |   |      | $ | 8,227,574  |      |  | $ | 9,772,879  |  
|Future costs                   |  |                |            |   |      |   |            |      |  |   |            |  
|Production                     |  |                | (1,083,832 | ) |      |   | (2,107,655 | )    |  |   | (2,470,938 | )
|Development(a)                 |  |                | (622,752   | ) |      |   | (864,347   | )    |  |   | (1,125,821 | )
|                               |  |                |            |   |      |   |            |      |  |   |            |  
|Future net cash flows          |  |                | 2,819,086  |   |      |   | 5,255,572  |      |  |   | 6,176,120  |  
|Undiscounted income taxes      |  |                | (929,183   | ) |      |   | (1,790,715 | )    |  |   | (2,021,454 | )
|                               |  |                |            |   |      |   |            |      |  |   |            |  
|After tax net cash flows       |  |                | 1,889,903  |   |      |   | 3,464,857  |      |  |   | 4,154,666  |  
|10% discount factor            |  |                | (879,553   | ) |      |   | (1,683,838 | )    |  |   | (2,055,365 | )
|                               |  |                |            |   |      |   |            |      |  |   |            |  
|Standardized measure           |  | $              | 1,010,350  |   |      | $ | 1,781,019  |      |  | $ | 2,099,301  |  
|                               |  |                |            |   |      |   |            |      |  |   |            |  
|PV10% Value (non-GAAP measure) |  | $              | 1,484,936  |   |      | $ | 2,704,461  |      |  | $ | 3,129,572  |  
|                               |  |                |            |   |      |   |            |      |  |   |            |  



Reconciliation of PV10% to
Standardized Measure



|                                    |  |                |            |   |      |   |            |      |  |   |            |  
|----------------------------------- |  | -------------- | ---------- | - | ---- | - | ---------- | ---- |  | - | ---------- | -
|                                    |  | December 31,   |           
|                                    |  | 2002           |            |   | 2003 |   |            | 2004 | 
|                                    |  | (In thousands) |           
|Future cash inflows                 |  | $              | 4,525,670  |   |      | $ | 8,227,574  |      |  | $ | 9,772,879  |  
|Future costs                        |  |                |            |   |      |   |            |      |  |   |            |  
|Production                          |  |                | (1,083,832 | ) |      |   | (2,107,655 | )    |  |   | (2,470,938 | )
|Development(a)                      |  |                | (622,752   | ) |      |   | (864,347   | )    |  |   | (1,125,821 | )
|                                    |  |                |            |   |      |   |            |      |  |   |            |  
|Future net cash flows               |  |                | 2,819,086  |   |      |   | 5,255,572  |      |  |   | 6,176,120  |  
|10% discounted factor               |  |                | (1,334,150 | ) |      |   | (2,551,111 | )    |  |   | (3,046,548 | )
|                                    |  |                |            |   |      |   |            |      |  |   |            |  
|PV10% Value (non-GAAP measure)      |  |                | 1,484,936  |   |      |   | 2,704,461  |      |  |   | 3,129,572  |  
|Undiscounted income taxes           |  |                | (929,183   | ) |      |   | (1,790,715 | )    |  |   | (2,021,454 | )
|10% discount factor                 |  |                | 454,597    |   |      |   | 867,273    |      |  |   | 991,183    |  
|                                    |  |                |            |   |      |   |            |      |  |   |            |  
|Discounted income taxes             |  |                | (474,586   | ) |      |   | (923,442   | )    |  |   | (1,030,271 | )
|                                    |  |                |            |   |      |   |            |      |  |   |            |  
|Standardized measure (GAAP measure) |  | $              | 1,010,350  |   |      | $ | 1,781,019  |      |  | $ | 2,099,301  |  
|                                    |  |                |            |   |      |   |            |      |  |   |            |  



Management believes that the
presentation of the non-GAAP financial measure of PV10% provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique
to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability when evaluating companies. Management also uses this pre-tax measure in evaluating acquisition candidates.
PV10% is not a measure of financial or operating performance under GAAP. PV10% should not be considered as an alternative to standardized measure as defined under GAAP.



|(a) | Future development costs of $1.1 billion at December 31, 2004 include an estimate of $683.2 million for development of properties classified as proved undeveloped
reserves including $182.2 million in 2005, $151.7 million in 2006, and $122.2 million in 2007. Actual results may differ from these estimates. Capital expenditures incurred to develop proved undeveloped reserves were approximately $19.1 million,
$50.4 million, and $73.7 million in 2002, 2003, and 2004, respectively.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



F-26



---

Changes in Standardized Measure



|                                        |  |                |           |   |      |   |           |      |  |   |           |  
|--------------------------------------- |  | -------------- | --------- | - | ---- | - | --------- | ---- |  | - | --------- | -
|                                        |  | December 31,   |          
|                                        |  | 2002           |           |   | 2003 |   |           | 2004 | 
|                                        |  | (In thousands) |          
|Standardized measure, beginning of year |  | $              | 390,939   |   |      | $ | 1,010,350 |      |  | $ | 1,781,019 |  
|Revisions:                              |  |                |           |   |      |   |           |      |  |   |           |  
|Prices and costs                        |  |                | 543,034   |   |      |   | 589,847   |      |  |   | 361,574   |  
|Quantities                              |  |                | 50,681    |   |      |   | 15,324    |      |  |   | (208,741  | )
|Development costs                       |  |                | 73        |   |      |   | (24,300   | )    |  |   | (54,475   | )
|Accretion of discount                   |  |                | 52,718    |   |      |   | 148,494   |      |  |   | 270,446   |  
|Income taxes                            |  |                | (338,342  | ) |      |   | (429,330  | )    |  |   | (126,355  | )
|Production rates and other              |  |                | (6,603    | ) |      |   | (17,429   | )    |  |   | (63,713   | )
|                                        |  |                |           |   |      |   |           |      |  |   |           |  
|Net revisions                           |  |                | 301,561   |   |      |   | 282,606   |      |  |   | 178,736   |  
|Extensions, discoveries and additions   |  |                | 26,102    |   |      |   | 193,641   |      |  |   | 435,117   |  
|Production                              |  |                | (175,693  | ) |      |   | (315,916  | )    |  |   | (427,185  | )
|Future development costs incurred       |  |                | 97,428    |   |      |   | 96,602    |      |  |   | 124,500   |  
|Purchases(a)                            |  |                | 370,448   |   |      |   | 545,765   |      |  |   | 37,326    |  
|Sales(b)                                |  |                | (435      | ) |      |   | (32,029   | )    |  |   | (30,212   | )
|                                        |  |                |           |   |      |   |           |      |  |   |           |  
|Standardized measure, end of year       |  | $              | 1,010,350 |   |      | $ | 1,781,019 |      |  | $ | 2,099,301 |  
|                                        |  |                |           |   |      |   |           |      |  |   |           |  



|(a) | Purchases includes the present value at the end of the period acquired plus cash flow received on such properties during the period, rather than their
estimated present value at the time of the acquisition.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(b) | Sales represents the present value at the beginning of the period of properties sold, less the cash flow received on such properties during the period.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------



F-27



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PATINA OIL & GAS CORPORATION



INDEX TO EXHIBITS



|      |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|----- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|2.1   |  | Amended and Restated Agreement and Plan of Merger dated as of January 16, 1996 as amended and restated as of March 20, 1996 (Incorporated herein by reference to Exhibit 2.1 to Amendment No. 1
to the Registration Statement on Form S-4 of the Company (Registration No. 333-572))                                                                                                                                                                                            
|      | 
|2.2   |  | Agreement and Plan of Merger among Patina Oil & Gas Corporation, Patina Bravo Corporation, Bravo Natural Resources, Inc., and Certain of the Stockholders of Bravo Natural Resources, Inc.
dated November 6, 2002 (Incorporated herein by reference to Exhibit 2.1 to the Companys Form 8-K filed on December 9, 2002)                                                                                                                                                         
|      | 
|2.3   |  | Purchase and Sale Agreement between Cordillera Energy Partners, LLC and Patina Oil & Gas Corporation dated August 25, 2003 (Incorporated herein by reference to Exhibit 2.1 to the
Companys Form 8-K filed on October 2, 2003)                                                                                                                                                                                                                                                 
|      | 
|2.4   |  | Agreement and Plan of Merger, dated as of December 15, 2004 by and among Noble Energy, Inc., Noble Energy Production, Inc. and Patina Oil & Gas Corporation (Incorporated herein by
reference to Exhibit 2.1 to Form 8-K filed December 21, 2004)                                                                                                                                                                                                                               
|      | 
|3.1   |  | Certificate of Incorporation (Incorporated herein by reference to the Exhibit 3.1 to the Companys Registration Statement on Form S-4 (Registration No. 333-572))                                                                                                                                                                                                                                                                                                               
|      | 
|3.2   |  | Amended and Restated Bylaws of Patina Oil & Gas Corporation. (Incorporated herein by reference to Exhibit 3(ii) of the Companys Form 8-K filed on May 25, 2001)                                                                                                                                                                                                                                                                                                                
|      | 
|3.3   |  | Certificate of Ownership and Merger of Gerrity Oil & Gas Corporation with and into the Company, effective March 21, 1997 (Incorporated herein by reference to Exhibit 4.3 of the
Companys Form 10-Q for the quarter ended March 31, 1997)                                                                                                                                                                                                                                      
|      | 
|4.1   |  | Rights Agreement, dated as of May 25, 2001 between the Company and Mellon Investor Services LLC, a Rights Agent (Incorporated herein by reference to Exhibit 4.1 of the Companys Form
8-A/A filed on June 12, 2001 (Registration No. 001-14344))                                                                                                                                                                                                                               
|      | 
|4.1.1 |  | Amendment to Rights Agreement, dated as of December 15, 2004 between Patina Oil & Gas Corporation and Mellon Investor Services, LLC (Incorporated herein by reference to Exhibit 4.1 to
Form 8-K filed on December 20, 2004)                                                                                                                                                                                                                                                    
|      | 
|4.2   |  | Certificate of Designations of Series A Junior Participating Preferred Stock (included as Exhibit A to the Rights Agreement listed above as Exhibit 4.1)                                                                                                                                                                                                                                                                                                                        
|      | 
|4.3   |  | Form of Warrant to Purchase Shares of Common Stock of Patina Oil & Gas Corporation dated March 8, 2004 (Incorporated herein by reference to Exhibit 4.1 to Amendment No. 1 to Form S-3
filed March 17, 2004 (Registration No. 333-110708))                                                                                                                                                                                                                                      
|      | 
|10.1  |  | Third Amended and Restated Credit Agreement dated January 28, 2003 by and among the Company, as Borrower, and Bank One, NA, as Administrative Agent, Wachovia Bank, National Association and
Wells Fargo Bank, N.A., as Syndication Agents, Bank of America, N.A. and Credit Lyonnais New York Branch, as Documentation Agents, and certain commercial lending institutions (Incorporated herein by reference to Exhibit 10.1 of the Companys
Form 10-K filed on March 5, 2003)



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|       |  |                                                                                                                                                                                                                                                                                                                              
|------ |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.1.1 |  | First Amendment to the Third Amended and Restated Credit Agreement dated May 1, 2003 by and among the Company, as borrower, Bank One, NA, as Administrative Agent, and certain other financial
institutions (Incorporated herein by reference to Exhibit 10.1.2 of the Companys Form 10-Q filed on August 1, 2003)          
|       | 
|10.1.2 |  | Second Amendment to the Third Amended and Restated Credit Agreement dated October 1, 2003 by and among the Company, as Borrower, and Bank One, NA, as Administrative Agent, and certain other
financial institutions (Incorporated herein by reference to Exhibit 10.1.3 to the Companys Form 8-K filed on October 2, 2003) 
|       | 
|10.2   |  | Agreement and Plan of Reorganization by and among Patina Oil & Gas Corporation, Le Norman Energy Corporation, Patina Oklahoma Corp., and The Le Norman Shareholders dated October 23, 2002
(Incorporated herein by reference to Exhibit 10.1 of the Companys Form 8-K filed on November 7, 2002)                            
|       | 
|10.3   |  | Patina Oil & Gas Corporation Profit Sharing and Savings Plan and Trust, effective January 1, 1997 (Incorporated herein by reference to Exhibit 10.3 of the Companys Form 10-K for the
year ended, December 31, 1997)                                                                                                        
|       | 
|10.4   |  | Amended and Restated Patina Oil & Gas Corporation Deferred Compensation Plan for Select Employees as adopted May 1, 1996 and amended as of September 30, 1997 and further amended as of
August 1, 2001 (Incorporated herein by reference to Exhibit 10.1 of the Companys Form 10-Q for the quarter ended September 30, 2001)
|       | 
|10.4.1 |  | Amendment to the Amended and Restated Patina Oil & Gas Corporation Deferred Compensation Plan For Select Employees (Incorporated herein by reference to Exhibit 10.3 to Form 8-K filed
September 20, 2004)                                                                                                                   
|       | 
|10.5   |  | Patina Oil & Gas Corporation 1998 Stock Purchase Plan (Incorporated herein by reference to Exhibit 10.3.3 of the Companys Form 10-K for the year ended December 31,
1997)                                                                                                                                                   
|       | 
|10.5.1 |  | Amendment No. 1 to the Patina Oil & Gas Corporation 1998 Stock Purchase Plan (Incorporated herein by reference to Exhibit 10.3 of the Companys Form 10-Q for the quarter ended June
30, 1999)                                                                                                                               
|       | 
|10.6   |  | Patina Oil & Gas Corporation 1996 Employee Stock Option Plan (Incorporated herein by reference to Exhibit 10.20 of the Companys Registration Statement on Form S-4 (Registration No.
333-572))                                                                                                                              
|       | 
|10.6.1 |  | Amendment No. 1 to the 1996 Employee Stock Option Plan of Patina Oil & Gas Corporation (Incorporated herein by reference to Exhibit 10.2 of the Companys Form 10-Q for the quarter
ended June 30, 1999)                                                                                                                     
|       | 
|10.6.2 |  | Amendment to Patina Oil & Gas Corporation 1996 Employee Stock Option Plan (Incorporated herein by reference to Exhibit 10.1 to Form 8-K filed September 20, 2004)                                                                                                                                                            
|       | 
|10.7   |  | Lease Agreement dated as of December 21, 2000 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant (Incorporated herein by reference to Exhibit 10.5.1 of the
Companys Form 10-K for the year ended December 31, 2000)                                                                           
|       | 
|10.7.1 |  | Amendment of Lease Agreement dated November 19, 2001 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant (Incorporated herein by reference to Exhibit 10.6.1 of the
Companys Form 10-K filed on March 5, 2003)                                                                                  



F-29



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|        |  |                                                                                                                                                                                                                                                  
|------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.7.2  |  | Second Amendment of Lease Agreement dated January 16, 2003 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant (Incorporated herein by reference to Exhibit 10.6.2
of the Companys Form 10-K filed on March 5, 2003)
|        | 
|10.7.3  |  | Third Amendment of Lease Agreement dated November 7, 2003 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant (Incorporated herein by reference to Exhibit 10.6.3
of the Companys Form 10-K filed on March 9, 2004) 
|        | 
|10.8    |  | Sale and Purchase Agreement by and between Wynn-Crosby 1998, Ltd. And Wynn-Crosby 1999, Ltd. And Patina Oklahoma Corp. dated February 19, 2003 (Incorporated herein by reference to Exhibit
10.1 to Form 8-K filed March 18, 2003)               
|        | 
|10.9    |  | Patina Oil & Gas Corporation 2005 Deferred Compensation Plan for Select Employees (Incorporated herein by reference to Exhibit 10.1 to Form 8-K filed December 30, 2004)                                                                         
|        | 
|10.10   |  | Letter Agreement dated July 19, 2004 between the Company and Ted D. Brown (Incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed October 28, 2004)                                                                                 
|        | 
|10.11   |  | Patina Oil & Gas Corporation Profit Sharing & 401(k)  Scudder Trust Company Prototype Defined Contribution Plan, adopted June 18, 2004 (Incorporated herein by reference to
Exhibit 10.1 to Form 10-Q filed July 29, 2004)                      
|        | 
|10.12   |  | Patina Oil & Gas Corporation Profit Sharing & 401(k)  Scudder Trust Company Prototype Defined Contribution Plan Adoption Agreement, dated June 18, 2004 (Incorporated herein by
reference to Exhibit 10.2 to Form 10-Q filed July 29, 2004)     
|        | 
|10.13   |  | Separation and Consulting Agreement dated December 22, 2004 between Patina Oil & Gas Corporation and Jay W. Decker (Incorporated herein by reference to Exhibit 10.1 to Form 8-K filed
December 22, 2004)                                        
|        | 
|10.14   |  | Patina Oil & Gas Corporation Amended and Restated Change in Control Plan (Incorporated herein by reference to Exhibit 10.5 to Form 8-K filed September 20, 2004)                                                                                 
|        | 
|10.14.1 |  | Amendment to the Amended and Restated Patina Oil & Gas Change in Control Plan (Incorporated herein by reference to Exhibit 10.1 to Form 8-K filed December 21, 2004)                                                                             
|        | 
|10.15   |  | Patina Oil & Gas Corporation 1996 Stock Plan for Non-Employee Directors (Incorporated herein by reference to Exhibit 10.21 of the Companys Registration Statement on Form S-4
(Registration No. 333-572))                                       
|        | 
|10.15.1 |  | Amendment to Patina Oil & Gas Corporation 1996 Stock Plan for Non-Employee Directors (Incorporated herein by reference to Exhibit 10.2 to Form 8-K filed September 20,
2004)                                                                     
|        | 
|10.16   |  | Form of Patina Oil & Gas Corporation Director/Officer Indemnification Agreement (Incorporated herein by reference to Exhibit 10.4 to Form 8-K filed September 20, 2004)                                                                          
|        | 
|10.17   |  | Patina Oil & Gas Corporation Long Term Incentive Program for Chief Executive Officer (Incorporated herein by reference to Exhibit 10.1 to Form 8-K filed December 16,
2004)                                                                      
|        | 
|10.18   |  | Employment Agreement dated July 31, 1997 by and between the Company and Thomas J. Edelman (Incorporated herein by reference to Exhibit 10.7 of the Companys Form 10-Q for the quarter
ended September 30, 1997)                                 



F-30



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|        |  |                                                                                                                                                                                                                   
|------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.18.1 |  | Amendment to Employment Agreement, dated as of December 15, 2004 between Patina Oil & Gas Corporation and Thomas J. Edelman (Incorporated herein by reference to Exhibit 10.2 to Form 8-K
filed December 21, 2004)
|        | 
|21.1    |  | Subsidiaries of Registrant *                                                                                                                                                                                      
|        | 
|23.1    |  | Consent of independent auditors *                                                                                                                                                                                 
|        | 
|23.2    |  | Consent of independent reservoir engineers *                                                                                                                                                                      
|        | 
|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 the Chief Executive Officer, dated February 25, 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 the Chief Financial Officer, dated February 25, 2005, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.*                                 



|(d) | Financial Statement Schedules Required by Regulation S-X.
|--- | ---------------------------------------------------------



| | The items listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.
| | ------------------------------------------------------------------------------------------------------------------------



* - Filed herewith



F-31