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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, 2003



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 of incorporation or organization) |  | (IRS Employer Identification 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 53,440,000 shares of voting stock held by
non-affiliates of the registrant, based upon the closing sale price of the common stock on June 30, 2003 of $16.08 per share as reported on the New York Stock Exchange, was $859,315,200. 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 March 5, 2004, the registrant had 69,757,408 shares of common stock
outstanding (excludes 2,197,912 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, which will be filed with the Commission no later than April 30, 2004.



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PATINA OIL & GAS CORPORATION

Annual Report on Form 10-K

December 31, 2003



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 southern Oklahoma and the Texas Panhandle, and the San Juan Basin. The Companys common stock is traded on the New York Stock Exchange under the symbol
POG.



At December 31, 2003, the Company had 1.5 trillion cubic
feet equivalent (Tcfe) of proved reserves having a pretax present value based upon a discount rate of 10% (PV10%) of $2.7 billion based on unescalated prices and costs. This valuation reflected average wellhead prices of $5.54 per Mcf
and $31.16 per barrel at year-end. During 2003, proved reserves increased 38%. The growth was largely the result of acquisitions and ongoing development and performance revisions which increased reserves by 374 Bcfe and 163 Bcfe, respectively. In
addition, oil and gas prices increased reserves 14 Bcfe. The reserve increases were offset by 100 Bcfe of production and 36 Bcfe of reserves sold. Exclusive of the impact of higher prices, the Company replaced over 500% of production in 2003. At
year-end, approximately 68% of Company reserves by volume were natural gas and over 78% by pretax present value was attributed to proved developed wells.



The Company operates over 75% of the 7,750 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, 2003, the Company had over 4,000 proven development projects in inventory, including
1,400 drilling or deepening locations, 850 recompletions, 1,300 restimulation (refrac or trifrac) projects and over 600 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 2003, average daily production totaled 274.0 MMcfe, comprised of 15,720 barrels of oil and 179.6 MMcf of gas. Approximately 70% was attributed to
Wattenberg. Based on year-end reserves and fourth quarter production, the Company had a reserve life index of 13.1 years.



Revenues and net income for 2003 totaled $406.7 million and $90.9 million, respectively. Cash provided from operations in 2003 totaled $271.8 million.
This cash flow, augmented with $216.0 million of bank borrowings and $9.3 million realized from the issuance of common stock, funded $466.5 million of capital expenditures in 2003, net of $16.9 million of property sales. These expenditures were
largely comprised of $307.3 million spent on acquisitions and $176.1 million on further development of properties. Development expenditures included $92.1 million expended in Wattenberg, $57.1 million in the Mid Continent, $1.3 million in the San
Juan Basin, and $25.6 million in the Central and Other region properties. The benefits of these projects, continued success in production enhancement and acquisitions fueled a 44% production increase during the year. Based on a $210.0 million
capital budget for 2004 combined with the benefits of the acquisitions made in 2003, the Company expects production to increase by approximately 17% to 20% in the coming year.



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History



The Company was incorporated in 1996 in Delaware 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 9.5 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.



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 remainder of the joint venture for $25.8 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% 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 produce primarily 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.



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Over the last five years, the Company has realized consistent growth in nearly every aspect of its
business. Revenues increased from $74.8 million in 1998 to $406.7 million in 2003. Net income rose from a loss of $4.4 million to net income of $90.9 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 and the execution of high return capital projects, while maintaining low production costs and an efficient operating structure. Production grew from 97.8 MMcfe per day in 1998 to 274.0 MMcfe per
day in 2003. Additionally, proven reserves jumped from 372.0 Bcfe at year-end 1998 to 1.5 Tcfe at December 31, 2003. The reserve growth was largely generated through further development and exploitation in the Wattenberg Field along with recent
additions from the Le Norman, Bravo, LNP, and Cordillera acquisitions.



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 36 month basis.



Development, Acquisition and Exploration



During 2003, the Company spent $176.1 million on the further development of
properties and $307.3 million on acquisitions. Development expenditures included $92.1 million in Wattenberg for the drilling or deepening of 39 J-Sand wells, 433 Codell refracs, 51 Codell trifracs, 14 recompletions and the drilling of 41 Codell
wells, $57.1 million in the Mid Continent for the drilling or deepening of 190 wells, eight refracs and 12 recompletions, $1.3 million in the San Juan Basin, and $25.6 million on the Central region and Other properties. The benefits of these
projects, the acquisitions, and the continued success in production enhancement contributed to a production increase of 44% over the prior year. The Company anticipates incurring approximately $210.0 million on the further development of its
properties in 2004.



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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Production, Revenue and Price History



The following table sets forth information regarding oil and gas production, revenues and direct 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,                                       
|                                    |  | 1999                                                           |        | 2000 |   | 2001    |  | 2002 |         | 2003
|                                    |  | (Dollars in thousands, except prices and per Mcfe information)
|Production                          |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Oil (MBbl)                          |  |                                                                | 1,653  |      |   | 1,685   |  |      | 2,661   |      |   | 3,272   |  |   | 5,737  
|Gas (MMcf)                          |  |                                                                | 29,477 |      |   | 33,463  |  |      | 41,002  |      |   | 49,777  |  |   | 65,570 
|MMcfe(a)                            |  |                                                                | 39,396 |      |   | 43,572  |  |      | 56,969  |      |   | 69,411  |  |   | 99,996 
|Revenues                            |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Oil                                 |  | $                                                              | 26,218 |      | $ | 38,741  |  | $    | 68,447  |      | $ | 80,233  |  | $ | 148,028
|Gas(c)                              |  |                                                                | 64,189 |      |   | 109,924 |  |      | 142,824 |      |   | 135,197 |  |   | 250,696
|                                    |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Subtotal                            |  |                                                                | 90,407 |      |   | 148,665 |  |      | 211,271 |      |   | 215,430 |  |   | 398,724
|Other                               |  |                                                                | 1,259  |      |   | 1,677   |  |      | 2,902   |      |   | 6,977   |  |   | 7,993  
|                                    |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Total                               |  |                                                                | 91,666 |      |   | 150,342 |  |      | 214,173 |      |   | 222,407 |  |   | 406,717
|                                    |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Direct operating expenses           |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Lease operating expenses            |  |                                                                | 11,902 |      |   | 13,426  |  |      | 25,356  |      |   | 27,986  |  |   | 54,082 
|Production taxes(d)                 |  |                                                                | 6,271  |      |   | 10,628  |  |      | 13,462  |      |   | 11,751  |  |   | 28,726 
|                                    |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Total                               |  |                                                                | 18,173 |      |   | 24,054  |  |      | 38,818  |      |   | 39,737  |  |   | 82,808 
|                                    |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Direct operating margin             |  | $                                                              | 73,493 |      | $ | 126,288 |  | $    | 175,355 |      | $ | 182,670 |  | $ | 323,909
|                                    |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Average sales price(b)              |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Oil (Bbl)                           |  | $                                                              | 15.86  |      | $ | 23.00   |  | $    | 25.72   |      | $ | 24.52   |  | $ | 25.80  
|Gas (Mcf)(c)                        |  |                                                                | 2.18   |      |   | 3.28    |  |      | 3.48    |      |   | 2.72    |  |   | 3.82   
|Mcfe(a)                             |  |                                                                | 2.29   |      |   | 3.41    |  |      | 3.71    |      |   | 3.10    |  |   | 3.99   
|Lease operating expense per Mcfe(d) |  | $                                                              | 0.30   |      | $ | 0.31    |  | $    | 0.45    |      | $ | 0.40    |  | $ | 0.54   
|Production tax expense per Mcfe     |  |                                                                | 0.16   |      |   | 0.24    |  |      | 0.24    |      |   | 0.17    |  |   | 0.29   
|                                    |  |                                                                |        |      |   |         |  |      |         |      |   |         |  |   |        
|Direct operating expense per Mcfe   |  |                                                                | 0.46   |      |   | 0.55    |  |      | 0.69    |      |   | 0.57    |  |   | 0.83   
|Production margin per Mcfe          |  | $                                                              | 1.83   |      | $ | 2.86    |  | $    | 3.02    |      | $ | 2.53    |  | $ | 3.16   

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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 30% of production is sold to Duke Energy Field Services (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.



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 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 one year and an
additional $100.0 million for two years. At December 31, 2003, the net unrealized pretax gains on these contracts totaled $421,000 ($261,000 gain net of $160,000 of deferred taxes) based on LIBOR futures prices at December 31, 2003.



The Company regularly enters into hedging agreements to reduce the impact on
its operations of fluctuations in oil and gas prices. All such contracts are entered into solely to hedge prices and limit volatility. The Companys current policy is to hedge between 50% and 75% of its production, when futures prices justify,
on a rolling 12 to 36 month basis. At December 31, 2003, hedges were in place covering 78.8 Bcf at prices averaging $4.00 per MMBtu and 12.2 million barrels of oil averaging $25.03 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 $88.4 million ($54.8 million loss net of $33.6 million of deferred taxes) at December 31, 2003. 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 $137,000, a non-current asset of $1.9 million, a current liability of $62.3 million, and a non-current liability of $27.6 million based on
contract expiration. The gas contracts settle monthly through December 2005 while the 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



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sold. Any ineffective portion of such hedges is recognized in earnings as it occurs. Net pretax gains relating to these derivatives were $4.1 million and
$20.4 million in 2001 and 2002 and a pretax loss of $50.4 million in 2003, 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 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.



State statutes govern
exploration and production operations, conservation of oil and gas resources, protection of the correlative rights of oil and gas owners and environmental standards. 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,



7



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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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 2003, nor does it
anticipate that such expenditures will be material in 2004.



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 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



8



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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 pollutants 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 coastal 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.



9



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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. When considering forward-looking statements, 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: 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 present value of such future net revenues), estimates of future production of oil and natural gas, expected results or benefits associated with recent acquisitions, business strategies, expansion and growth of the Companys operations, cash
flow and anticipated liquidity, grassroots prospects and development and property acquisitions, obtaining financial or industry partners for prospect or program development, or marketing of oil and natural gas. We caution you that these
forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and gas. These risks include but are not limited to:
general economic conditions, the market price of oil and natural gas, the risks associated with exploration, the Companys ability to find, acquire, market, develop and produce new properties, operating hazards attendant to the oil and gas
business, uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures, the strength and financial resources of the Companys competitors, the Companys
ability to find and retain skilled personnel, climatic conditions, labor relations, availability and cost of material and equipment, environmental risks, the results of financing efforts, regulatory developments and the other risks described in this
Form 10-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.



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.



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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.
| | - | ----------------------------------------------------------------------------------------



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.



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.
| | - | ---------------------------------------------------------------------



Operating Risks of Oil and Natural 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



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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 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 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.



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.



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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 August 2008. The monthly rent is approximately $94,000. 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 2,400 square foot field office in Hinton, 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, 2003, the Company had 400 employees, including 281 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.



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



General



During 2003,
the Companys production averaged 274.0 MMcfe per day, of which 191.2 MMcfe per day or 70% was attributed to the Wattenberg Field of Colorados D-J Basin. Accordingly, the Companys proved reserves at December 31, 2003 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, 2003.



|                  |  |                              |           |   |     |   |            |        |                   |           |              |           |   |     |  
|----------------- |  | ---------------------------- | --------- | - | --- | - | ---------- | ------ | ----------------- | --------- | ------------ | --------- | - | --- | -
|                  |  | Pre-tax PresentValue 10% (a) |           |   |     |   |            |        |                   |           |              |          
|                  |  | Amount (Inthousands)         |           | % |     |   | Oil(MBbls) |        | Natural Gas(MMcf) |           | Total(MMcfe) |           | % |    
|Wattenberg        |  | $                            | 1,574,491 |   | 58  |   |            | 36,421 |                   | 592,508   |              | 811,032   |   | 54  |  
|Mid Continent     |  |                              | 802,777   |   | 30  |   |            | 30,452 |                   | 278,429   |              | 461,142   |   | 30  |  
|San Juan          |  |                              | 173,352   |   | 6   |   |            | 349    |                   | 131,937   |              | 134,032   |   | 9   |  
|Central and Other |  |                              | 153,841   |   | 6   |   |            | 14,725 |                   | 21,460    |              | 109,808   |   | 7   |  
|                  |  |                              |           |   |     |   |            |        |                   |           |              |           |   |     |  
|Total             |  | $                            | 2,704,461 |   | 100 | % |            | 81,947 |                   | 1,024,334 |              | 1,516,014 |   | 100 | %
|                  |  |                              |           |   |     |   |            |        |                   |           |              |           |   |     |  



|(a) | Pre-tax Present Value 10% does not include the effects of future income taxes or future
plugging and abandonment costs, as is required in computing the standardized measure of discounted future net cash flows more fully described in Note (13) Unaudited Supplemental Oil and Gas Reserve Information to the financial statements.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The following table sets forth summary
information with respect to oil and natural gas production for the year ended December 31, 2003.



|                  |  |            |  |                   |  |              |  |     |  
|----------------- |  | ---------- |  | ----------------- |  | ------------ |  | --- | -
|                  |  | Oil(MBbls) |  | Natural Gas(MMcf) |  | Total(MMcfe) |  | %   |  
|Wattenberg        |  | 2,846      |  | 52,715            |  | 69,789       |  | 70  |  
|Mid Continent     |  | 1,484      |  | 10,700            |  | 19,607       |  | 20  |  
|San Juan          |  | 5          |  | 903               |  | 936          |  | 1   |  
|Central and Other |  | 1,402      |  | 1,252             |  | 9,664        |  | 9   |  
|                  |  |            |  |                   |  |              |  |     |  
|Total             |  | 5,737      |  | 65,570            |  | 99,996       |  | 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 better than 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.



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In 2003, development expenditures in Wattenberg totaled $92.1 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 and refracing or trifracing 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 2003 in what is considered a mature field.



During
2003, the Company drilled or deepened 39 wells to the J-Sand formation in Wattenberg. The cost of drilling and completing a J-Sand well approximates $350,000 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, 2003, the Company had over 270 proven J-Sand drilling locations or deepening projects in inventory. The Company plans to drill or deepen approximately 37 wells to the J-Sand in 2004.



The Company performed 433 refracs in Wattenberg during 2003. The refrac
program continues to be focused primarily on the Codell formation. A typical refrac costs approximately $140,000. At December 31, 2003, the Company had approximately 1,100 proven refrac projects. The Company plans to perform approximately 450 refrac
projects in 2004.



The Company performed 51 trifracs in
Wattenberg during 2003. The trifrac program, which is effectively a refrac of a refrac, was initiated in 2003 with encouraging results. A typical trifrac costs approximately $130,000. The Company is in the early stages of evaluating the trifrac
program and expects to perform approximately 50 trifracs in 2004. At December 31, 2003, the Company had over 200 proven trifrac projects in inventory.



The Company also performed 14 recompletions and drilled 41 Codell wells in the D-J Basin in 2003. The Company had an additional 600 Codell / J-Sand /
Sussex proven recompletion opportunities and over 600 Codell new drill opportunities at December 31, 2003. During 2003, 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 2003 capital development program and helped fuel the 44% increase in the Companys production over the prior year. The Company estimates it had over 700 of these minor projects in inventory
at year-end 2003.



At December 31, 2003, the Company had
working interests in approximately 3,300 gross (3,140 net) producing oil and gas wells in the D-J Basin with estimated proved reserves of 811.0 Bcfe, including 36.4 million barrels of oil and 592.5 Bcf of gas. Daily production from these properties
averaged 191,201 Mcfe, comprised of 7,797 barrels and 144,423 Mcf per day in 2003. Based on a capital of $210.0 million, the Company anticipates spending $110.0 million in Wattenberg in 2004.



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 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
primarily produce natural gas. Together the Le Norman, Bravo, LNP, and certain Cordillera properties comprise the Companys Mid Continent assets.



15



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The Loco Field is comprised of fourteen 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 twenty 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 76 wells in the Field in 2003 with plans to drill approximately 40
wells in 2004. 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 thirteen 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 twenty 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 39 wells in the Field in 2003 and plans to drill three wells and to continue to evaluate
additional exploitation opportunities in the Field in 2004. 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. 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 is currently being developed on 40 acre spacing. However, the Company believes a portion of the Field could be down spaced to include 20 acre locations. The Company drilled 41 wells in the Field
in 2003 and plans to drill approximately 40 wells in 2004.



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 three wells
in the Field in 2003 and plans to drill approximately six wells in the Field during 2004 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 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 plans to
drill approximately four wells in the Field during 2004.



In
the fourth quarter of 2003, the Company acquired interests in the South Thomas Field as part of the Cordillera acquisition. The Field is located in Blaine and Custer Counties in western Oklahoma and is primarily comprised of Red Fork production at a
depth of approximately 10,600 feet, with additional potential in the deeper Morrow Sandstone. The Company plans to drill two wells in the Field during 2004.



During 2003, development expenditures for the Mid Continent region totaled $57.1 million for the drilling or deepening of 190 wells, eight refracs, and 12
recompletions. At December 31, 2003, estimated proved reserves attributed to the Mid Continent region totaled 461.1 Bcfe, including 30.5 million barrels of oil and 278.4 Bcf of gas. Daily production from these properties averaged 53,718 Mcfe,
comprised of 4,067 barrels and 29,316 Mcf per day in 2003. Based on a capital budget of $210.0 million, the Company anticipates spending $70.0 million in the Mid Continent region in 2004.



16



---

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 2003, development expenditures
for the San Juan Basin totaled $1.3 million. At December 31, 2003, estimated proved reserves attributed to the San Juan Basin totaled 134.0 Bcfe, including 349,000 barrels of oil and 131.9 Bcf of gas. Based on a capital budget of $210.0 million, the
Company anticipates spending $15.0 million in the San Juan Basin in 2004 for the drilling of approximately 19 wells.



Central Region 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. Elysium sold certain properties in the Lake Washington Field in Louisiana for $30.5 million in March 2001 ($15.25 million net to the Company). In January
2003, the Company acquired the remaining 50% interest of the joint venture for $25.8 million, simultaneously divesting the remainder of Lake Washington and all California assets. In late 2003, the Company sold its interests in various Louisiana
fields for approximately $8.6 million. At December 31, 2003, the oil and gas properties were located primarily in central Kansas and the Illinois Basin, with minor interests remaining in Louisiana and Texas.



During 2001, the Company accumulated acreage positions in three Rocky
Mountain basins and acquired a producing field in West Texas (collectively, grassroots projects). 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.



These properties and remaining grassroots project comprise the Companys Central Region and Other areas of
operations. During 2003 development expenditures for the Central Region and Other properties totaled $25.6 million for the drilling or deepening of 79 wells and performing 91 recompletions, primarily in the Illinois Basin, Kansas and Texas. Daily
production from these properties averaged 26,477 Mcfe, comprised of 3,841 barrels and 3,431 Mcf per day in 2003. At December 31, 2003, estimated proved reserves totaled 109.8 Bcfe, including 14.7 million barrels of oil and 21.5 Bcf of gas. Based on
a capital budget of $210.0 million, the Company anticipates spending $15.0 million on these properties in 2004.



17



---

Proved Reserves



The following table sets forth estimated net proved reserves for the three years ended December 31, 2003.



|                     |  |              |         |      |   |           |  |   |          
|-------------------- |  | ------------ | ------- | ---- | - | --------- |  | - | ---------
|                     |  | December 31,
|                     |  | 2001         |         | 2002 |   | 2003     
|Oil (MBb1)           |  |              |         |      |   |           |  |   |          
|Developed            |  |              |         |      |   |           |  |   |          
|Producing            |  |              | 14,898  |      |   | 26,185    |  |   | 43,653   
|Non-producing        |  |              | 13,322  |      |   | 15,648    |  |   | 14,475   
|                     |  |              |         |      |   |           |  |   |          
|Total Developed      |  |              | 28,220  |      |   | 41,833    |  |   | 58,128   
|Undeveloped          |  |              | 3,884   |      |   | 15,495    |  |   | 23,819   
|                     |  |              |         |      |   |           |  |   |          
|Total                |  |              | 32,104  |      |   | 57,328    |  |   | 81,947   
|                     |  |              |         |      |   |           |  |   |          
|Natural gas (MMcf)   |  |              |         |      |   |           |  |   |          
|Developed            |  |              |         |      |   |           |  |   |          
|Producing            |  |              | 272,848 |      |   | 361,000   |  |   | 516,577  
|Non-producing        |  |              | 157,639 |      |   | 161,227   |  |   | 179,672  
|                     |  |              |         |      |   |           |  |   |          
|Total Developed      |  |              | 430,487 |      |   | 522,227   |  |   | 696,249  
|Undeveloped          |  |              | 96,053  |      |   | 235,295   |  |   | 328,085  
|                     |  |              |         |      |   |           |  |   |          
|Total                |  |              | 526,540 |      |   | 757,522   |  |   | 1,024,334
|                     |  |              |         |      |   |           |  |   |          
|Total MMcfe          |  |              | 719,164 |      |   | 1,101,491 |  |   | 1,516,014
|                     |  |              |         |      |   |           |  |   |          
|Pretax PV10% Value   |  | $            | 527,184 |      | $ | 1,484,936 |  | $ | 2,704,461
|                     |  |              |         |      |   |           |  |   |          
|Standardized Measure |  | $            | 390,939 |      | $ | 1,010,350 |  | $ | 1,781,019
|                     |  |              |         |      |   |           |  |   |          
|                     |  |              |         |      |   |           |  |   |          
|Oil price (Bbl)      |  | $            | 19.72   |      | $ | 30.51     |  | $ | 31.16    
|Gas price (Mcf)      |  | $            | 2.35    |      | $ | 3.67      |  | $ | 5.54     



The following table
sets forth the estimated pretax future net revenues as of year-end 2003 from the production of proved reserves and the pretax present value discounted at 10% of such revenues, net of estimated future capital costs, including an estimate of $201.3
million of future development costs (comprised of $81.9 of expenditures on proved developed non-producing properties and $119.4 million in expenditures on proved undeveloped properties) in 2004 (in thousands):



|                      |  |                   |           |             |   |           |       |  |   |          
|--------------------- |  | ----------------- | --------- | ----------- | - | --------- | ----- |  | - | ---------
|                      |  | December 31, 2003
|Future Net Revenues   |  | Developed         |           | Undeveloped |   |           | Total
|2004                  |  | $                 | 407,483   |             | $ | (41,579   | )     |  | $ | 365,904  
|2005                  |  |                   | 356,347   |             |   | 30,805    |       |  |   | 387,152  
|2006                  |  |                   | 339,995   |             |   | 68,276    |       |  |   | 408,271  
|Remainder             |  |                   | 2,666,708 |             |   | 1,491,370 |       |  |   | 4,158,078
|                      |  |                   |           |             |   |           |       |  |   |          
|Total                 |  | $                 | 3,770,533 |             | $ | 1,548,872 |       |  | $ | 5,319,405
|                      |  |                   |           |             |   |           |       |  |   |          
|Pretax PV10% Value(a) |  | $                 | 2,111,979 |             | $ | 592,482   |       |  | $ | 2,704,461
|                      |  |                   |           |             |   |           |       |  |   |          

---

|(a) | The after tax present value discounted at 10% of the proved reserves totaled $1.8 billion at year-end 2003.
|--- | -----------------------------------------------------------------------------------------------------------



At December 31, 2003 the Wattenberg Field represents 58% of the pretax PV10%
value and 811.0 Bcfe or 54% of Patinas proved reserves.



The quantities and values in the preceding tables are based on constant prices in effect at December 31, 2003, which averaged $31.16 per barrel of oil and $5.54 per Mcf of gas. These wellhead average prices were based on year-end NYMEX
prices of $32.52 per barrel and $6.19 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.



18



---

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 present 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,
2003. 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 present 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, 2003
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.



19



---

Producing Wells



The following table sets forth the producing wells in which the Company owned a working interest at December 31, 2003. Wells are classified as oil or
natural gas wells according to their predominant production stream.



|                           |  |            |  |         
|-------------------------- |  | ---------- |  | --------
|PrincipalProduction Stream |  | GrossWells |  | NetWells
|Wattenberg                 |  |            |  |         
|Oil                        |  | 2,643      |  | 2,511   
|Natural gas                |  | 661        |  | 628     
|                           |  |            |  |         
|Total                      |  | 3,304      |  | 3,139   
|                           |  |            |  |         
|Mid Continent              |  |            |  |         
|Oil                        |  | 2,198      |  | 1,035   
|Natural gas                |  | 995        |  | 484     
|                           |  |            |  |         
|Total                      |  | 3,193      |  | 1,519   
|                           |  |            |  |         
|San Juan                   |  |            |  |         
|Oil                        |  |           |  |        
|Natural gas                |  | 210        |  | 150     
|                           |  |            |  |         
|Total                      |  | 210        |  | 150     
|                           |  |            |  |         
|Central and Other          |  |            |  |         
|Oil                        |  | 917        |  | 838     
|Natural gas                |  | 128        |  | 114     
|                           |  |            |  |         
|Total                      |  | 1,045      |  | 952     
|                           |  |            |  |         
|Total                      |  |            |  |         
|Oil                        |  | 5,758      |  | 4,384   
|Natural gas                |  | 1,994      |  | 1,376   
|                           |  |            |  |         
|Total                      |  | 7,752      |  | 5,760   
|                           |  |            |  |         



The Company had 215
wells (207 net) in Wattenberg, 889 wells (655 net) in the Mid Continent region, two wells (two net) in the San Juan Basin, and 938 wells (845 net) in the Central Region and Other areas that were shut-in at December 31, 2003. The Companys
average working interest in the Wattenberg wells was approximately 95%, the average working interest in the Mid Continent wells was approximately 48%, and the average working interest in the San Juan wells was 74%. As of December 31, 2003, the
Company operated approximately 5,800 gross (5,500 net) producing wells.



20



---

Drilling Results



The following table sets forth the number of wells drilled or deepened by the Company during the past three years. During 2001, the Company drilled or
deepened 68 development wells (64 net) in Wattenberg, drilled 16 development wells (eight net) in the Illinois Basin and drilled nine development coalbed methane wells (five net) in Utah. 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 gas wells on its grassroots 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 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.



|           |  |      |  |       |  |      
|---------- |  | ---- |  | ----- |  | -----
|           |  | 2001 |  | 2002  |  | 2003 
|Productive |  |      |  |       |  |      
|Gross      |  | 93.0 |  | 140.0 |  | 345.0
|Net        |  | 77.0 |  | 114.0 |  | 318.0
|Dry        |  |      |  |       |  |      
|Gross      |  | 0.0  |  | 4.0   |  | 5.0  
|Net        |  | 0.0  |  | 2.0   |  | 5.0  



At December 31, 2003,
the Company had eight wells (eight net) in Wattenberg, 25 wells (14 net) in the Mid Continent region, and six wells (six 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, 2003. 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. The significant majority of the
Companys leases on undeveloped acreage have no term expiration as they are held by current production from offsetting wells.



|                   |  |           |  |             |  |         |  |        
|------------------ |  | --------- |  | ----------- |  | ------- |  | -------
|                   |  | Developed |  | Undeveloped
|                   |  | Gross     |  | Net         |  | Gross   |  | Net    
|Colorado           |  | 201,900   |  | 180,300     |  | 68,900  |  | 59,400 
|Oklahoma           |  | 275,400   |  | 93,800      |  | 68,300  |  | 26,500 
|Texas              |  | 74,800    |  | 46,000      |  | 32,500  |  | 15,300 
|Wyoming            |  | 10,000    |  | 1,000       |  | 14,200  |  | 9,200  
|Michigan           |  |          |  |            |  | 29,100  |  | 28,800 
|Other              |  | 16,900    |  | 9,400       |  | 19,900  |  | 5,300  
|New Mexico         |  | 25,900    |  | 17,700      |  | 6,700   |  | 3,000  
|Illinois / Indiana |  | 45,500    |  | 37,400      |  | 8,000   |  | 8,000  
|Kansas             |  | 2,700     |  | 2,500       |  | 11,500  |  | 10,500 
|Louisiana / Texas  |  | 17,700    |  | 5,200       |  | 24,800  |  | 6,800  
|                   |  |           |  |             |  |         |  |        
|Total              |  | 670,800   |  | 393,300     |  | 283,900 |  | 172,800
|                   |  |           |  |             |  |         |  |        



21



---

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



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



|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, 2003.



22



---

PART II



|ITEM 5. |  | MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS
|------- |  | -----------------------------------------------------------------------------



The Companys Common Stock is listed on the New York Stock Exchange (NYSE) under the symbol
POG. In June 2002, a 5-for-4 stock split was effected in the form of a 25% stock dividend to common stockholders. In June 2003, the Company declared another 5-for-4 stock split which was effected in the form of a 25% stock dividend to
common stockholders. In February 2004, the Company declared a 2-for-1 stock split in which shareholders received an additional share of the Companys 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
|2002           |  |              |       |     |   |      
|First Quarter  |  | $            | 10.19 |     | $ | 7.90 
|Second Quarter |  |              | 11.98 |     |   | 10.08
|Third Quarter  |  |              | 11.56 |     |   | 8.32 
|Fourth Quarter |  |              | 13.94 |     |   | 10.69
|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



On March 5, 2004, the
closing price of the Common Stock was $26.33.



Holders of Record



As of February 23, 2004, there were 125 holders of record
of the common stock and 69.7 million shares outstanding, exclusive of the 2.5 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 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



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 $66.9 million available for dividends and
or other restricted payments as of December 31, 2003. The amount available for dividends and other restricted payments increases quarterly by 20% of cash flow, as defined.





23



---

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, 2003 (a):



|                                                                           |  |                                                                   |  |                                                     |      |                                                                                         |          
|-------------------------------------------------------------------------- |  | ----------------------------------------------------------------- |  | --------------------------------------------------- | ---- | --------------------------------------------------------------------------------------- | ---------
|Plan category                                                              |  | Number ofsecurities to beissued uponexercise ofoutstandingoptions |  | Weighted-averageexercise price ofoutstandingoptions |      | Number ofsecuritiesremaining availablefor future issuanceunder equitycompensation plans
|Equity compensation plans approved by security holders (stock option plan) |  | 6,457,800                                                         |  | $                                                   | 9.19 |                                                                                         | 2,917,200
|Equity compensation plans not approved by security holders                 |  |                                                                  |  |                                                     |     |                                                                                         |         
|                                                                           |  |                                                                   |  |                                                     |      |                                                                                         |          
|Total                                                                      |  | 6,457,800                                                         |  | $                                                   | 9.19 |                                                                                         | 2,917,200
|                                                                           |  |                                                                   |  |                                                     |      |                                                                                         |          



(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. All such issuances are approved by the Compensation Committee, which is comprised of five independent directors. Issuances to Named
Employees are disclosed in the Companys proxy statements.



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
|2003 |  |                      |  | $                          |     |              | $ |         
|2002 |  | 557,500               |  | $                          | 8.94 |              | $ | 4,985,000
|2001 |  | 306,000               |  | $                          | 6.40 |              | $ | 1,958,000



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 (7) 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.



24



---

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



The following table presents selected historical financial data of the Company for the five-year period ended December 31, 2003. 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 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, |        
|                                          |  | 1999                                     |         |   | 2000 |   |         | 2001 |  |   | 2002    |   |  | 2003 |         
|                                          |  | (In thousands except per share data)     |        
|Statement of Operations Data              |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Revenues                                  |  | $                                        | 91,666  |   |      | $ | 150,342 |      |  | $ | 214,173 |   |  | $    | 222,407  |   |  | $ | 406,717   |  
|Expenses                                  |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Lease operating                           |  |                                          | 11,902  |   |      |   | 13,426  |      |  |   | 25,356  |   |  |      | 27,986   |   |  |   | 54,082    |  
|Production taxes                          |  |                                          | 6,271   |   |      |   | 10,628  |      |  |   | 13,462  |   |  |      | 11,751   |   |  |   | 28,726    |  
|Exploration                               |  |                                          | 666     |   |      |   | 293     |      |  |   | 513     |   |  |      | 2,171    |   |  |   | 6,207     |  
|General and administrative                |  |                                          | 6,212   |   |      |   | 7,165   |      |  |   | 10,994  |   |  |      | 12,714   |   |  |   | 19,034    |  
|Interest and other                        |  |                                          | 10,844  |   |      |   | 10,117  |      |  |   | 7,034   |   |  |      | 2,762    |   |  |   | 9,395     |  
|Impairment of hedges                      |  |                                          |        |   |      |   |        |      |  |   | 6,370   |   |  |      |         |   |  |   |          |  
|Loss on sale of oil and gas properties    |  |                                          |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   | 7,223     |  
|Deferred compensation adjustments         |  |                                          | 2,167   |   |      |   | 12,734  |      |  |   | 3,236   |   |  |      | 9,983    |   |  |   | 33,110    |  
|Depletion, depreciation and amortization  |  |                                          | 40,744  |   |      |   | 40,600  |      |  |   | 49,916  |   |  |      | 66,162   |   |  |   | 98,119    |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Total expenses                            |  |                                          | 78,806  |   |      |   | 94,963  |      |  |   | 116,881 |   |  |      | 133,529  |   |  |   | 255,896   |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Pretax income                             |  |                                          | 12,860  |   |      |   | 55,379  |      |  |   | 97,292  |   |  |      | 88,878   |   |  |   | 150,821   |  
|Provision for income taxes                |  |                                          |        |   |      |   | 12,953  |      |  |   | 35,025  |   |  |      | 31,171   |   |  |   | 57,312    |  
|Cumulative effect of accounting change    |  |                                          |        |   |      |   |        |      |  |   |        |   |  |      |         |   |  |   | 2,613     |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Net income                                |  | $                                        | 12,860  |   |      | $ | 42,426  |      |  | $ | 62,267  |   |  | $    | 57,707   |   |  | $ | 90,896    |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Net income per share                      |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Basic                                     |  | $                                        | 0.13    |   |      | $ | 0.75    |      |  | $ | 1.00    |   |  | $    | 0.88     |   |  | $ | 1.33      |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Diluted                                   |  | $                                        | 0.12    |   |      | $ | 0.61    |      |  | $ | 0.93    |   |  | $    | 0.84     |   |  | $ | 1.28      |  
|                                          |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Weighted average shares outstanding       |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Basic                                     |  |                                          | 47,705  |   |      |   | 52,325  |      |  |   | 62,392  |   |  |      | 65,933   |   |  |   | 68,170    |  
|Diluted                                   |  |                                          | 49,263  |   |      |   | 68,433  |      |  |   | 67,290  |   |  |      | 68,970   |   |  |   | 71,062    |  
|Cash dividends per common share           |  | $                                        | 0.016   |   |      | $ | 0.032   |      |  | $ | 0.054   |   |  | $    | 0.080    |   |  | $ | 0.124     |  
|Balance Sheet Data                        |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Current assets                            |  | $                                        | 19,350  |   |      | $ | 39,368  |      |  | $ | 40,671  |   |  | $    | 49,222   |   |  | $ | 102,032   |  
|Oil and gas properties, net               |  |                                          | 308,035 |   |      |   | 355,904 |      |  |   | 378,011 |   |  |      | 637,258  |   |  |   | 1,068,660 |  
|Total assets                              |  |                                          | 330,765 |   |      |   | 422,578 |      |  |   | 455,524 |   |  |      | 719,090  |   |  |   | 1,196,291 |  
|Current liabilities                       |  |                                          | 19,108  |   |      |   | 30,867  |      |  |   | 45,065  |   |  |      | 69,072   |   |  |   | 142,544   |  
|Debt                                      |  |                                          | 132,000 |   |      |   | 177,000 |      |  |   | 77,000  |   |  |      | 200,000  |   |  |   | 416,000   |  
|Stockholders equity                      |  |                                          | 159,922 |   |      |   | 160,151 |      |  |   | 249,574 |   |  |      | 298,580  |   |  |   | 330,512   |  
|Cash Flow Data                            |  |                                          |         |   |      |   |         |      |  |   |         |   |  |      |          |   |  |   |           |  
|Net cash provided by operating activities |  | $                                        | 49,660  |   |      | $ | 109,384 |      |  | $ | 172,777 |   |  | $    | 152,157  |   |  | $ | 271,825   |  
|Net cash used in investing activities     |  |                                          | (23,669 | ) |      |   | (86,134 | )    |  |   | (82,357 | ) |  |      | (282,392 | ) |  |   | (470,881  | )
|Net cash from financing activities        |  |                                          | (35,451 | ) |      |   | (21,223 | )    |  |   | (92,823 | ) |  |      | 131,905  |   |  |   | 197,681   |  



25



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



|                                         |  |       |         |        |   |         |  |        |         |  |   |        
|---------------------------------------- |  | ----- | ------- | ------ | - | ------- |  | ------ | ------- |  | - | -------
|                                         |  | 2002 
|(In thousands, except per share data)    |  | First |         | Second |   | Third   |  | Fourth
|Revenues                                 |  | $     | 51,886  |        | $ | 50,693  |  | $      | 51,646  |  | $ | 68,182 
|Lease operating expenses                 |  |       | 7,154   |        |   | 6,582   |  |        | 6,397   |  |   | 7,853  
|Production taxes                         |  |       | 2,056   |        |   | 2,877   |  |        | 2,715   |  |   | 4,102  
|General and administrative               |  |       | 2,593   |        |   | 3,453   |  |        | 2,506   |  |   | 4,162  
|Deferred compensation adjustment         |  |       | 4,317   |        |   | 1,752   |  |        | 348     |  |   | 3,566  
|Depletion, depreciation and amortization |  |       | 14,795  |        |   | 16,169  |  |        | 16,625  |  |   | 18,572 
|Net income                               |  |       | 13,077  |        |   | 12,387  |  |        | 13,973  |  |   | 18,270 
|Net income per share(1)                  |  |       |         |        |   |         |  |        |         |  |   |        
|Basic                                    |  | $     | 0.20    |        | $ | 0.19    |  | $      | 0.21    |  | $ | 0.27   
|Diluted                                  |  |       | 0.19    |        |   | 0.18    |  |        | 0.20    |  |   | 0.26   
|Average daily production                 |  |       |         |        |   |         |  |        |         |  |   |        
|Oil (Bbl)                                |  |       | 8,044   |        |   | 8,416   |  |        | 8,644   |  |   | 10,731 
|Gas (Mcf)                                |  |       | 128,189 |        |   | 130,624 |  |        | 137,359 |  |   | 149,089
|Equivalent Mcfe                          |  |       | 176,450 |        |   | 181,122 |  |        | 189,221 |  |   | 213,476
|Average realized prices                  |  |       |         |        |   |         |  |        |         |  |   |        
|Oil (Bbl)                                |  | $     | 23.26   |        | $ | 24.96   |  | $      | 24.69   |  | $ | 24.96  
|Gas (Mcf)                                |  |       | 2.70    |        |   | 2.68    |  |        | 2.43    |  |   | 3.03   
|Equivalent Mcfe                          |  |       | 3.02    |        |   | 3.09    |  |        | 2.89    |  |   | 3.37   



|                                         |  |       |         |        |   |         |  |        |         |  |   |        
|---------------------------------------- |  | ----- | ------- | ------ | - | ------- |  | ------ | ------- |  | - | -------
|                                         |  | 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   



|(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.



26



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|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 southern Oklahoma and the Texas
Panhandle, and the San Juan Basin.



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



During 2003, the Company achieved excellent results in several key areas:



| |  | Daily production increased 44% from 190.1 MMcfe per day in 2002 to 274.0 MMcfe per day in 2003. The Companys Wattenberg properties contributed 25% of this increase, while the
full year benefit of production from Mid Continent properties acquired in 2002 and additional production from Mid Continent properties acquired in 2003 contributed nearly 60%.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Revenues increased 83% from $222.4 million in 2002 to $406.7 million in 2003 primarily due to the 44% increase in production and a 29% increase in realized oil and gas prices. Net
income increased 58% from $57.7 million in 2002 to $90.9 million in 2003. Cash flow from operations increased 79% from $152.2 million in 2002 to $271.8 million in 2003.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Proved Reserves increased 38% from 1.1 Tcfe to 1.5 Tcfe, with acquisitions and ongoing development and performance revisions contributing 374 Bcfe and 163 Bcfe, respectively. In
addition, oil and gas prices increased reserves 14 Bcfe. The reserve increases were offset by 100 Bcfe of production and 36 Bcfe of reserves sold. Exclusive of the impact of higher prices, the Company replaced over 500% of production in 2003 at a
finding and development cost of $0.88 per Mcfe.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | The Company spent $176.1 million on the further development of its properties, as follows:
| | - | ------------------------------------------------------------------------------------------



|                  |  |              |       |                      |     |         |     |          |    |               |   
|----------------- |  | ------------ | ----- | -------------------- | --- | ------- | --- | -------- | -- | ------------- | --
|                  |  | Expenditures |       | Drillings/Deepenings |     | Refracs |     | Trifracs |    | Recompletions
|Wattenberg        |  | $            | 92.1  |                      | 80  |         | 433 |          | 51 |               | 14
|Mid Continent     |  |              | 57.1  |                      | 190 |         | 8   |          |   |               | 12
|San Juan          |  |              | 1.3   |                      | 1   |         |    |          |   |               | 3 
|Central and Other |  |              | 25.6  |                      | 79  |         |    |          |   |               | 91
|                  |  |              |       |                      |     |         |     |          |    |               |   
|Total             |  | $            | 176.1 |                      |     |         |     |          |    |               |   
|                  |  |              |       |                      |     |         |     |          |    |               |   



| |  | The Company spent $307.3 million on acquisitions which were primarily comprised of $23.1 million, $39.7 million, and $239.0 million on the Elysium, LNP, and Cordillera acquisitions,
respectively. Through these acquisitions and those completed in late 2002, the Company materially diversified its asset base by increasing its presence in the Mid Continent and adding a third core area in the San Juan Basin.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



27



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Critical Accounting Policies and Estimates



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



28



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Factors Affecting Financial Condition and Liquidity



Liquidity and Capital Resources



During 2003, the Company spent $176.1 million on the further development of properties and $307.3 million on acquisitions. Acquisition expenditures were
primarily comprised of $23.1 million and $39.7 million on the Elysium and Le Norman Partners purchases, respectively, and $239.0 million on the Cordillera acquisition, exclusive of $4.0 million attributed to the warrants issued. Development
expenditures included $92.1 million in Wattenberg for the drilling or deepening of 39 J-Sand wells, the drilling of 41 Codell wells, and performing 433 Codell refracs, 51 Codell trifracs and 14 recompletions, $57.1 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 190 wells, and performing eight refracs and 12 recompletions, $1.3 million in the San Juan Basin, and $25.6 million on
other properties (primarily in Illinois and Kansas), primarily for drilling or deepening 79 wells and performing 91 recompletions. These acquisitions and projects, and the continued success in production enhancement allowed production to increase
44% over the prior year. On October 1, 2003, the Company expended $243.0 million on the Cordillera acquisition. The Cordillera properties are primarily located in the Mid Continent, the San Juan Basin, and the Permian Basin and primarily produce
gas. The decision to increase or decrease development activity is heavily dependent on the prices being received for production.



At December 31, 2003, the Company had $1.2 billion of assets. Total capitalization was $746.5 million, of which 44% was represented by stockholders
equity and 56% by bank debt. During 2003, net cash provided by operations totaled $271.8 million, as compared to $152.2 million in 2002 ($279.8 million and $158.9 million prior to changes in working capital, respectively). At December 31, 2003,
there were no significant commitments for capital expenditures. Based upon a $210.0 million capital budget for 2004, the Company expects production to continue to increase in the coming year. The level of these and other future expenditures is
largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly, depending on available opportunities and market conditions. The Company plans to finance its ongoing development, acquisition
and exploration expenditures and additional equity repurchases using internal cash flow, proceeds from asset sales and bank borrowings. In addition, joint ventures or future public and private offerings of debt or equity securities may be utilized.



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



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



The following summarizes the Companys contractual obligations at December 31, 2003 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                     |  | $                 |      |            | $ |           |  | $            | 416,000 |       | $ |      |  | $ | 416,000
|Firm transportation agreement      |  |                   | 582   |            |   | 1,164      |  |              | 1,164   |       |   | 8,776 |  |   | 11,686 
|Non-cancelable operating leases    |  |                   | 1,207 |            |   | 2,961      |  |              | 2,541   |       |   |      |  |   | 6,709  
|                                   |  |                   |       |            |   |            |  |              |         |       |   |       |  |   |        
|Total contractual cash obligations |  | $                 | 1,789 |            | $ | 4,125      |  | $            | 419,705 |       | $ | 8,776 |  | $ | 434,395
|                                   |  |                   |       |            |   |            |  |              |         |       |   |       |  |   |        



29



---

Banking



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



|                          |  |                   |         |             |   |           |  |   |       
|------------------------- |  | ----------------- | ------- | ----------- | - | --------- |  | - | ------
|                          |  | December 31, 2003
|                          |  | BorrowingBase     |         | Outstanding |   | Available
|Revolving Credit Facility |  | $                 | 500,000 |             | $ | 416,000   |  | $ | 84,000
|                          |  |                   |         |             |   |           |  |   |       



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, 2003. Patina had $84.0 million available under the Credit Agreement at December 31, 2003.



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 2.7% during 2003 and 2.7% at December 31, 2003.



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



The Credit
Agreement contains financial covenants, including but not limited to a maximum total debt to EBITDA ratio, as defined, and a minimum current ratio. It also contains negative covenants, including but not limited to restrictions on indebtedness;
certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers; changes in fiscal year; transactions with
affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge causes; issuance of securities; and
non-speculative commodity hedging. At December 31, 2002 and 2003, the Company was in compliance with the covenants. Borrowings under the Credit Agreement mature in January 2007, but may be prepaid at anytime. The Company had a restricted payment
basket under the Credit Agreement of $66.9 million as of December 31, 2003, 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 2004, 2005, and 2006, respectively. The $176.1 million of development expenditures for 2003 were
funded entirely with internal cash flow. The $307.3 million of acquisition expenditures were largely funded by bank borrowings, somewhat offset by current year cash flow from operations. The 2004 capital budget of $210.0 million, comprised primarily
of $110.0 million of development expenditures in Wattenberg, $70.0 million in the Mid Continent region, $15.0 million in the San Juan Basin, and $15.0 million on the Central and Other properties, is expected to increase production by approximately
17% to 20%. The purchase price for the Elysium acquisition was $23.1 million and the purchase price for the LNP properties was $39.7 million. On October 1, 2003, the Company acquired the Cordillera properties for $243.0 million, comprised of $239.0
million of cash 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. On December 31, 2003, the Company had $416.0 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 internal cash flow.



30



---

Net cash provided by operating activities in 2001, 2002 and 2003 was $172.8 million, $152.2 million and
$271.8 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). Operating cash flows in 2002 and 2003 were benefited by $3.5 million and $10.6 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 2001, 2002 and 2003 totaled $82.4 million, $282.4 million and $470.9 million, respectively. Capital expenditures in 2001 were largely comprised of development expenditures of
$77.3 million ($65.6 million in Wattenberg) and the initiation of our grassroots projects, somewhat offset by $16.5 million of proceeds from sales of assets, primarily Elysiums properties in the Lake Washington Field in Louisiana. The increase
in expenditures in 2002 was due to the Mid Continent acquisitions for total cash consideration of $180.4 million and the increase in development expenditures to $97.4 million ($82.2 million in Wattenberg). The further 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.



Net cash used in financing activities in 2001 was $92.8 million, while net cash provided by financing activities was $131.9 million and $197.7 million in
2002 and 2003, respectively. Sources of financing have been primarily bank borrowings. During 2001, the combination of operating cash flow, proceeds from the exercise of the Companys $4.00 warrants for $36.0 million, refinancing of the Elysium
loan, and proceeds from the sale of the Lake Washington properties, allowed the Company to repay $100.0 million of bank debt, repurchase $51.5 million of equity securities and fund capital development and acquisition expenditures of $88.1 million.
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.



Capital Requirements



During 2003, $466.5 million of capital, net of $16.9 million of property sales, was expended, including $176.1 million on development projects and $307.3
million on acquisitions. Development expenditures represented approximately 63% of internal cash flow (defined as net cash provided by operations before changes in working capital). The Company manages its capital budget with the goal of funding it
with internal cash flow. The 2004 development capital budget of $210.0 million is expected to increase production by approximately 17% to 20%. Based on current futures prices for oil and natural gas, the Company expects its 2004 capital program to
be funded with internal cash flow. The purchase price for the Elysium acquisition was $23.1 million, the purchase price for the LNP properties was $39.7 million, and the purchase price for the Cordillera Acquisition was $243.0 million, comprised of
$239.0 million of cash funded with borrowings under the Companys bank facility and the issuance of five year warrants to purchase 1.0 million shares of Patina common stock for $22.50 per share. As such, exclusive of any other acquisitions or
significant equity repurchases, management expects to reduce long-term debt in 2004. Development and exploration activities are highly discretionary, and, for the foreseeable future, management expects such activities to be maintained at levels
equal to or below internal cash flow.



31



---

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 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 one year and an additional $100.0 million for two years. At December 31, 2003, the net unrealized pretax gains on these
contracts totaled $421,000 ($261,000 gain net of $160,000 of deferred taxes) based on LIBOR futures prices at December 31, 2003.



The Company regularly enters into hedging agreements to reduce the impact on its operations of fluctuations in oil and gas prices. All such contracts are
entered into solely to hedge prices and limit volatility. The Companys current policy is to hedge between 50% and 75% of its production, when futures prices justify, on a rolling 12 to 36 month basis. At December 31, 2003, hedges were in place
covering 78.8 Bcf at prices averaging $4.00 per MMBtu and 12.2 million barrels of oil averaging $25.03 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 $88.4 million ($54.8 million loss net of $33.6 million of deferred taxes) at December 31, 2003. 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 $137,000, a non-current asset of $1.9 million, a current liability of $62.3 million, and a non-current liability of $27.6 million based on contract expiration. The gas contracts settle monthly through December 2005 while
the 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. Net pretax gains relating to these derivatives
were $4.1 million and $20.4 million in 2001 and 2002 and a pretax loss of $50.4 million in 2003, 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.



32



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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 2002 and 2003. Average price computations exclude hedging gains and losses and other nonrecurring items to provide
comparability. Average prices per Mcfe indicate the composite impact of changes in oil and natural gas prices. Oil production is converted to natural gas equivalents at the rate of one barrel per six Mcf.



|          |  |                |       |            |   |               |  |   |     
|--------- |  | -------------- | ----- | ---------- | - | ------------- |  | - | ----
|          |  | Average Prices
|          |  | Oil            |       | NaturalGas |   | EquivalentMcf
|          |  | (Per Bbl)      |       | (Per Mcf)  |   | (Per Mcfe)   
|Annual    |  |                |       |            |   |               |  |   |     
|1999      |  | $              | 17.71 |            | $ | 2.21          |  | $ | 2.40
|2000      |  |                | 29.16 |            |   | 3.69          |  |   | 3.96
|2001      |  |                | 24.99 |            |   | 3.42          |  |   | 3.63
|2002      |  |                | 25.71 |            |   | 2.23          |  |   | 2.81
|2003      |  |                | 30.17 |            |   | 4.21          |  |   | 4.49
|          |  |                |      
|Quarterly |  |                |       |            |   |               |  |   |     
|          |  |                |      
|2002      |  |                |       |            |   |               |  |   |     
|First     |  | $              | 21.02 |            | $ | 2.06          |  | $ | 2.45
|Second    |  |                | 25.72 |            |   | 2.25          |  |   | 2.81
|Third     |  |                | 27.74 |            |   | 1.74          |  |   | 2.53
|Fourth    |  |                | 27.51 |            |   | 2.80          |  |   | 3.34
|          |  |                |      
|2003      |  |                |       |            |   |               |  |   |     
|First     |  | $              | 33.33 |            | $ | 4.26          |  | $ | 4.69
|Second    |  |                | 28.18 |            |   | 4.02          |  |   | 4.27
|Third     |  |                | 29.40 |            |   | 4.27          |  |   | 4.49
|Fourth    |  |                | 30.30 |            |   | 4.27          |  |   | 4.53



33



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Results of Operations



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



Average realized oil
prices increased 5.2% 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.



34



---

Interest and other expenses increased to $9.4 million in 2003, an increase of 240% 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 shares 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 Company expects to record a 38% provision for income taxes in 2004. The increase in the effective tax
rate was due to the expiration of Section 29 tax credits as of December 31, 2002.



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



Comparison of 2002 to 2001.Revenues for 2002 totaled $222.4 million, a 4% increase over 2001. Net
income for 2002 totaled $57.7 million compared to $62.3 million in 2001. The increase in revenue was due primarily to increases in production, which more than offset decreases in oil and gas prices, while the decrease in net income was due primarily
to increases in depletion expense and the deferred compensation adjustment.



Average daily oil and gas production in 2002 totaled 8,965 barrels and 136.4 MMcf (190.2 MMcfe), an increase of 22% on an equivalent basis from 2001. The rise in production was due to the increased level of capital
expenditures in Wattenberg and to a lesser extent from the Le Norman and Bravo properties purchased in the fourth quarter of 2002. During 2002, 66 wells were drilled or deepened and 447 refracs and 11 recompletions were performed in Wattenberg,
compared to 68 new wells or deepenings and 323 refracs and seven recompletions in 2001. The Company drilled or deepened 38 wells and performed 52 recompletions on the Elysium properties during 2002. The Company also drilled 33 wells on the recently
acquired Mid Continent properties in 2002. The Company drilled four wells and five coal bed methane wells in 2002 on its grassroots projects compared to nine coal bed methane wells in 2001. The following table sets forth summary information with
respect to oil and natural gas production for the years ended December 31, 2001 and 2002:



35



---

|                  |  |                    |  |                    |  |                      |  |         |  |         |  |        |  |         |  |         |  |       
|----------------- |  | ------------------ |  | ------------------ |  | -------------------- |  | ------- |  | ------- |  | ------ |  | ------- |  | ------- |  | ------
|                  |  | Oil (Bbls per day) |  | Gas (Mcfs per day) |  | Total (Mcfe per day)
|                  |  | 2001               |  | 2002               |  | Change               |  | 2001    |  | 2002    |  | Change |  | 2001    |  | 2002    |  | Change
|Wattenberg        |  | 5,101              |  | 6,405              |  | 1,304                |  | 110,286 |  | 132,177 |  | 21,891 |  | 140,893 |  | 170,602 |  | 29,709
|Mid Continent     |  |                   |  | 365                |  | 365                  |  |        |  | 1,844   |  | 1,844  |  |        |  | 4,029   |  | 4,029 
|Central and Other |  | 2,190              |  | 2,195              |  | 5                    |  | 2,049   |  | 2,355   |  | 306    |  | 15,186  |  | 15,535  |  | 349   
|                  |  |                    |  |                    |  |                      |  |         |  |         |  |        |  |         |  |         |  |       
|Total             |  | 7,291              |  | 8,965              |  | 1,674                |  | 112,335 |  | 136,376 |  | 24,041 |  | 156,079 |  | 190,166 |  | 34,087
|                  |  |                    |  |                    |  |                      |  |         |  |         |  |        |  |         |  |         |  |       



Average realized oil
prices decreased 5% from $25.72 per barrel in 2001 to $24.52 in 2002. Average realized gas prices decreased 22% from $3.48 per Mcf in 2001 to $2.72 in 2002. Average oil prices include hedging gains of $1.9 million or $0.73 per barrel in 2001 and
hedging losses of $3.9 million or $1.19 per barrel in 2002. Average gas prices included hedging gains of $2.1 million or $0.05 per Mcf in 2001 and $24.3 million or $0.49 per Mcf in 2002. The following table sets forth summary information with
respect to oil and natural gas prices for the years ended December 31, 2001 and 2002:



|              |  |            |       |      |           |       |        |              |   |       |   |      |   |        |  |   |      |  |      |       |        |  |   |      |  |   |      |  |   |       |  
|------------- |  | ---------- | ----- | ---- | --------- | ----- | ------ | ------------ | - | ----- | - | ---- | - | ------ |  | - | ---- |  | ---- | ----- | ------ |  | - | ---- |  | - | ---- |  | - | ----- | -
|              |  | Oil $/Bbls |       |      | Gas $/Mcf |       |        | Total $/Mcfe |  
|              |  | 2001       |       | 2002 |           |       | Change |              |   | 2001  |   | 2002 |   | Change |  |   | 2001 |  | 2002 |       | Change | 
|Wattenberg    |  | $          | 25.51 |      | $         | 26.29 |        |              | $ | 0.78  |   |      | $ | 3.42   |  | $ | 2.20 |  | $    | (1.22 | )      |  | $ | 3.60 |  | $ | 2.69 |  | $ | (0.91 | )
|Mid Continent |  |            |      |      |           | 26.12 |        |              |   | 26.12 |   |      |   |       |  |   | 4.12 |  |      | 4.12  |        |  |   |     |  |   | 4.25 |  |   | 4.25  |  
|Other         |  |            | 23.78 |      |           | 23.95 |        |              |   | 0.17  |   |      |   | 4.02   |  |   | 2.48 |  |      | (1.54 | )      |  |   | 3.97 |  |   | 3.76 |  |   | (0.21 | )
|              |  |            |       |      |           |       |        |              |   |       |   |      |   |        |  |   |      |  |      |       |        |  |   |      |  |   |      |  |   |       |  
|Subtotal      |  |            | 24.99 |      |           | 25.71 |        |              |   | 0.72  |   |      |   | 3.43   |  |   | 2.23 |  |      | (1.20 | )      |  |   | 3.64 |  |   | 2.81 |  |   | (0.83 | )
|Hedging       |  |            | 0.73  |      |           | (1.19 | )      |              |   | (1.92 | ) |      |   | 0.05   |  |   | 0.49 |  |      | 0.44  |        |  |   | 0.07 |  |   | 0.29 |  |   | 0.22  |  
|              |  |            |       |      |           |       |        |              |   |       |   |      |   |        |  |   |      |  |      |       |        |  |   |      |  |   |      |  |   |       |  
|Total         |  | $          | 25.72 |      | $         | 24.52 |        |              | $ | (1.20 | ) |      | $ | 3.48   |  | $ | 2.72 |  | $    | (0.76 | )      |  | $ | 3.71 |  | $ | 3.10 |  | $ | (0.61 | )
|              |  |            |       |      |           |       |        |              |   |       |   |      |   |        |  |   |      |  |      |       |        |  |   |      |  |   |      |  |   |       |  



Lease operating
expenses totaled $28.0 million or $0.40 per Mcfe for 2002 compared to $25.4 million or $0.45 per Mcfe in the prior year. The increase in operating expenses was primarily attributed to increased production and the Le Norman and Bravo acquisitions.
Production taxes totaled $11.8 million or $0.17 per Mcfe in 2002 compared to $13.5 million or $0.24 per Mcfe in 2001. The $1.7 million decrease was primarily due to lower oil and gas prices.



General and administrative expenses in 2002, net of reimbursements, totaled
$12.7 million, an increase of $1.7 million or 16% from 2001. The increase was primarily due to the Le Norman and Bravo acquisitions.



Interest and other expenses fell to $2.8 million in 2002, a decrease of 61% from the prior year. Interest expense decreased as a result of lower average
debt balances and lower average interest rates. The Companys average interest rate in 2002 was 2.9% compared to 5.8% in 2001.



Deferred compensation adjustment totaled $10.0 million in 2002, an increase of $6.7 million from the prior year. The increase relates to the greater
increase in value of the Companys common shares and other investments held in a deferred compensation plan during 2002. The Companys common stock price appreciated by 44% or $3.86 per share in 2002 versus 15% or $1.12 per share in 2001.



Depletion, depreciation and amortization expense for 2002
totaled $66.2 million, an increase of $16.2 million or 33% from 2001. Depletion expense totaled $64.7 million or $0.93 per Mcfe for 2002 compared to $48.9 million or $0.86 per Mcfe for 2001. The increase in depletion expense resulted primarily from
the 22% increase in oil and gas production in 2002 and a higher depletion rate. The depletion rate was increased in the fourth quarter of 2001 in conjunction with the completion of the year-end 2001 reserve report. The increase reflected the lower
oil and gas reserves resulting from lower year-end oil and gas prices. Depreciation and amortization expense in 2002 totaled $1.4 million compared to $1.0 million in 2001 or $0.02 per Mcfe for both years.



Provision for income taxes for 2002 totaled $31.2 million, a decrease of $3.9
million from 2001. The decrease was due to a 9% decrease in pretax income and a slight decrease in the Companys effective tax rate. The Company recorded a 35% tax provision for 2002 compared to a 36% tax provision in 2001.



36



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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.



The FASB is currently evaluating the application of certain provisions of SFAS No. 141, Business Combinations, and SFAS No. 142,
Goodwill and Other Intangible Assets, to companies in the extractive industries, including oil and gas companies. The FASB is considering whether the provisions of SFAS No. 141 and SFAS No.142 require registrants to classify costs
associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other oil and gas property costs, and provide specific footnote disclosures.



37



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Historically, the Company has included oil and gas lease acquisition costs as a component of oil and gas
properties. In the event the FASB determines that costs associated with mineral rights are required to be classified as intangible assets, approximately $580.8 million of the Companys oil and gas property acquisition costs may be required to
be separately classified on its balance sheets as intangible assets. However, the Company currently believes that its results of operations and financial condition would not be affected since such intangible assets would continue to be depleted and
assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. The Company does not believe the classification of oil and gas lease acquisition costs as intangible assets would have any impact on
the Companys compliance with covenants under its debt agreements.



|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 2003, exclusive of any hedges, ranged from a monthly low of $3.45 per Mcf to a monthly high of $5.37 per Mcf. Oil prices, exclusive of any hedges, ranged from a monthly low of
$27.35 per barrel to a monthly high of $35.15 per barrel during 2003. A significant decline in prices of oil or natural gas could have a material adverse effect on the Companys financial condition and results of operations.



In 2003, a 10% reduction in oil and gas prices, excluding oil and gas
quantities that were fixed through hedging transactions, would have reduced revenues by $14.2 million. If oil and gas future prices at December 31, 2003 had declined by 10%, the net unrealized hedging losses at that date would have decreased by
$70.8 million (from $88.4 million to $17.6 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 and $25.1 million in 2002 and 2003,
respectively, and a gain of $1.9 million in 2001, 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 loss of $25.3 million in 2003, and gains of $2.1 million and $24.3 million in 2001 and 2002, respectively, related to these contracts.



At December 31, 2003, the Company was a party to swap
contracts for oil based on NYMEX prices covering approximately 14,350 barrels of oil per day for 2004 at fixed prices ranging from $23.03 to $29.40 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price
for the swap contracts is $24.85 per barrel for 2004. The Company also entered into swap contracts for oil for 2005 and 2006 as of December 31, 2003, which are summarized in the table below. The net unrealized losses on these contracts totaled $40.8
million based on NYMEX futures prices at December 31, 2003.



At
December 31, 2003, the Company was a party to swap contracts for natural gas based on CIG, EPSJ, ANR and Panhandle Eastern Pipeline (PEPL) index prices covering approximately 129,500 MMBtus per day for 2004 at fixed prices ranging
from $2.83 to $5.64 per MMBtu. The overall weighted average hedged price for the swap contracts is $4.04 per MMBtu for 2004. The Company also entered into natural gas swap contracts for 2005 as of December 31, 2003, which are summarized in the table
below. The net unrealized losses on these contracts totaled $47.6 million based on futures prices at December 31, 2003.



38



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At December 31, 2003, 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) |  
|01/01/04 - 03/31/04 |  | 13,450            |  | 25.44 |                               | $                                   | (7,991  | ) |                  | 95,000 |         | 4.23 |                                     | $ | (8,363  | )
|04/01/04 - 06/30/04 |  | 14,350            |  | 24.93 |                               |                                     | (7,277  | ) |                  | 90,000 |         | 3.58 |                                     |   | (6,078  | )
|07/01/04 - 09/30/04 |  | 14,750            |  | 24.69 |                               |                                     | (6,207  | ) |                  | 90,000 |         | 3.57 |                                     |   | (6,630  | )
|10/01/04 - 12/31/04 |  | 14,800            |  | 24.43 |                               |                                     | (5,555  | ) |                  | 77,000 |         | 3.93 |                                     |   | (4,995  | )
|                    |  |                   |  |       |                               |                                    
|2005                |  | 13,700            |  | 24.78 |                               |                                     | (12,833 | ) |                  | 55,000 |         | 3.65 |                                     |   | (10,553 | )
|2006                |  | 5,400             |  | 26.11 |                               |                                     | (971    | ) |                  |       |         |     |                                     |   |        |  



|                    |  |                                     |  |         |                                |                                     |        |   |                  |       |         |      |                                     |   |      |  
|------------------- |  | ----------------------------------- |  | ------- | ------------------------------ | ----------------------------------- | ------ | - | ---------------- | ----- | ------- | ---- | ----------------------------------- | - | ---- | -
|                    |  | Natural Gas Swaps (ANR/PEPLIndexes) |  |         | Natural Gas Swaps (EPSJ Index) |                                    
|Time Period         |  | DailyVolumeMMBtu                    |  | $/MMBtu |                                | UnrealizedGain (Loss) ($/thousands) |        |   | DailyVolumeMMBtu |       | $/MMBtu |      | UnrealizedGain (Loss) ($/thousands) |  
|01/01/04 - 03/31/04 |  | 31,800                              |  | 4.90    |                                | $                                   | (2,510 | ) |                  | 7,300 |         | 4.86 |                                     | $ | (262 | )
|04/01/04 - 06/30/04 |  | 33,500                              |  | 4.35    |                                |                                     | (1,700 | ) |                  | 8,300 |         | 4.16 |                                     |   | (255 | )
|07/01/04 - 09/30/04 |  | 34,700                              |  | 4.31    |                                |                                     | (1,842 | ) |                  | 9,000 |         | 4.15 |                                     |   | (303 | )
|10/01/04 - 12/31/04 |  | 32,700                              |  | 4.52    |                                |                                     | (1,659 | ) |                  | 8,600 |         | 4.36 |                                     |   | (277 | )
|                    |  |                                     |  |         |                                |                                    
|2005                |  | 25,000                              |  | 4.52    |                                |                                     | (1,688 | ) |                  | 6,000 |         | 4.11 |                                     |   | (448 | )



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, 2002 and 2003, the Company had zero and $9.9 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. Based on futures prices as of December 31, 2003, the CIG basis differential for 2004 averages an $0.80 per MMBtu discount, ranging from a discount of $1.04 per MMBtu in January 2004 to a discount of $0.64
per MMBtu in December 2004. The decrease in the CIG basis differential is believed to be in part due to the pipeline expansions made in 2003 (primarily the Kern River expansion of 900 MMBtu per day in May 2003) resulting in an increase in gas
pipeline capacity for transportation out of the Rocky Mountain region.



Interest Rate Risk



At December 31, 2003, the
Company had $416.0 million outstanding under its credit facility with an average interest rate of 2.7%. 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 2.7% during 2003. Assuming no change in the amount
outstanding at December 31, 2003, the annual impact on interest expense of a ten percent change in the average interest rate would be approximately $690,000, net of tax. As the interest rate is variable and is reflective of current market
conditions, the carrying value approximates the fair value.



39



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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
|-------- |  | -----------------------



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. There were no significant changes in the Companys internal controls or in other factors that could significantly affect these controls, since the date the controls were
evaluated.



40



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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 2003 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     |  | 53  |  | Chairman and Chief Executive Officer, Chairman of the Board
|Jay W. Decker         |  | 52  |  | President and Director                                     
|David J. Kornder      |  | 43  |  | Executive Vice President and Chief Financial Officer       
|Andrew M. Ashby       |  | 48  |  | Senior Vice President - Operations                         
|David D. Le Norman(1) |  | 41  |  | Senior Vice President - Business Development               
|Barton R. Brookman    |  | 41  |  | Vice President                                             
|James A. Lillo        |  | 49  |  | Vice President                                             
|Terry L. Ruby         |  | 45  |  | Vice President                                             
|Donald R. Shaw        |  | 45  |  | Vice President                                             
|David W. Siple        |  | 44  |  | Vice President                                             
|Jeffrey L. Berenson   |  | 53  |  | Director                                                   
|Robert J. Clark       |  | 59  |  | Director                                                   
|Elizabeth K. Lanier   |  | 52  |  | Director                                                   
|Alexander P. Lynch    |  | 51  |  | Director                                                   
|Paul M. Rady          |  | 50  |  | Director                                                   

---

|(1) | Mr. Le Norman resigned on March 1, 2004.
|--- | ----------------------------------------



Thomas J. Edelman founded the Company and has served as Chairman of the Board, Chairman and Chief Executive Officer since its formation. 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 and is a Director of Star Gas Corporation.



Jay W. Decker has served as President since March 1998 and as a
Director since 1996. He was formerly the Executive Vice President and a Director of Hugoton Energy Corporation, a public independent oil company since 1995. From 1989 until its merger into Hugoton Energy in 1995, Mr. Decker was the President and
Chief Executive Officer of Consolidated Oil & Gas, Inc., a private independent oil company and President of a predecessor company. Prior to 1989, Mr. Decker served as Vice PresidentOperations for General Atlantic Energy Company and in
various capacities with Peppermill Oil Company, Wainoco Oil & Gas and Shell Oil Company. Mr. Decker received his Bachelor of Science Degree in Petroleum Engineering from the University of Wyoming.



David J. Kornder has served as Executive Vice President and Chief
Financial Officer since 1996. Prior to that time, he served as Vice PresidentFinance of 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.



41



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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.



David D. Le Normanhas served as Senior Vice President since joining the Company in November 2002. From 1995 to 2002, Mr. Le Norman was the President and founder of Le Norman Energy Corporation until it was acquired by the Company in
November 2002. From 1987 to 1995, Mr. Le Norman worked in various engineering and business development capacities at Texaco. Mr. Le Norman received his Bachelor of Science Degree in Petroleum Engineering from the University of Wyoming and his M.B.A.
from Oklahoma City University. Mr. Le Norman resigned on March 1, 2004.



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.



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  Technology 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 Snyder Oil Corporation. 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.



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.



42



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Robert J. Clark has served as a Director since 1996. Mr. Clark is the President of Bear Cub
Investments LLC, a private gas gathering and processing company. 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. Mr.
Clark also serves as a Director of Evergreen Resources, Inc.



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.



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.



43



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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.



The Board has established five 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. Messrs. Berenson, Clark, Lanier, Lynch
and Rady are the members of the Audit Committee.



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 Messrs. Berenson, Clark, Lanier, Lynch and Rady.



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 Messrs. Berenson, Clark, Lanier, Lynch and Rady.



Dividend Committee. The Dividend Committee is authorized and directed to approve the payment of dividends. The members of the Dividend Committee
are Messrs. Edelman and Kornder.



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 Messrs. Edelman and Lynch.



|ITEM 11. |  | COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
|-------- |  | ------------------------------------------------



Information with respect to officers compensation is incorporated herein by reference to the Companys 2004 Proxy Statement.



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



Information with respect to security ownership of certain beneficial owners and management is incorporated herein by reference to the Companys 2004
Proxy Statement.



|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 2004 Proxy Statement.



44



---

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 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)                                                                                                                                                                                                                                                 
|     | 
|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  |  | Bylaws (Incorporated herein by reference to Exhibit 3.3 to the Companys Registration Statement on Form S-4 (Registration No. 333-572))                                                                                                                                                                                                                                                                                                                                         
|     | 
|3.3  |  | Amended and Restated Bylaws of Patina Oil & Gas Corporation. (Incorporated herein by reference to Exhibit 3.2 of the Companys Form 8-K filed on May 25, 2001)                                                                                                                                                                                                                                                                                                                  
|     | 
|3.4  |  | 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. (Incorporated herein by reference to Exhibit 3.2 of the Companys Form 8-K filed on May 25, 2001)                                                                                                                                                                                                                                                                                                                                                             
|     | 
|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)



45



---

|       |  |                                                                                                                                                                                                                                                                                                                               
|------ |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|       | 
|10.1.1 |  | First Amendment to the Third Amended and Restated Credit Agreement dated January 28, 2003 by and among the Company, as borrower, Bank One, NA, as Administrative Agent, and certain other
financial institutions (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)
|       | 
|10.5.1 |  | 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)                                                                                                                                                   
|       | 
|10.5.2 |  | 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)                                                                                                                               
|       | 
|10.5.3 |  | Patina Oil & Gas Corporation 1996 Employee Stock Option Plan (Incorporated by reference to Exhibit 10.20 of the Companys Registration Statement on Form S-4 (Registration No.
33300-572))                                                                                                                                    
|       | 
|10.5.4 |  | 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   |  | 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)                                                                            
|       | 
|10.6.1 |  | Amendment of Lease Agreement dated December 21, 2000 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)                                                                                   
|       | 
|10.6.2 |  | Second Amendment of Lease Agreement dated December 21, 2000 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)                                                                            
|       | 
|10.6.3 |  | Third Amendment of Lease Agreement dated December 21, 2000 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant *                                                                                                                                                                                  



46



---

|     |  |                                                                                                                                                                                                                  
|---- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|     | 
|10.7 |  | 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)
|     | 
|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 March 9, 2004, 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 March 9, 2004, 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 1, 2003 to incorporate by reference a press release dated October 1, 2003 announcing the closing
of the acquisition of Cordillera Energy Partners, L.L.C.



The
Company filed a current report on Form 8-K/A amending the October 1, 2003 Form 8-K providing financial information as required by Item 7 for the acquisition of Cordillera Energy Partners, L.L.C.



The Company filed a current report on Form 8-K on October 30, 2003 to
furnish the information required under Item 12 related to the Companys September 30, 2003 press release announcing the Companys financial results for the three months ended September 30, 2003.



| | (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.



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



47



---

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: |  | March 9, 2004 |  |                              |  | By: |  | /s/ Thomas J. Edelman                                 
|      |  |               |  |                              |  |     |  |                                                       
|      |  |               |  |                              |  |     |  | Thomas J. Edelman Chairman and Chief Executive Officer



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 and Chief Executive Officer (Principal Executive Officer)                                |  | March 9, 2004
|                                           |  |                                                                                                  
|/s/ Jay W. DeckerJay W. Decker             |  | President and Director                                                                            |  | March 9, 2004
|                                           |  |                                                                                                  
|/s/ David J. KornderDavid J. Kornder       |  | Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) |  | March 9, 2004
|                                           |  |                                                                                                  
|/s/ Jeffrey L. BerensonJeffrey L. Berenson |  | Director                                                                                          |  | March 9, 2004
|                                           |  |                                                                                                  
|/s/ Robert J. ClarkRobert J. Clark         |  | Director                                                                                          |  | March 9, 2004
|                                           |  |                                                                                                  
|/s/ Elizabeth K. LanierElizabeth K. Lanier |  | Director                                                                                          |  | March 9, 2004
|                                           |  |                                                                                                  
|/s/ Alexander P. LynchAlexander P. Lynch   |  | Director                                                                                          |  | March 9, 2004
|                                           |  |                                                                                                  
|/s/ Paul M. RadyPaul M. Rady               |  | Director                                                                                          |  | March 9, 2004



48



---

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.



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.



49



---

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



Present Value. 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.



50



---

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                                                                                  |  |     
|----------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                                                                                  |  | Page
|PATINA OIL & GAS CORPORATION                                                                                                                                      |  |     
|                                                                                                                                                                  | 
|Independent Auditors Report                                                                                                                                      |  | F-2 
|                                                                                                                                                                  | 
|Consolidated Balance Sheets as of December 31, 2002 and 2003                                                                                                      |  | F-3 
|                                                                                                                                                                  | 
|Consolidated Statements of Operations for the years ended December 31, 2001, 2002 and 2003                                                                        |  | F-4 
|                                                                                                                                                                  | 
|Consolidated Statements of Changes in Stockholders Equity and Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2001, 2002 and 2003 |  | F-5 
|                                                                                                                                                                  | 
|Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2002 and 2003                                                                        |  | F-6 
|                                                                                                                                                                  | 
|Notes to Consolidated Financial Statements                                                                                                                        |  | F-7 



F-1



---

INDEPENDENT AUDITORS REPORT



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, 2002 and 2003, 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, 2003. 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 auditing standards generally accepted in the
United States of America. 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, 2002 and 2003, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.



As discussed in Note 2 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.



/s/ DELOITTE & TOUCHE LLP



Denver, Colorado

March 5, 2004



F-2



---

PATINA OIL & GAS CORPORATION



CONSOLIDATED BALANCE SHEETS

(In thousands except share data)



|                                                                                               |  |              |           |   |      |   |           |  
|---------------------------------------------------------------------------------------------- |  | ------------ | --------- | - | ---- | - | --------- | -
|                                                                                               |  | December 31, |          
|                                                                                               |  | 2002         |           |   | 2003 |  
|ASSETS                                                                                         |  |              |           |   |      |   |           |  
|Current assets                                                                                 |  |              |           |   |      |   |           |  
|Cash and equivalents                                                                           |  | $            | 1,920     |   |      | $ | 545       |  
|Accounts receivable                                                                            |  |              | 33,555    |   |      |   | 59,973    |  
|Inventory and other                                                                            |  |              | 5,453     |   |      |   | 17,736    |  
|Deferred income taxes                                                                          |  |              |          |   |      |   | 23,641    |  
|Unrealized hedging gains                                                                       |  |              | 8,294     |   |      |   | 137       |  
|                                                                                               |  |              |           |   |      |   |           |  
|                                                                                               |  |              | 49,222    |   |      |   | 102,032   |  
|                                                                                               |  |              |           |   |      |   |           |  
|Unrealized hedging gains                                                                       |  |              | 15,558    |   |      |   | 1,867     |  
|                                                                                               |  |             
|Oil and gas properties, successful efforts method                                              |  |              | 1,104,205 |   |      |   | 1,628,750 |  
|Accumulated depletion, depreciation and amortization                                           |  |              | (466,947  | ) |      |   | (560,090  | )
|                                                                                               |  |              |           |   |      |   |           |  
|                                                                                               |  |              | 637,258   |   |      |   | 1,068,660 |  
|                                                                                               |  |              |           |   |      |   |           |  
|Field equipment and other                                                                      |  |              | 12,194    |   |      |   | 15,027    |  
|Accumulated depreciation                                                                       |  |              | (5,087    | ) |      |   | (6,506    | )
|                                                                                               |  |              |           |   |      |   |           |  
|                                                                                               |  |              | 7,107     |   |      |   | 8,521     |  
|                                                                                               |  |              |           |   |      |   |           |  
|Other assets, net                                                                              |  |              | 9,945     |   |      |   | 15,211    |  
|                                                                                               |  |              |           |   |      |   |           |  
|                                                                                               |  | $            | 719,090   |   |      | $ | 1,196,291 |  
|                                                                                               |  |              |           |   |      |   |           |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                           |  |              |           |   |      |   |           |  
|Current liabilities                                                                            |  |              |           |   |      |   |           |  
|Accounts payable                                                                               |  | $            | 41,773    |   |      | $ | 61,329    |  
|Accrued liabilities                                                                            |  |              | 14,298    |   |      |   | 18,866    |  
|Unrealized hedging losses                                                                      |  |              | 13,001    |   |      |   | 62,349    |  
|                                                                                               |  |              |           |   |      |   |           |  
|                                                                                               |  |              | 69,072    |   |      |   | 142,544   |  
|                                                                                               |  |              |           |   |      |   |           |  
|Bank debt                                                                                      |  |              | 200,000   |   |      |   | 416,000   |  
|Deferred income taxes                                                                          |  |              | 96,569    |   |      |   | 154,480   |  
|Other noncurrent liabilities                                                                   |  |              | 15,012    |   |      |   | 50,236    |  
|Unrealized hedging losses                                                                      |  |              | 1,787     |   |      |   | 27,631    |  
|Deferred compensation liability                                                                |  |              | 38,070    |   |      |   | 74,888    |  
|Commitments and contingencies                                                                  |  |              |           |   |      |   |           |  
|Stockholders equity                                                                           |  |              |           |   |      |   |           |  
|Preferred Stock, $.01 par, 5,000,000 shares authorized, none issued or outstanding             |  |              |          |   |      |   |          |  
|Common Stock, $.01 par, 100,000,000 shares authorized, 70,324,465 and 71,504,986 shares issued |  |              | 703       |   |      |   | 715       |  
|Less Common Stock Held in Treasury, at cost, 2,590,678 shares and 2,481,820 shares             |  |              | (6,817    | ) |      |   | (7,850    | )
|Capital in excess of par value                                                                 |  |              | 175,186   |   |      |   | 187,171   |  
|Deferred compensation                                                                          |  |              |          |   |      |   | (764      | )
|Retained earnings                                                                              |  |              | 123,707   |   |      |   | 205,786   |  
|Accumulated other comprehensive income (loss)                                                  |  |              | 5,801     |   |      |   | (54,546   | )
|                                                                                               |  |              |           |   |      |   |           |  
|                                                                                               |  |              | 298,580   |   |      |   | 330,512   |  
|                                                                                               |  |              |           |   |      |   |           |  
|                                                                                               |  | $            | 719,090   |   |      | $ | 1,196,291 |  
|                                                                                               |  |              |           |   |      |   |           |  



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, |        
|                                                                                |  | 2001                    |         | 2002 |   | 2003    | 
|Revenues                                                                        |  |                         |         |      |   |         |  |   |         |  
|Oil and gas sales                                                               |  | $                       | 211,271 |      | $ | 215,430 |  | $ | 398,724 |  
|Other                                                                           |  |                         | 2,902   |      |   | 6,977   |  |   | 7,993   |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|                                                                                |  |                         | 214,173 |      |   | 222,407 |  |   | 406,717 |  
|Expenses                                                                        |  |                         |         |      |   |         |  |   |         |  
|Lease operating                                                                 |  |                         | 25,356  |      |   | 27,986  |  |   | 54,082  |  
|Production taxes                                                                |  |                         | 13,462  |      |   | 11,751  |  |   | 28,726  |  
|Exploration                                                                     |  |                         | 513     |      |   | 2,171   |  |   | 6,207   |  
|General and administrative                                                      |  |                         | 10,994  |      |   | 12,714  |  |   | 19,034  |  
|Interest and other                                                              |  |                         | 7,034   |      |   | 2,762   |  |   | 9,395   |  
|Impairment of oil and gas hedges                                                |  |                         | 6,370   |      |   |        |  |   |        |  
|Loss on sale of oil and gas properties                                          |  |                         |        |      |   |        |  |   | 7,223   |  
|Deferred compensation adjustment                                                |  |                         | 3,236   |      |   | 9,983   |  |   | 33,110  |  
|Depletion, depreciation and amortization                                        |  |                         | 49,916  |      |   | 66,162  |  |   | 98,119  |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|                                                                                |  |                         | 116,881 |      |   | 133,529 |  |   | 255,896 |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Pretax income                                                                   |  |                         | 97,292  |      |   | 88,878  |  |   | 150,821 |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Provision for income taxes                                                      |  |                         |         |      |   |         |  |   |         |  
|Current                                                                         |  |                         | 11,466  |      |   | 8,799   |  |   | 21,492  |  
|Deferred                                                                        |  |                         | 23,559  |      |   | 22,372  |  |   | 35,820  |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|                                                                                |  |                         | 35,025  |      |   | 31,171  |  |   | 57,312  |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Net income before change in accounting principle                                |  | $                       | 62,267  |      | $ | 57,707  |  | $ | 93,509  |  
|Cumulative effect of change in accounting principle                             |  |                         |        |      |   |        |  |   | (2,613  | )
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Net income                                                                      |  | $                       | 62,267  |      | $ | 57,707  |  | $ | 90,896  |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Net income per share before cumulative effect of change in accounting principle |  |                         |         |      |   |         |  |   |         |  
|Basic                                                                           |  | $                       | 1.00    |      | $ | 0.88    |  | $ | 1.37    |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Diluted                                                                         |  | $                       | 0.93    |      | $ | 0.84    |  | $ | 1.32    |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Net loss per share from change in accounting principle                          |  |                         |         |      |   |         |  |   |         |  
|Basic                                                                           |  | $                       |        |      | $ |        |  | $ | (0.04   | )
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Diluted                                                                         |  | $                       |        |      | $ |        |  | $ | (0.04   | )
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Net income per share                                                            |  |                         |         |      |   |         |  |   |         |  
|Basic                                                                           |  | $                       | 1.00    |      | $ | 0.88    |  | $ | 1.33    |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Diluted                                                                         |  | $                       | 0.93    |      | $ | 0.84    |  | $ | 1.28    |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Weighted average shares outstanding                                             |  |                         |         |      |   |         |  |   |         |  
|Basic                                                                           |  |                         | 62,392  |      |   | 65,933  |  |   | 68,170  |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  
|Diluted                                                                         |  |                         | 67,290  |      |   | 68,970  |  |   | 71,062  |  
|                                                                                |  |                         |         |      |   |         |  |   |         |  



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, 2000                                               |  | $                    |  |              | 62,637 |   |               | $ | 626 |                              |  | $ | (4,503               | ) |  | $                | 151,214 |   |                                           | $ |     |       |  | $ | 12,814  |   |  | $ |        |   |  | $ | 160,151 |  
|Repurchase of common stock and warrants                                  |  |                      |  |              | (7,353 | ) |               |   | (73 | )                            |  |   |                     |   |  |                  | (51,401 | ) |                                           |   |     |       |  |   |        |   |  |   |        |   |  |   | (51,474 | )
|Issuance of common stock                                                 |  |                      |  |              | 2,103  |   |               |   | 20  |                              |  |   |                     |   |  |                  | 8,040   |   |                                           |   |     |       |  |   |        |   |  |   |        |   |  |   | 8,060   |  
|Deferred compensation stock issued, net                                  |  |                      |  |              |       |   |               |   |    |                              |  |   | (1,363               | ) |  |                  |        |   |                                           |   |     |       |  |   |        |   |  |   |        |   |  |   | (1,363  | )
|Conversion of warrants                                                   |  |                      |  |              | 8,994  |   |               |   | 90  |                              |  |   |                     |   |  |                  | 35,885  |   |                                           |   |     |       |  |   |        |   |  |   |        |   |  |   | 35,975  |  
|Tax benefit from stock options                                           |  |                      |  |              |       |   |               |   |    |                              |  |   |                     |   |  |                  | 2,165   |   |                                           |   |     |       |  |   |        |   |  |   |        |   |  |   | 2,165   |  
|Dividends                                                                |  |                      |  |              |       |   |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                           |   |     |       |  |   | (3,568  | ) |  |   |        |   |  |   | (3,568  | )
|Comprehensive income:                                                    |  |                      |   |              |        |   |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                           |   |      |       |  |   |         |   |  |   |         |   |  |   |         |  
|Net income                                                               |  |                      |  |              |       |   |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                           |   |     |       |  |   | 62,267  |   |  |   |        |   |  |   | 62,267  |  
|Cumulative effect of change in accounting principle, net of income taxes |  |                      |  |              |       |   |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                           |   |     |       |  |   |        |   |  |   | (25,077 | ) |  |   | (25,077 | )
|Contract settlements reclassed to income                                 |  |                      |  |              |       |   |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                           |   |     |       |  |   |        |   |  |   | 822     |   |  |   | 822     |  
|Change in unrealized hedging gains                                       |  |                      |  |              |       |   |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                           |   |     |       |  |   |        |   |  |   | 61,616  |   |  |   | 61,616  |  
|                                                                         |  |                      |   |              |        |   |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                           |   |      |       |  |   |         |   |  |   |         |   |  |   |         |  
|Total comprehensive income                                               |  |                      |  |              |       |   |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                           |   |     |       |  |   | 62,267  |   |  |   | 37,361  |   |  |   | 99,628  |  
|                                                                         |  |                      |   |              |        |   |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                           |   |      |       |  |   |         |   |  |   |         |   |  |   |         |  
|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 gains                                       |  |                      |  |              |       |   |               |   |    |                              |  |   |                     |   |  |                  |        |   |                                           |   |     |       |  |   |        |   |  |   | (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 |  
|                                                                         |  |                      |   |              |        |   |               |   |     |                              |  |   |                      |   |  |                  |         |   |                                           |   |      |       |  |   |         |   |  |   |         |   |  |   |         |  



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, |         
|                                                                                 |  | 2001                    |          |   | 2002 |   |          | 2003 | 
|Operating activities                                                             |  |                         |          |   |      |   |          |      |  |   |          |  
|Net income                                                                       |  | $                       | 62,267   |   |      | $ | 57,707   |      |  | $ | 90,896   |  
|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                                                              |  |                         | 513      |   |      |   | 2,171    |      |  |   | 6,207    |  
|Depletion, depreciation and amortization                                         |  |                         | 49,916   |   |      |   | 66,162   |      |  |   | 98,119   |  
|Deferred income taxes                                                            |  |                         | 23,559   |   |      |   | 22,372   |      |  |   | 32,104   |  
|Tax benefit from exercise of stock options                                       |  |                         | 2,165    |   |      |   | 3,496    |      |  |   | 10,576   |  
|Impairment of oil and gas hedges                                                 |  |                         | 4,077    |   |      |   | (4,077   | )    |  |   |         |  
|Deferred compensation adjustment                                                 |  |                         | 3,236    |   |      |   | 9,983    |      |  |   | 33,110   |  
|Loss (gain) on deferred compensation asset                                       |  |                         | (29      | ) |      |   | 995      |      |  |   | (1,751   | )
|Loss on sale of oil and gas properties                                           |  |                         |         |   |      |   |         |      |  |   | 7,223    |  
|Other                                                                            |  |                         | 113      |   |      |   | 70       |      |  |   | 734      |  
|Changes in current and other assets and liabilities                              |  |                         |          |   |      |   |          |      |  |   |          |  
|Decrease (increase) in                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|Accounts receivable                                                              |  |                         | 15,423   |   |      |   | (11,379  | )    |  |   | (21,126  | )
|Inventory and other                                                              |  |                         | 828      |   |      |   | (615     | )    |  |   | (10,421  | )
|Increase (decrease) in                                                           |  |                         |          |   |      |   |          |      |  |   |          |  
|Accounts payable                                                                 |  |                         | 4,313    |   |      |   | 8,656    |      |  |   | 14,298   |  
|Income taxes payable                                                             |  |                         | (330     | ) |      |   |         |      |  |   |         |  
|Accrued liabilities                                                              |  |                         | 3,123    |   |      |   | 360      |      |  |   | 1,674    |  
|Other assets and liabilities                                                     |  |                         | 3,603    |   |      |   | (3,744   | )    |  |   | 7,569    |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash provided by operating activities                                        |  |                         | 172,777  |   |      |   | 152,157  |      |  |   | 271,825  |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Investing activities                                                             |  |                         |          |   |      |   |          |      |  |   |          |  
|Development and exploration                                                      |  |                         | (77,856  | ) |      |   | (99,598  | )    |  |   | (176,136 | )
|Acquisitions, net of cash acquired                                               |  |                         | (10,230  | ) |      |   | (182,509 | )    |  |   | (307,326 | )
|Disposition of oil and gas properties                                            |  |                         | 16,468   |   |      |   | 2,303    |      |  |   | 16,943   |  
|Other                                                                            |  |                         | (10,739  | ) |      |   | (2,588   | )    |  |   | (4,362   | )
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash used in investing activities                                            |  |                         | (82,357  | ) |      |   | (282,392 | )    |  |   | (470,881 | )
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Financing activities                                                             |  |                         |          |   |      |   |          |      |  |   |          |  
|Increase (decrease) in indebtedness                                              |  |                         | (100,000 | ) |      |   | 123,000  |      |  |   | 216,000  |  
|Repayment from (loan to) affiliate                                               |  |                         | 24,500   |   |      |   |         |      |  |   |         |  
|Deferred credits                                                                 |  |                         | (4,577   | ) |      |   |         |      |  |   |         |  
|Loan origination fees                                                            |  |                         | (169     | ) |      |   |         |      |  |   | (1,574   | )
|Issuance of common stock                                                         |  |                         | 42,465   |   |      |   | 14,427   |      |  |   | 9,302    |  
|Repurchase of common stock and warrants                                          |  |                         | (51,474  | ) |      |   | (9       | )    |  |   | (17,230  | )
|Common stock dividends                                                           |  |                         | (3,568   | ) |      |   | (5,513   | )    |  |   | (8,817   | )
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash provided by (used in) financing activities                              |  |                         | (92,823  | ) |      |   | 131,905  |      |  |   | 197,681  |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Increase (decrease) in cash                                                      |  |                         | (2,403   | ) |      |   | 1,670    |      |  |   | (1,375   | )
|Cash and equivalents, beginning of period                                        |  |                         | 2,653    |   |      |   | 250      |      |  |   | 1,920    |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Cash and equivalents, end of period                                              |  | $                       | 250      |   |      | $ | 1,920    |      |  | $ | 545      |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  



The accompanying notes are an integral part of these financial statements



F-6



---

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, was formed in 1996 to hold the assets of Snyder
Oil Corporation (SOCO) in the Wattenberg Field and to facilitate the acquisition of Gerrity Oil & Gas Corporation (Gerrity). In conjunction with the Gerrity acquisition, SOCO received 43.8 million common shares of Patina.
In 1997, a series of transactions eliminated SOCOs ownership in the Company.



In November 2000, Patina acquired various property interests out of bankruptcy. The assets were acquired through Elysium Energy, L.L.C. (Elysium), a New York limited liability company, in which Patina held
a 50% interest. Patina invested $21.0 million. In January 2003, the Company purchased the remaining 50% interest in Elysium for $23.1 million, comprised of $16.0 million and the assumption of $7.1 million in debt and other liabilities. See Note
(10).



In November 2002, Patina acquired the stock of Le Norman
Energy Corporation (Le Norman) for $62.0 million and the issuance of 513,200 shares of the Companys common stock. Le Normans properties are located primarily in the Anadarko and Ardmore-Marietta Basins of Oklahoma and
primarily produce oil. The acquisition also included a 30% reversionary interest in Le Norman Partners (LNP). See Note (3).



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



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



In October 2003, the Company acquired the assets of Cordillera Energy Partners, LLC (Cordillera) for $243.0 million, comprised of $239.0
million of cash 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 primarily produce gas. See Note (3).



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



The Companys operations currently consist
of the acquisition, development, exploitation and production of oil and gas properties. Historically, Patinas properties were primarily located in the Wattenberg Field of Colorados D-J Basin. Over the past two years, the Company acquired
a leasehold position with production in West Texas in efforts to expand and diversify through grassroots projects (Grassroots Projects). Through Le Norman, LNP, Bravo, and certain Cordillera properties (collectively, Mid
Continent) and Elysium and the Grassroots Projects (collectively, Central and Other), the Company currently has oil and gas properties in central Kansas, the Illinois Basin, Texas, Oklahoma and New Mexico. Based on fourth quarter
2003 production, Wattenberg accounted for approximately 62%, Mid Continent for 25%, San Juan for 3% and Central and Other for 10% of daily oil and gas production on an equivalent basis.



F-7



---

|(2) | 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. Costs of productive wells, unsuccessful developmental wells and productive leases are capitalized and amortized on a unit-of-production basis over
the life of the associated oil and gas reserves. Oil is converted to natural gas equivalents (Mcfe) at the rate of one barrel to six Mcf. Amortization of capitalized costs has generally been provided on a field-by-field basis.



The Company follows the provisions of Statement of Financial Accounting
Standards No. 144 (SFAS 144), Accounting for the Impairment or Disposal of Long-Lived Assets, which requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a field-by-field
basis (see Recent Accounting Pronouncements). 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.



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 or 2001 assuming adoption on a pro forma basis. At December 31, 2003
an asset retirement obligation of $27.6 million is recorded in Other noncurrent liabilities. A reconciliation of the changes in the Companys liability from December 31, 2002 to December 31, 2003 is as follows (amounts in thousands):



|                                                    |  |   |        |  
|--------------------------------------------------- |  | - | ------ | -
|Asset retirement obligation as of December 31, 2002 |  | $ | 1,904  |  
|Liability from adoption of SFAS No. 143             |  |   | 21,405 |  
|Liabilities incurred                                |  |   | 3,761  |  
|Liabilities settled                                 |  |   | (757   | )
|Accretion expense                                   |  |   | 1,281  |  
|                                                    |  |   |        |  
|Asset retirement obligation as of December 31, 2003 |  |   | 27,594 |  
|                                                    |  |   |        |  



Field equipment and other



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



F-8



---

Other Assets



At December 31, 2002, the balance represented $5.3 million in assets held in a deferred compensation plan and $4.6 million representing the value assigned
for the 30% reversionary interest in Le Norman Partners which the Company acquired in conjunction with the Le Norman acquisition. This amount was recorded in oil and gas properties in conjunction with the acquisition of the remaining 70% interest in
LNP. At December 31, 2003, the balance primarily represented $14.1 million in assets held in a deferred compensation plan and $937,000 in unamortized loan origination costs. See Note (7).



Gas Imbalances



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



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 Company had no such changes prior to 2001. The
components of accumulated other comprehensive income (loss) and related tax effects for the twelve months ended December 31, 2002 were as follows (in thousands):



|                                                  |  |       |         |   |           |   |         |           |  |   |         |  
|------------------------------------------------- |  | ----- | ------- | - | --------- | - | ------- | --------- |  | - | ------- | -
|                                                  |  | Gross |         |   | TaxEffect |   |         | Net ofTax | 
|Accumulated other comprehensive income  12/31/01 |  | $     | 58,376  |   |           | $ | (21,015 | )         |  | $ | 37,361  |  
|Change in fair value of hedges                    |  |       | (24,265 | ) |           |   | 8,735   |           |  |   | (15,530 | )
|Impaired oil and gas hedging swaps                |  |       | (6,370  | ) |           |   | 2,293   |           |  |   | (4,077  | )
|Contract settlements during the year              |  |       | (18,677 | ) |           |   | 6,724   |           |  |   | (11,953 | )
|                                                  |  |       |         |   |           |   |         |           |  |   |         |  
|Accumulated other comprehensive loss  12/31/02   |  | $     | 9,064   |   |           | $ | (3,263  | )         |  | $ | 5,801   |  
|                                                  |  |       |         |   |           |   |         |           |  |   |         |  



The impairment relates
to a fourth quarter 2001 non-cash provision of $6.4 million ($4.1 million net of taxes) related to the write-off of all outstanding oil and gas hedges with Enron North America (Enron). The write-off reduced earnings per share in the
quarter and year by $0.06 (fully diluted). In accordance with generally accepted accounting principles, the Company recorded additional non-cash revenues of an identical amount in the course of 2002, as the impaired value of the hedges would have
otherwise expired.



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 |          |   | TaxEffect |   |         | 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 | )
|                                                  |  |       |          |   |           |   |         |           |  |   |         |  



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



Financial Instruments



The book value and
estimated fair value of cash and equivalents was $1.9 million and $545,000 at December 31, 2002 and 2003, respectively. The book value and estimated fair value of the bank debt was $200.0 million and $416.0 million at December 31, 2002 and 2003,
respectively. The book value of these assets and liabilities approximates fair value due to their short maturity or floating rate structure of these instruments.



F-9



---

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 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 one year and an additional $100.0 million for two years. At December 31, 2003,
the net unrealized pretax gains on these contracts totaled $421,000 ($261,000 gain net of $160,000 of deferred taxes) based on LIBOR futures prices at December 31, 2003.



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 and $25.1 million in 2002 and 2003, respectively, and a gain of $1.9 million in 2001, 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 loss of
$25.3 million in 2003, and gains of $2.1 million and $24.3 million in 2001 and 2002, respectively, related to these contracts.



At December 31, 2003, the Company was a party to swap contracts for oil based on NYMEX prices covering approximately 14,350 barrels of oil per day for
2004 at fixed prices ranging from $23.03 to $29.40 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $24.85 per barrel for 2004. The Company also entered into swap
contracts for oil for 2005 and 2006 as of December 31, 2003, which are summarized in the table below. The net unrealized losses on these contracts totaled $40.8 million based on NYMEX futures prices at December 31, 2003.



At December 31, 2003, the Company was a party to swap contracts for natural
gas based on CIG, EPSJ, ANR and Panhandle Eastern Pipeline (PEPL) index prices covering approximately 129,500 MMBtus per day for 2004 at fixed prices ranging from $2.83 to $5.64 per MMBtu. The overall weighted average hedged price
for the swap contracts is $4.04 per MMBtu for 2004. The Company also entered into natural gas swap contracts for 2005 as of December 31, 2003, which are summarized in the table below. The net unrealized losses on these contracts totaled $47.6
million based on futures prices at December 31, 2003.



At December 31, 2003,
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) |  
|01/01/04 - 03/31/04 |  | 13,450            |  | 25.44 |                               | $                                  | (7,991  | ) |                  | 95,000 |         | 4.23 |                                    | $ | (8,363  | )
|04/01/04 - 06/30/04 |  | 14,350            |  | 24.93 |                               |                                    | (7,277  | ) |                  | 90,000 |         | 3.58 |                                    |   | (6,078  | )
|07/01/04 - 09/30/04 |  | 14,750            |  | 24.69 |                               |                                    | (6,207  | ) |                  | 90,000 |         | 3.57 |                                    |   | (6,630  | )
|10/01/04 - 12/31/04 |  | 14,800            |  | 24.43 |                               |                                    | (5,555  | ) |                  | 77,000 |         | 3.93 |                                    |   | (4,995  | )
|                    |  |                   |  |       |                               |                                   
|2005                |  | 13,700            |  | 24.78 |                               |                                    | (12,833 | ) |                  | 55,000 |         | 3.65 |                                    |   | (10,553 | )
|2006                |  | 5,400             |  | 26.11 |                               |                                    | (971    | ) |                  |       |         |     |                                    |   |        |  



F-10



---

|                    |  |                                      |  |         |                                |                                    |        |   |                  |       |         |      |                                    |   |      |  
|------------------- |  | ------------------------------------ |  | ------- | ------------------------------ | ---------------------------------- | ------ | - | ---------------- | ----- | ------- | ---- | ---------------------------------- | - | ---- | -
|                    |  | Natural Gas Swaps (ANR/PEPL Indexes) |  |         | Natural Gas Swaps (EPSJ Index) |                                   
|Time Period         |  | DailyVolumeMMBtu                     |  | $/MMBtu |                                | UnrealizedGain (Loss)($/thousands) |        |   | DailyVolumeMMBtu |       | $/MMBtu |      | UnrealizedGain (Loss)($/thousands) |  
|01/01/04 - 03/31/04 |  | 31,800                               |  | 4.90    |                                | $                                  | (2,510 | ) |                  | 7,300 |         | 4.86 |                                    | $ | (262 | )
|04/01/04 - 06/30/04 |  | 33,500                               |  | 4.35    |                                |                                    | (1,700 | ) |                  | 8,300 |         | 4.16 |                                    |   | (255 | )
|07/01/04 - 09/30/04 |  | 34,700                               |  | 4.31    |                                |                                    | (1,842 | ) |                  | 9,000 |         | 4.15 |                                    |   | (303 | )
|10/01/04 - 12/31/04 |  | 32,700                               |  | 4.52    |                                |                                    | (1,659 | ) |                  | 8,600 |         | 4.36 |                                    |   | (277 | )
|                    |  |                                      |  |         |                                |                                   
|2005                |  | 25,000                               |  | 4.52    |                                |                                    | (1,688 | ) |                  | 6,000 |         | 4.11 |                                    |   | (448 | )



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, 2002 and 2003, the Company had zero and $9.9 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 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 2003, net hedging losses of $47.8 million ($29.6
million after tax) were reclassified from Accumulated other comprehensive income to earnings and the changes in the fair value of outstanding derivative net liabilities decreased by $144.8 million ($90.0 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 2003.



As of December 31, 2003, the Company had net unrealized
hedging losses of $88.0 million ($54.5 million after tax), comprised of $137,000 of current assets, $1.9 million of non-current assets, $62.3 million of current liabilities and $27.6 million of non-current liabilities. Based on estimated future
prices as of December 31, 2003, the Company expects to reclassify as a decrease to earnings during the next twelve months $62.2 million ($38.6 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 (7). The Company accounts for assets held in a deferred compensation plan in accordance with EITF 97-14. See Note (7).



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 which was paid on March 3, 2004 in which shareholders received
an additional share of the Companys 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-11



---

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



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,
|                                                          |  | 2001                    |     | 2002 |   | 2003 
|Stock Purchase Plan                                       |  | $                       | 653 |      | $ | 1,662 |  | $ |     
|Restricted Stock Grant                                    |  |                         |    |      |   |      |  |   | 861  
|401(k) profit sharing contribution in common stock        |  |                         | 647 |      |   | 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-12



---

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.



The FASB is currently evaluating the application of certain provisions of SFAS No. 141, Business Combinations,
and SFAS No. 142, Goodwill and Other Intangible Assets, to companies in the extractive industries, including oil and gas companies. The FASB is considering whether the provisions of SFAS No. 141 and SFAS No.142 require registrants to
classify costs associated with mineral rights, including both proved and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other oil and gas property costs, and provide specific footnote disclosures.



Historically, the Company has included oil and gas lease
acquisition costs as a component of oil and gas properties. In the event the FASB determines that costs associated with mineral rights are required to be classified as intangible assets, approximately $580.8 million of the Companys oil and gas
property acquisition costs may be required to be separately classified on its balance sheets as intangible assets. However, the Company currently believes that its results of operations and financial condition would not be affected since such
intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. The Company does not believe the classification of oil and gas lease acquisition
costs as intangible assets would have any impact on the Companys compliance with covenants under its debt agreements.



F-13



---

|(3) | ACQUISITIONS
|--- | ------------



In November 2002, through Patina Oklahoma Corporation, a wholly owned subsidiary, Patina acquired the stock of Le Norman Energy Corporation (Le
Norman or the Le Norman Acquisition) for $62.0 million in cash funded with borrowings under the Companys bank facility 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.



In December 2002, Patina acquired the stock of Bravo Natural Resources, Inc. (Bravo or the Bravo Acquisition), a Delaware
corporation, for $119.0 million in cash funded with borrowings under the Companys bank facility. 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.



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.



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



|                              |  |           |        |   |       |   |         |            |  |   |         |  
|----------------------------- |  | --------- | ------ | - | ----- | - | ------- | ---------- |  | - | ------- | -
|                              |  | Le Norman |        |   | Bravo |   |         | Cordillera | 
|Purchase Price:               |  |           |        |   |       |   |         |            |  |   |         |  
|Cash paid                     |  | $         | 62,023 |   |       | $ | 118,974 |            |  | $ | 238,969 |  
|Stock / Warrants issued       |  |           | 5,779  |   |       |   |        |            |  |   | 4,000   |  
|                              |  |           |        |   |       |   |         |            |  |   |         |  
|Total                         |  | $         | 67,802 |   |       | $ | 118,974 |            |  | $ | 242,969 |  
|                              |  |           |        |   |       |   |         |            |  |   |         |  
|Allocation of Purchase Price: |  |           |        |   |       |   |         |            |  |   |         |  
|Working capital               |  | $         | 215    |   |       | $ | (1,784  | )          |  | $ | (676    | )
|Oil and gas properties        |  |           | 66,805 |   |       |   | 159,913 |            |  |   | 285,183 |  
|Other non-current assets      |  |           | 5,271  |   |       |   | 2,622   |            |  |   | 410     |  
|Deferred income taxes         |  |           | (4,489 | ) |       |   | (40,653 | )          |  |   | (39,800 | )
|Other non-current liabilities |  |           |       |   |       |   | (1,124  | )          |  |   | (2,148  | )
|                              |  |           |        |   |       |   |         |            |  |   |         |  
|Total                         |  | $         | 67,802 |   |       | $ | 118,974 |            |  | $ | 242,969 |  
|                              |  |           |        |   |       |   |         |            |  |   |         |  



The following table
reflects the unaudited pro forma results of operations for the twelve months ended December 31, 2002 and 2003 as though the Le Norman, Bravo, and Cordillera acquisitions had occurred on January 1, 2002 (in thousands, except per share amounts):



|                                      |  |                  |           |           |       |        |                       |   |        |  |   |        |   |  |   |        
|------------------------------------- |  | ---------------- | --------- | --------- | ----- | ------ | --------------------- | - | ------ |  | - | ------ | - |  | - | -------
|                                      |  | HistoricalPatina |           | Pro Forma |       |        | Pro FormaConsolidated
|Year ended December 31, 2002          |  |                  | Le Norman |           | Bravo |        | Cordillera            |   |       
|Revenues                              |  | $                | 222,407   |           | $     | 16,097 |                       | $ | 16,721 |  | $ | 16,798 |   |  | $ | 272,023
|Net income                            |  |                  | 57,707    |           |       | 822    |                       |   | 1,548  |  |   | (5,176 | ) |  |   | 54,901 
|Net income per common share  basic   |  |                  | 0.88      |           |       |        |                       |   |        |  |   |        |   |  |   | 0.83   
|Net income per common share  diluted |  |                  | 0.84      |           |       |        |                       |   |        |  |   |        |   |  |   | 0.80   
|                                      |  |                  |           |           |      
|Year ended December 31, 2003          |  |                  |           |           |       |        |                       |   |        |  |  
|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   



F-14



---

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 Le Norman, Bravo, and Cordillera acquisitions been consummated on January 1, 2002, nor are the pro forma amounts necessarily indicative of the future results of operations of the Company.



|(4) | OIL AND GAS PROPERTIES
|--- | ----------------------



The cost of oil and gas properties at December 31, 2002 and 2003 included approximately $10.3 million and $2.5 million, respectively, in net unevaluated
leasehold and property costs to which proved reserves have not been assigned. These amounts have been excluded from amortization during the respective period. The following table sets forth costs incurred related to oil and gas properties:



|                          |  |                                         |         |   |      |   |         |      |  |   |         |  
|------------------------- |  | --------------------------------------- | ------- | - | ---- | - | ------- | ---- |  | - | ------- | -
|                          |  | 2001                                    |         |   | 2002 |   |         | 2003 | 
|                          |  | (In thousands, except per Mcfe amounts) |        
|Development               |  | $                                       | 77,343  |   |      | $ | 97,428  |      |  | $ | 169,929 |  
|Acquisition - evaluated   |  |                                         | 6,603   |   |      |   | 182,008 |      |  |   | 305,833 |  
|Acquisition - unevaluated |  |                                         | 3,627   |   |      |   | 500     |      |  |   | 1,493   |  
|Exploration and other     |  |                                         | 513     |   |      |   | 2,171   |      |  |   | 6,207   |  
|                          |  |                                         |         |   |      |   |         |      |  |   |         |  
|                          |  | $                                       | 88,086  |   |      | $ | 282,107 |      |  | $ | 483,462 |  
|                          |  |                                         |         |   |      |   |         |      |  |   |         |  
|Asset retirement costs    |  | $                                       |        |   |      | $ |        |      |  | $ | 3,761   |  
|                          |  |                                         |         |   |      |   |         |      |  |   |         |  
|Disposition of properties |  | $                                       | (16,468 | ) |      | $ | (2,303  | )    |  | $ | (16,943 | )
|                          |  |                                         |         |   |      |   |         |      |  |   |         |  
|Depletion rate (per Mcfe) |  | $                                       | 0.86    |   |      | $ | 0.93    |      |  | $ | 0.94    |  
|                          |  |                                         |         |   |      |   |         |      |  |   |         |  



The disposition of
properties in 2001 relates primarily to the sale of Elysium properties in the Lake Washington Field in Louisiana for $30.5 million in March 2001 ($15.25 million net to the Company) and additional property sales in Wattenberg. 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.



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



During 2003, 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, additions to oil and gas
properties of approximately $3.8 million were recorded for the estimated asset retirement costs related to new wells drilled or acquired.



F-15



---

|(5) | INDEBTEDNESS
|--- | ------------



The following indebtedness was outstanding on the respective dates:



|                             |  |                |         |      |   |        
|---------------------------- |  | -------------- | ------- | ---- | - | -------
|                             |  | December 31,  
|                             |  | 2002           |         | 2003
|                             |  | (In thousands)
|Bank facility - Patina       |  | $              | 193,000 |      | $ | 416,000
|Bank facility - Elysium, net |  |                | 7,000   |      |   |       
|Less current portion         |  |                |        |      |   |       
|                             |  |                |         |      |   |        
|Bank debt, net               |  | $              | 200,000 |      | $ | 416,000
|                             |  |                |         |      |   |        



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, 2003. Patina had $84.0 million available under the Credit Agreement at December 31, 2003.



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 2.7% during 2003 and 2.7% at December 31, 2003.



The Credit
Agreement contains financial covenants, including but not limited to a maximum total debt to EBITDA ratio, as defined, and a minimum current ratio. It also contains negative covenants, including but not limited to restrictions on indebtedness;
certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers; changes in fiscal year; transactions with
affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge causes; issuance of securities; and
non-speculative commodity hedging. At December 31, 2002 and 2003, the Company was in compliance with the covenants. Borrowings under the Credit Agreement mature in January 2007, but may be prepaid at anytime. The Company had a restricted payment
basket under the Credit Agreement of $66.9 million as of December 31, 2003, which may be used to repurchase equity securities, pay dividends or make other restricted payments.



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



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



Scheduled maturities of indebtedness for the next five years are zero in 2004, 2005, and 2006 and $416.0 million in 2007. Management intends to extend the
maturity of its credit facility on a regular basis; however, there can be no assurance it will be able to do so. Cash payments for interest totaled $7.2 million, $1.9 million and $6.6 million during 2001, 2002 and 2003, respectively.



F-16



---

|(6) | STOCKHOLDERS EQUITY
|--- | --------------------



A total of 100.0 million common shares, $0.01 par value, are authorized of which 71.5 million were issued at December 31, 2003. 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 the Companys 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 splits. 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, 2001:



|                                               |  |            |   |  |            |   |  |            |  
|---------------------------------------------- |  | ---------- | - |  | ---------- | - |  | ---------- | -
|                                               |  | 2001       |   |  | 2002       |   |  | 2003       |  
|Beginning shares                               |  | 62,637,100 |   |  | 66,381,100 |   |  | 70,324,400 |  
|Exercise of stock options                      |  | 1,363,400  |   |  | 2,524,900  |   |  | 2,214,600  |  
|Issued under Stock Purchase Plan               |  | 306,100    |   |  | 557,500    |   |  |           |  
|Issued in lieu of salaries and bonuses         |  | 212,100    |   |  | 246,100    |   |  | 142,200    |  
|Issued for directors fees                      |  | 4,800      |   |  | 5,800      |   |  | 5,400      |  
|Issued for Le Norman acquisition               |  |           |   |  | 513,200    |   |  |           |  
|Exercise of $4.00 warrants                     |  | 8,993,800  |   |  |           |   |  |           |  
|Issued to deferred compensation plan           |  | 37,000     |   |  | 36,000     |   |  |           |  
|Vesting of stock grant                         |  | 104,200    |   |  |           |   |  |           |  
|Contributed to 401(k) plan                     |  | 75,700     |   |  | 60,500     |   |  |           |  
|                                               |  |            |   |  |            |   |  |            |  
|Total shares issued                            |  | 11,097,100 |   |  | 3,944,000  |   |  | 2,362,200  |  
|Repurchases                                    |  | (7,353,100 | ) |  | (700       | ) |  | (1,181,600 | )
|                                               |  |            |   |  |            |   |  |            |  
|Ending shares                                  |  | 66,381,100 |   |  | 70,324,400 |   |  | 71,505,000 |  
|Treasury shares held in deferred comp (Note 7) |  | (2,691,800 | ) |  | (2,590,700 | ) |  | (2,481,800 | )
|                                               |  |            |   |  |            |   |  |            |  
|Adjusted shares outstanding                    |  | 63,689,300 |   |  | 67,733,700 |   |  | 69,023,200 |  
|                                               |  |            |   |  |            |   |  |            |  



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 |        | Total 
|     |  | First   |        | Second |   | Third  |  | Fourth |       
|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



During 2001, 2002 and
2003, the Company repurchased and retired shares of its common stock for $51.5 million, $9,000 and $17.2 million, respectively.



During 2001, 8,993,800 $4.00 warrants ($12.50 prior to the stock splits) were converted into common stock with the Company receiving cash proceeds of
$36.0 million. The remaining unexercised warrants expired on May 2, 2001.



During 2003, in conjunction with the Cordillera acquisition, 1,000,000 five year warrants to purchase the Companys common stock for $22.50 per share were issued. At December 31, 2003, all of the warrants were
outstanding. The warrants expire on October 1, 2008.



F-17



---

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



In September 2003,
the Compensation Committee of the Board of Directors awarded a restricted stock grant of 47,500 shares of common stock to the officers and directors of the Company in lieu of the suspended Stock Purchase Plan (see Note 7). The shares vest 30% in May
2004, 30% in May 2005, and 40% in May 2006. The non-vested shares have been recorded as Deferred compensation in the equity section of the accompanying consolidated balance sheets.



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



|                                                |  |                         |        |              |        |          |   |           |  |              |        |          |        |           |   |              |  |          |        |  |        |  |   |     
|----------------------------------------------- |  | ----------------------- | ------ | ------------ | ------ | -------- | - | --------- |  | ------------ | ------ | -------- | ------ | --------- | - | ------------ |  | -------- | ------ |  | ------ |  | - | ----
|                                                |  | Year Ended December 31,
|                                                |  | 2001                    |        | 2002         |        | 2003    
|                                                |  | NetIncome               |        | CommonShares |        | PerShare |   | NetIncome |  | CommonShares |        | PerShare |        | NetIncome |   | CommonShares |  | PerShare
|Net income                                      |  | $                       | 62,267 |              | 62,392 |          |   |           |  | $            | 57,707 |          | 65,933 |           |   |              |  | $        | 90,896 |  | 68,170 |  |   |     
|Basic net income attributable to common stock   |  |                         | 62,267 |              | 62,392 |          | $ | 1.00      |  |              | 57,707 |          | 65,933 |           | $ | 0.88         |  |          | 90,896 |  | 68,170 |  | $ | 1.33
|                                                |  |                         |        |              |        |          |   |           |  |              |        |          |        |           |   |              |  |          |        |  |        |  |   |     
|Effect of dilutive securities:                  |  |                         |        |              |        |          |   |           |  |              |        |          |        |           |   |              |  |          |        |  |        |  |   |     
|Stock options                                   |  |                         |       |              | 3,376  |          |   |           |  |              |       |          | 3,037  |           |   |              |  |          |       |  | 2,892  |  |   |     
|Unvested stock grant                            |  |                         |       |              | 22     |          |   |           |  |              |       |          |       |           |   |              |  |          |       |  |       |  |   |     
|$4.00 common stock warrants                     |  |                         |       |              | 1,500  |          |   |           |  |              |       |          |       |           |   |              |  |          |       |  |       |  |   |     
|                                                |  |                         |        |              |        |          |   |           |  |              |        |          |        |           |   |              |  |          |        |  |        |  |   |     
|Diluted net income attributable to common stock |  | $                       | 62,267 |              | 67,290 |          | $ | 0.93      |  | $            | 57,707 |          | 68,970 |           | $ | 0.84         |  | $        | 90,896 |  | 71,062 |  | $ | 1.28
|                                                |  |                         |        |              |        |          |   |           |  |              |        |          |        |           |   |              |  |          |        |  |        |  |   |     



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 Patina common stock at $22.50 per share were excluded from the computation of
diluted earnings per share because they were anti-dilutive.



|(7) | EMPLOYEE BENEFIT PLANS
|--- | ----------------------



401(k) Savings



The Company maintains a 401(k) profit sharing and savings plan (the 401(k) Plan). Eligible employees may make voluntary contributions to the
401(k) Plan. The Company may, at its discretion, make additional matching or profit sharing contributions to the 401(k) Plan. The Company made profit sharing contributions of $647,000, $801,000 and $1.4 million for 2001, 2002 and 2003, respectively.
The contributions in 2001 and 2002 were made in common stock while the 2003 contribution was made in cash. A total of 75,700 and 60,500 common shares were contributed in 2001 and 2002, respectively.



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



F-18



---

possible purchase under the Stock Purchase Plan. Plan years run from the date of the Annual Meeting through the next Annual Meeting. In 2001, the Board of
Directors approved 379,000 common shares (exclusive of shares available for purchase with participants salaries and bonuses) for possible purchase by participants during the plan year. As of December 31, 2001, participants had purchased
306,100 shares of common stock at an average price of $8.53 per share ($6.40 net price per share), resulting in cash proceeds to the Company of $2.0 million. 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 $653,000 and $1.7 million associated with these purchases for 2001 and 2002,
respectively. 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 Company stock). The Company can make discretionary matching contributions of the participants salary deferral and those assets are invested in instruments as directed by the participant. The Deferred
Compensation Plan does not have dollar limits on tax-deferred contributions. The assets of the Deferred Compensation Plan are held in a rabbi trust (Trust) and, therefore, may be available to satisfy the claims of the Companys
creditors in the event of bankruptcy or insolvency of the Company. Participants have the ability to direct the Plan Administrator to invest their salary and bonus deferrals into pre-approved mutual funds held by the Trust. In addition, participants
have the right to request that the Plan Administrator re-allocate the portfolio of investments (i.e., cash, mutual funds, Company stock) in the participants individual account within the Trust, however, the Plan Administrator is not required
to honor any such request. Company matching contributions are in the form of either cash or Company stock and vest ratably over a three-year period. Participants may elect to receive their payments in either cash or the Companys common stock.
At December 31, 2003, the balance of the assets in the Trust totaled $74.9 million, including 2,481,820 shares of common stock of the Company valued at $60.8 million. The Company accounts for the Deferred Compensation Plan in accordance with
Emerging Issues Task Force (EITF) Abstract 97-14, Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held in a Rabbi Trust and Invested.



Assets of the Trust, other than common stock of the Company, are invested in 11 mutual funds that cover the investment
spectrum from equities to money market instruments. These mutual funds are publicly quoted and reported at market value. The Company accounts for these investments in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and
Equity Securities. The Trust also holds common shares of the Company. The Companys common stock that is held by the Trust has been classified as treasury stock in the stockholders equity section of the accompanying balance sheets.
The market value of the assets held by the Trust, exclusive of the market value of the shares of the Companys common stock that are reflected as treasury stock, at December 31, 2002 and 2003, was $5.3 million and $14.1 million, respectively,
and is classified as Other Assets in the accompanying balance sheets. The amounts payable to the plan participants at December 31, 2002 and 2003, including the market value of the shares of the Companys common stock that are reflected as
treasury stock, was $38.1 million and $74.9 million, respectively, and is classified as Deferred Compensation Liability in the accompanying balance sheets. Approximately 2,279,400 shares or 92% of the Company common stock held in the Plan are
attributable to the Chief Executive Officer at December 31, 2003.



In accordance with EITF 97-14, all market fluctuations in value of the Trust assets have been reflected in the respective income statements. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of
the Company, have been included as Other income in the respective income statements. Increases or decreases in the market value of the deferred compensation liability, including the shares of common stock of the Company held by the Trust, while
recorded as treasury stock, are included as Deferred compensation adjustments in the respective income statement. In response to the changes in total market value of the Trust, the Company recorded deferred compensation adjustments of $3.2 million,
$10.0 million, and $33.1 million in 2001, 2002 and 2003, respectively.



F-19



---

Stock Option 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 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 |  | Range of ExercisePrices |  | WeightedAverageExercisePrice
|2001 |  | 1,980,000      |  | $7.24  $10.57          |  | $                            | 7.33 
|2002 |  | 2,305,000      |  | $8.25  $12.66          |  | $                            | 8.41 
|2003 |  | 2,122,000      |  | $13.59  $17.13         |  | $                            | 13.62



The Company also
maintains a shareholder approved stock grant and option plan for non-employee Directors (the Directors Plan). The Directors Plan provides for each non-employee Director to receive common shares having a market value equal to
$2,500 quarterly in payment of a portion of their retainer. A total of 4,800 shares were issued in 2001, 5,800 in 2002, and 5,400 in 2003. It also provides for 15,625 options to be granted to each non-employee Director upon appointment and upon
annual re-election, thereafter. The options vest over a three-year period (30%, 60%, 100%) and expire five years from the date of grant. The following is a summary of stock options granted under the Directors Plan:



|     |  |                |  |                         |  |                              |      
|---- |  | -------------- |  | ----------------------- |  | ---------------------------- | -----
|Year |  | OptionsGranted |  | Range of ExercisePrices |  | WeightedAverageExercisePrice
|2001 |  | 78,100         |  | $7.87  $10.51          |  | $                            | 9.98 
|2002 |  | 78,100         |  | $11.30  $12.80         |  | $                            | 11.60
|2003 |  | 78,100         |  | $15.39                  |  | $                            | 15.39



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, 2001, 2002, and 2003, respectively:



|                                    |  |             |  |      |        |      |   |        |  |   |       
|----------------------------------- |  | ----------- |  | ---- | ------ | ---- | - | ------ |  | - | ------
|                                    |  |             |  | 2001 |        | 2002 |   | 2003  
|Net income                          |  | As Reported |  | $    | 62,267 |      | $ | 57,707 |  | $ | 90,896
|                                    |  | Pro forma   |  |      | 60,698 |      |   | 54,742 |  |   | 86,726
|Basic net income per common share   |  | As Reported |  | $    | 1.00   |      | $ | 0.88   |  | $ | 1.33  
|                                    |  | Pro forma   |  |      | 0.97   |      |   | 0.83   |  |   | 1.27  
|Diluted net income per common share |  | As Reported |  | $    | 0.93   |      | $ | 0.84   |  | $ | 1.28  
|                                    |  | Pro forma   |  |      | 0.90   |      |   | 0.79   |  |   | 1.22  



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 2001, 2002 and 2003: dividend yield of 1%, 1% and 1%; expected volatility of 48%, 46% and
45%; risk-free interest rate of 4.7%, 4.2% and 2.7%; and expected life of 3.6 years, 3.8 years and 3.7 years, respectively.



F-20



---

A summary of the status of the Companys stock option plans as of December 31, 2001, 2002 and 2003
and changes during the years are presented below:



|                                                               |  |            |   |      |                              |      |        |            |   |                              |   |        |  |            |                              |  |   |      
|-------------------------------------------------------------- |  | ---------- | - | ---- | ---------------------------- | ---- | ------ | ---------- | - | ---------------------------- | - | ------ |  | ---------- | ---------------------------- |  | - | -----
|                                                               |  | 2001       |   | 2002 |                              | 2003
|                                                               |  | Shares     |   |      | WeightedAverageExercisePrice |      | Shares |            |   | WeightedAverageExercisePrice |   | Shares |  |            | WeightedAverageExercisePrice
|Outstanding at beginning of year                               |  | 6,284,000  |   |      | $                            | 2.33 |        | 6,879,000  |   |                              | $ | 3.83   |  | 6,565,000  |                              |  | $ | 5.72 
|Granted                                                        |  | 2,058,000  |   |      |                              | 7.43 |        | 2,383,000  |   |                              |   | 8.51   |  | 2,200,000  |                              |  |   | 13.68
|Exercised                                                      |  | (1,363,000 | ) |      |                              | 2.37 |        | (2,525,000 | ) |                              |   | 3.06   |  | (2,214,000 | )                            |  |   | 3.32 
|Forfeited                                                      |  | (100,000   | ) |      |                              | 3.78 |        | (172,000   | ) |                              |   | 7.72   |  | (93,000    | )                            |  |   | 10.18
|                                                               |  |            |   |      |                              |      |        |            |   |                              |   |        |  |            |                              |  |   |      
|Outstanding at end of year                                     |  | 6,879,000  |   |      | $                            | 3.83 |        | 6,565,000  |   |                              | $ | 5.72   |  | 6,458,000  |                              |  | $ | 9.19 
|                                                               |  |            |   |      |                              |      |        |            |   |                              |   |        |  |            |                              |  |   |      
|Options exercisable at year-end                                |  | 3,014,000  |   |      |                              |      |        | 2,421,000  |   |                              |   |        |  | 2,031,000  |                              |  |   |      
|                                                               |  |            |   |      |                              |      |        |            |   |                              |   |        |  |            |                              |  |   |      
|Weighted-average fair value of options granted during the year |  |            |   |      | $                            | 2.87 |        |            |   |                              | $ | 3.18   |  |            |                              |  | $ | 4.83 



The following table summarizes
information about stock options outstanding at December 31, 2003:



|                  |  |                                      |  |                                       |  |                                |       |                                      |           |                               |   |      
|----------------- |  | ------------------------------------ |  | ------------------------------------- |  | ------------------------------ | ----- | ------------------------------------ | --------- | ----------------------------- | - | -----
|                  |  | Options Outstanding                  |  | Options Exercisable                  
|Exercise Price    |  | NumberOutstanding atDecember 31,2003 |  | Weighted-Avg.RemainingContractualLife |  | Weighted-AverageExercise Price |       | NumberExercisable atDecember 31,2003 |           | Weighted-AverageExercisePrice
|$  0.94 to   2.94 |  | 849,000                              |  | 0.9 years                             |  | $                              | 2.41  |                                      | 849,000   |                               | $ | 2.41 
|4.52 to   7.96    |  | 1,319,000                            |  | 2.1 years                             |  |                                | 7.18  |                                      | 667,000   |                               |   | 7.12 
|8.05 to 12.67     |  | 2,112,000                            |  | 3.1 years                             |  |                                | 8.56  |                                      | 511,000   |                               |   | 8.61 
|12.80 to 17.13    |  | 2,178,000                            |  | 4.2 years                             |  |                                | 13.67 |                                      | 4,000     |                               |   | 12.80
|                  |  |                                      |  |                                       |  |                                |       |                                      |           |                               |   |      
|$  0.94 to 17.13  |  | 6,458,000                            |  | 3.0 years                             |  | $                              | 9.19  |                                      | 2,031,000 |                               |   | 5.54 
|                  |  |                                      |  |                                       |  |                                |       |                                      |           |                               |   |      



F-21



---

|(8) | 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,
2001, 2002 and 2003 follows:



|                                              |  |      |    |  |      |    |  |      |  
|--------------------------------------------- |  | ---- | -- |  | ---- | -- |  | ---- | -
|                                              |  | 2001 |    |  | 2002 |    |  | 2003 |  
|Federal statutory rate                        |  | 35   | %  |  | 35   | %  |  | 35   | %
|State income tax rate, net of federal benefit |  | 3    | %  |  | 3    | %  |  | 3    | %
|Section 29 tax credits and other              |  | (2   | %) |  | (3   | %) |  |     |  
|                                              |  |      |    |  |      |    |  |      |  
|Effective income tax rate                     |  | 36   | %  |  | 35   | %  |  | 38   | %
|                                              |  |      |    |  |      |    |  |      |  



Current income tax
expense in 2003 totaled $19.8 million for federal purposes and $1.7 million for state purposes. The Company expects to utilize approximately $17.0 million of net operating loss carryforwards in 2003 to reduce current taxes.



For book purposes the components of the net deferred tax asset and liability
at December 31, 2002 and 2003 were:



|                                             |  |                |          |   |      |   |          |  
|-------------------------------------------- |  | -------------- | -------- | - | ---- | - | -------- | -
|                                             |  | 2002           |          |   | 2003 |  
|                                             |  | (In thousands) |         
|Deferred tax assets                          |  |                |          |   |      |   |          |  
|NOL and depletion carryforwards              |  | $              | 29,749   |   |      | $ | 18,524   |  
|Deferred compensation deductions             |  |                | 13,517   |   |      |   | 26,923   |  
|Alternative minimum tax credit carryforwards |  |                | 14,200   |   |      |   | 9,147    |  
|Deferred deductions and other                |  |                | 950      |   |      |   | 2,934    |  
|Taxes relating to unrealized hedging losses  |  |                |         |   |      |   | 33,431   |  
|Valuation allowance                          |  |                | (3,601   | ) |      |   | (3,225   | )
|                                             |  |                |          |   |      |   |          |  
|                                             |  |                | 54,815   |   |      |   | 87,734   |  
|                                             |  |                |          |   |      |   |          |  
|Deferred tax liabilities                     |  |                |          |   |      |   |          |  
|Taxes relating to unrealized hedging gains   |  |                | (3,444   | ) |      |   |         |  
|Depreciable and depletable property          |  |                | (147,940 | ) |      |   | (218,573 | )
|                                             |  |                |          |   |      |   |          |  
|                                             |  |                | (151,384 | ) |      |   | (218,573 | )
|                                             |  |                |          |   |      |   |          |  
|Net deferred tax liability                   |  | $              | (96,569  | ) |      | $ | (130,839 | )
|                                             |  |                |          |   |      |   |          |  



For tax purposes, the
Company had net operating loss carryforwards of approximately $41.3 million at December 31, 2003. Utilization of these losses will be limited each year as a result of various acquisitions. These carryforwards expire from 2005 through 2023. The
Company has provided a $3.2 million valuation allowance against the loss carryforwards that could expire unutilized. At December 31, 2003, the Company had AMT credit carryforwards of approximately $9.1 million that are available indefinitely. In
addition, at December 31, 2003, the Company had depletion deduction carryforwards of approximately $12.0 million that are available indefinitely. The Company paid $4.8 million and $14.0 million in federal and state taxes during 2002 and 2003,
respectively.



|(9) | MAJOR CUSTOMERS
|--- | ---------------



During 2001, 2002 and 2003, Duke Energy Field Services, Inc. accounted for 29%, 37% and 23%, BP Amoco Production Company accounted for 13%, 9% and 15%,
and E-Prime accounted for 10%, 7%, and 1%, of revenues, respectively. Accounts receivable amounts from these customers at December 31, 2002 and 2003 totaled $15.2 million and $25.4 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.



F-22



---

|(10) | RELATED PARTY TRANSACTIONS
|---- | --------------------------



In March 2001, the Company loaned an officer $50,000, represented by a 7.00% recourse promissory note. The loan was repaid in September 2002. In May 2001,
the Company loaned a director $136,000 to finance the purchase of 31,250 common shares from the Company under the Stock Purchase Plan. The loan was represented by a 7.50% recourse promissory note and was repaid in September 2002.



Patina provided certain administrative services to Elysium under an operating
agreement. The Company was paid $850,000 and $2.9 million for these services in 2001 and 2002, respectively. As the Company purchased the remaining 50% interest in Elysium in January 2003, there were no indirect monthly reimbursements in 2003.



|(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. Future minimum lease payments under such leases and
agreements approximate $1.8 million in 2004, $2.1 million per year from 2005 through 2007, $1.6 million in 2008 and approximately $600,000 per year from 2009 to 2023.



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



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



|(12) | SUBSEQUENT EVENTS
|---- | -----------------



In February 2004, the Company sold its interests in the Adams Baggett field in Texas and certain minor interests in Oklahoma for $15.5 million. The
Company expects to recognize a pretax gain in the first quarter of 2004 of approximately $7.5 million on the transaction. In addition, in January 2004, the Company sold certain properties acquired in the Cordillera acquisition in the Breedlove Field
in Martin County, Texas. The properties were sold for $6.0 million and no gain or loss will be recognized on the transaction.



On February 10, 2004, the Company declared a 2-for-1 stock split. The stock split was paid on March 3, 2004 to stockholders of record at the close of
business on February 23, 2004. Stockholders received an additional share of common stock for every share held on that date. After the split, the Company had approximately 71.1 million (74.9 million fully diluted) shares outstanding, including 2.5
million shares held in the deferred compensation plan. All share and per share amounts for all periods presented herein have been restated to reflect the 2-for-1 stock split.



F-23



---

|(13) | UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
|---- | ------------------------------------------------------



Netherland, Sewell & Associates, Inc., independent petroleum consultants, audited the Companys total proved reserves at December 31, 2001, 2002
and 2003. 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, 2000            |  | 42,713 |   |  | 521,550     |  
|Revisions                             |  | (9,852 | ) |  | (40,737     | )
|Extensions, discoveries and additions |  | 4,675  |   |  | 52,713      |  
|Production                            |  | (2,661 | ) |  | (41,002     | )
|Purchases                             |  | 61     |   |  | 34,921      |  
|Sales                                 |  | (2,832 | ) |  | (905        | )
|                                      |  |        |   |  |             |  
|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   |  
|                                      |  |        |   |  |             |  



F-24



---

Proved Developed Reserves



|                  |  |        |  |            
|----------------- |  | ------ |  | -----------
|                  |  | Oil    |  | Natural Gas
|                  |  | (MBbl) |  | (MMcf)     
|December 31, 2000 |  | 35,146 |  | 409,103    
|                  |  |        |  |            
|December 31, 2001 |  | 28,220 |  | 430,487    
|                  |  |        |  |            
|December 31, 2002 |  | 41,833 |  | 522,227    
|                  |  |        |  |            
|December 31, 2003 |  | 58,128 |  | 696,249    
|                  |  |        |  |            



Standardized Measure



|                                         |  |                |           |   |      |   |            |      |  |   |            |  
|---------------------------------------- |  | -------------- | --------- | - | ---- | - | ---------- | ---- |  | - | ---------- | -
|                                         |  | December 31,   |          
|                                         |  | 2001           |           |   | 2002 |   |            | 2003 | 
|                                         |  | (In thousands) |          
|Future cash inflows                      |  | $              | 1,868,209 |   |      | $ | 4,525,670  |      |  | $ | 8,227,574  |  
|Future costs                             |  |                |           |   |      |   |            |      |  |   |            |  
|Production                               |  |                | (486,526  | ) |      |   | (1,083,832 | )    |  |   | (2,107,655 | )
|Development(a)                           |  |                | (379,474  | ) |      |   | (622,752   | )    |  |   | (864,347   | )
|                                         |  |                |           |   |      |   |            |      |  |   |            |  
|Future net cash flows                    |  |                | 1,002,209 |   |      |   | 2,819,086  |      |  |   | 5,255,572  |  
|Undiscounted income taxes                |  |                | (279,461  | ) |      |   | (929,183   | )    |  |   | (1,790,715 | )
|                                         |  |                |           |   |      |   |            |      |  |   |            |  
|After tax net cash flows                 |  |                | 722,748   |   |      |   | 1,889,903  |      |  |   | 3,464,857  |  
|10% discount factor                      |  |                | (331,809  | ) |      |   | (879,553   | )    |  |   | (1,683,838 | )
|                                         |  |                |           |   |      |   |            |      |  |   |            |  
|Standardized measure                     |  | $              | 390,939   |   |      | $ | 1,010,350  |      |  | $ | 1,781,019  |  
|                                         |  |                |           |   |      |   |            |      |  |   |            |  
|Pretax Standardized measure (SEC PV10) |  | $              | 527,184   |   |      | $ | 1,484,936  |      |  | $ | 2,704,461  |  
|                                         |  |                |           |   |      |   |            |      |  |   |            |  



|(a) | Future development costs of $864.3 million at December 31, 2003 include an estimate of $523.9 million for development of properties classified as proved undeveloped
reserves including $119.4 million in 2004, $119.4 million in 2005, and $100.1 million in 2006. Actual results may differ from these estimates. Capital expenditures incurred to develop proved undeveloped reserves were approximately $21.8 million,
$19.1 million, and $50.4 million in 2001, 2002, and 2003, respectively.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Changes in Standardized Measure



|                                        |  |                |            |   |      |   |           |      |  |   |           |  
|--------------------------------------- |  | -------------- | ---------- | - | ---- | - | --------- | ---- |  | - | --------- | -
|                                        |  | December 31,   |           
|                                        |  | 2001           |            |   | 2002 |   |           | 2003 | 
|                                        |  | (In thousands) |           
|Standardized measure, beginning of year |  | $              | 1,438,945  |   |      | $ | 390,939   |      |  | $ | 1,010,350 |  
|Revisions:                              |  |                |            |   |      |   |           |      |  |   |           |  
|Prices and costs                        |  |                | (1,820,512 | ) |      |   | 543,034   |      |  |   | 589,847   |  
|Quantities                              |  |                | 9,303      |   |      |   | 50,681    |      |  |   | 15,324    |  
|Development costs                       |  |                | (31,998    | ) |      |   | 73        |      |  |   | (24,300   | )
|Accretion of discount                   |  |                | 221,782    |   |      |   | 52,718    |      |  |   | 148,494   |  
|Income taxes                            |  |                | 642,635    |   |      |   | (338,342  | )    |  |   | (429,330  | )
|Production rates and other              |  |                | 23,470     |   |      |   | (6,603    | )    |  |   | (17,429   | )
|                                        |  |                |            |   |      |   |           |      |  |   |           |  
|Net revisions                           |  |                | (955,320   | ) |      |   | 301,561   |      |  |   | 282,606   |  
|Extensions, discoveries and additions   |  |                | 25,259     |   |      |   | 26,102    |      |  |   | 193,641   |  
|Production                              |  |                | (172,454   | ) |      |   | (175,693  | )    |  |   | (315,916  | )
|Future development costs incurred       |  |                | 77,343     |   |      |   | 97,428    |      |  |   | 96,602    |  
|Purchases(a)                            |  |                | 9,241      |   |      |   | 370,448   |      |  |   | 545,765   |  
|Sales(b)                                |  |                | (32,075    | ) |      |   | (435      | )    |  |   | (32,029   | )
|                                        |  |                |            |   |      |   |           |      |  |   |           |  
|Standardized measure, end of year       |  | $              | 390,939    |   |      | $ | 1,010,350 |      |  | $ | 1,781,019 |  
|                                        |  |                |            |   |      |   |           |      |  |   |           |  



|(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-25



---

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 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)                                                                                                                                                                                                                                                 
|       | 
|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    |  | Bylaws (Incorporated herein by reference to Exhibit 3.3 to the Companys Registration Statement on Form S-4 (Registration No. 333-572))                                                                                                                                                                                                                                                                                                                                         
|       | 
|3.3    |  | Amended and Restated Bylaws of Patina Oil & Gas Corporation. (Incorporated herein by reference to Exhibit 3.2 of the Companys Form 8-K filed on May 25, 2001)                                                                                                                                                                                                                                                                                                                  
|       | 
|3.4    |  | 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. (Incorporated herein by reference to Exhibit 3.2 of the Companys Form 8-K filed on May 25, 2001)                                                                                                                                                                                                                                                                                                                                                             
|       | 
|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 January 28, 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)                                                                                                                                                                               



F-26



---

|       |  |                                                                                                                                                                                                                                                                                                                               
|------ |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|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)
|       | 
|10.5.1 |  | 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)                                                                                                                                                   
|       | 
|10.5.2 |  | 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)                                                                                                                               
|       | 
|10.5.3 |  | Patina Oil & Gas Corporation 1996 Employee Stock Option Plan (Incorporated by reference to Exhibit 10.20 of the Companys Registration Statement on Form S-4 (Registration No.
33300-572))                                                                                                                                    
|       | 
|10.5.4 |  | 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   |  | 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)                                                                            
|       | 
|10.6.1 |  | Amendment of Lease Agreement dated December 21, 2000 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)                                                                                   
|       | 
|10.6.2 |  | Second Amendment of Lease Agreement dated December 21, 2000 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)                                                                            
|       | 
|10.6.3 |  | Third Amendment of Lease Agreement dated December 21, 2000 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant *                                                                                                                                                                                  
|       | 
|10.7   |  | 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)                                                                                                             
|       | 
|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.*                                                                                                                                                                                                                          



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|     |  |                                                                                                                                                                              
|---- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|32.1 |  | Certification of the Chief Executive Officer, dated March 9, 2004, 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 March 9, 2004, 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-28