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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

For the fiscal year ended December 31, 2003

OR

For the transaction period from                      to                     

Commission file number 1-14344

PATINA OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

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.

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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,

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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

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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.

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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:

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:

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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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.

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

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.

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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.

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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.

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Proved Reserves

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

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):

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.

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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.

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Producing Wells

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

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.

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Drilling Results

The following table sets forth the number of wells drilled or deepened by the Company during the past three years. During 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.

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.

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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.

There were no matters submitted to a vote of security holders during the fourth quarter of the year ended December 31, 2003.

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PART II

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.

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:

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.

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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):

(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:

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.

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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.

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