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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, 2002

OR

o            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)

_____________________

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  o 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  o No

The aggregate market value of the 18,457,700 shares of voting stock held by non-affiliates of the registrant, based upon the closing sale price of the common stock on June 30, 2002 of $27.43 per share as reported on the New York Stock Exchange, was $506,294,711. Shares of common stock held by each officer and director and by each person who owns 5% or more of the outstanding common stock have been excluded in that such persons may be deemed affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of February 28, 2003, the registrant had 27,215,820 shares of common stock outstanding (excludes 1,093,113 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, 2003.

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PATINA OIL & GAS CORPORATION
Annual Report on Form 10-K
December 31, 2002

PART I

ITEM 1.         BUSINESS

General

Patina Oil & Gas Corporation (“Patina” or the “Company”) is a rapidly growing mid-size 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”) and the Mid Continent region of southern Oklahoma and the Texas Panhandle. The Company’s common shares are traded on the New York Stock Exchange under the symbol POG.

At December 31, 2002, the Company had 1.1 trillion cubic feet equivalent (“Tcfe”) of proved reserves having a pretax present value (PV10%) of $1.5 billion based on unescalated prices and costs. The SEC valuation reflected average wellhead prices of $3.67 per Mcf and $30.51 per barrel at year-end. During 2002, proved reserves increased 53%. The growth was largely the result of acquisitions and higher prices, which increased reserves by 237.1 Bcfe and 142.2 Bcfe, respectively. Reserve additions from ongoing development, discoveries and performance revisions added 72.4 Bcfe, offset by 69.4 Bcfe of production. Exclusive of the impact of higher prices, the Company replaced 446% of production in 2002. At year-end, approximately 69% of Company reserves by volume were natural gas and over 80% by pretax present value was developed. For information with respect to our proved reserves, see ITEM 2. Properties of this Form 10-K.

The Company operates over 90% of the 5,600 producing wells in which it holds a working interest. The high proportion of operated properties allows the Company to exercise more control over expenses, capital allocation and the timing of development and exploitation activities in its fields. At December 31, 2002, the Company had over 4,000 proven development projects in inventory, including 1,100 drilling or deepening locations, 700 recompletions, 1,500 restimulation (“refrac”) projects and over 700 production enhancement projects.

The Company’s properties have relatively long reserve lives and highly predictable production profiles. In general, these properties have extensive production histories and production enhancement opportunities. During 2002, the Company’s average daily production totaled 190.2 MMcfe, comprised of 8,965 barrels of oil and 136.4 MMcf of gas. Approximately 90% was attributed to Wattenberg. Based on year-end reserves and fourth quarter production, the Company had a reserve life index of 14.0 years.

Revenues and net income for 2002 totaled $222.4 million and $57.7 million, respectively. Cash provided from operations in 2002 totaled $152.2 million. This cash flow, augmented with $123.0 million of bank borrowings and $14.4 million realized from stock purchase plan purchases and stock option exercises, funded $282.1 million of capital expenditures in 2002. These expenditures were largely comprised of $182.5 million spent on acquisitions and $97.4 million on further development of properties. Development expenditures included $82.2 million expended in Wattenberg, $4.9 million on grassroots exploration and development, $4.6 million in the Mid Continent and $5.7 million on the Elysium properties. The benefits of these projects, continued success in production enhancement and acquisitions fueled a 22% production increase during the year. The Company has set a $150.0 million capital budget excluding acquisitions for 2003. The impact of that development and the benefit of completed and pending acquisitions should increase production by more than 30% in 2003.

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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 the Field. SOCO retained 17.5 million shares of the Company’s common stock and the acquired company’s shareholders received 7.5 million shares of common stock, $40.0 million of 7.125% convertible preferred stock and 3.8 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 sizeable acreage positions in central Wyoming and northwest Colorado, acquired a 50% interest in an early stage coal bed 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. Since year-end, the remainder of Elysium has been acquired and an agreement to acquire additional Oklahoma properties has been announced.

Elysium’s properties are located primarily 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 assets.

During 2001, the Company accumulated sizable acreage positions in three Rocky Mountain basins and acquired a leasehold position with existing production in West Texas. The intent was to aggregate prospects with significant reserve potential and long-term development prospects. The Company attempted to target areas where it could apply the expertise in tight sand fracture technology it developed in Wattenberg. To date, the grassroots projects have contributed minimal production growth and cash flow.

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 205,301 shares of the 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. 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 combination, the Le Norman and Bravo acquisitions established a strong presence in the Mid Continent region for the Company. Subsequent to year-end, a third acquisition of approximately $40.0 million in the Mid Continent region was announced. It is expected to close in March 2003.

Over the last five years, the Company has realized consistent growth in nearly every aspect of its business. Revenues increased from $100.1 million in 1997 to $222.4 million in 2002. Net income rose from a loss of $16.9 million to net income of $57.7 million during the same period. The growth was primarily the result of increasing oil and gas production, which grew from 104.6 MMcfe per day in 1997 to 190.2 MMcfe per day in 2002. Proven reserves jumped from 357.5 Bcfe at year-end 1997 to 1,101.5 Bcfe at December 31, 2002. The reserve growth was largely generated through further development and exploitation in the Wattenberg Field along with recent additions from the Le Norman and Bravo acquisitions. Growth has been achieved through the development and execution of high return capital projects and the maintenance of low production costs and an efficient operating structure.

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Business Strategy

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

Development, Acquisition and Exploration

During 2002, the Company spent $97.4 million on the further development of properties and $182.5 million on acquisitions. The development expenditures included $82.2 million in Wattenberg for the drilling or deepening of 58 J-Sand wells, 447 Codell refracs, 11 recompletions and the drilling of eight Codell wells, $4.9 million on grassroots exploration and development, $4.6 million in the Mid Continent, and $5.7 million on the Elysium properties. The benefits of these projects, the acquisitions, and the continued success in production enhancement contributed to a production increase of 22% over the prior year. The Company anticipates incurring approximately $150.0 million on the further development of its properties during 2003.

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, and Bravo in December 2002.

______________

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

   (b)   Sales of natural gas liquids are included in gas revenues.

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Gathering, Processing and Marketing

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

Natural Gas. The natural gas produced in Wattenberg is high in heating content (BTU’s) and must be processed to extract natural gas liquids (“NGL”). Residue gas is sold to utilities, independent marketers and end users through intrastate and interstate pipelines. The Company utilizes two separate arrangements to gather, process and market its gas production. Approximately 35% of production is sold to Duke Energy Field Services (“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 properties is gathered and transported to an interstate pipeline, where it is sold to end users and marketers. Pricing is generally based on the ANR Pipeline Oklahoma index plus a premium.

Oil. Oil production is principally sold to refiners, marketers and other purchasers that truck it to local refineries or pipelines. The price is based on a calendar month NYMEX price with adjustments for quality.

Hedging Activities

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 twelve to twenty-four month basis. At December 31, 2002, hedges were in place covering 64.3 Bcf at prices averaging $3.57 per MMBtu and 4.4 million barrels of oil averaging $24.11 per barrel. The estimated fair value of the Company’s hedge contracts that would be realized on termination, approximated a net unrealized pre-tax gain of $9.1 million ($5.8 million gain net of $3.3 million of deferred taxes) at December 31, 2002, which is presented on the balance sheet as a current asset of $8.3 million, a non-current asset of $15.6 million, a current liability of $13.0 million, and a non-current liability of $1.8 million based on contract expiration. The gas contracts expire monthly through December 2005 while the oil contracts expire monthly through December 2004. 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 or ANR Pipeline Oklahoma (“ANR”) index for natural gas. Transaction gains and losses are determined monthly and are included as increases or decreases in oil and gas revenues in the period the hedged production is sold. Any ineffective portion of such hedges is recognized in earnings as it occurs. Net pretax losses relating to these derivatives in 2000 were $23.9 million, with pretax gains of $4.1 million and $20.4 million in 2001 and 2002, respectively. Over the last three years, the Company has recorded cumulative net pretax hedging gains of $580,000 in income. Effective January 1, 2001, the unrealized gains (losses) on these 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 or CIG, on the Company’s balance sheet in Accumulated other comprehensive income (loss), a component of Stockholders’ Equity.

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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, to 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 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, 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.

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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 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 cleanup 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 2002, nor does it anticipate that such expenditures will be material in 2003.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), known as the “Superfund” law, and analagous 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 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 zero discharges 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

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exploration and production facilities are required to obtain permits for their storm water discharges. Costs may be incurred in connection with treatment of wastewater or developing storm water 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 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 analagous 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 significant adverse impact on operating costs and the oil and gas industry in general.

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 or refracing 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 acquisition, 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.

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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.

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 customers demand for oil and natural gas;

•          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

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.

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 availability of certain resources, including drilling rigs, water, chemicals, 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.

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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.

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.

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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.

Chief Executive Officer’s Interest In Another Oil And Gas Company

Our Chief Executive Officer also serves as the Chairman of Range Resources Corporation (“Range”), a publicly traded oil and gas company in which he is a significant investor. He is also an officer, director and/or significant investor in several other public and private companies engaged in various aspects of the energy industry. We currently have no business relationships with any of these companies, none of them owns our securities nor do we hold any of theirs. Historically, no material conflict has arisen with regard to these companies. However, conflicts of interests may arise particularly as the Company has recently become active in some of the same geographic areas as Range. Board policies are in place that require Mr. Edelman, along with all other officers and directors, to give us notification of any potential conflicts that arise. However, we cannot assure you that we will not compete with one or more of these companies, particularly for acquisitions, or encounter other conflicts of interest in the future.

Key Members Of Our 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 43,000 square feet and expires in March 2007. The monthly rent is approximately $92,000. The Company owns a 6,000 square foot production facility in Platteville, Colorado used to support its Wattenberg Field operations. Elysium maintains six field offices in the areas of its operations. The Company also owns an 11,000 square foot field office in Velma, Oklahoma used to support its Mid Continent operations.

Employees

On December 31, 2002, the Company had 232 employees, including 138 that work in its field offices. An additional 102 employees work for Elysium. None of these employees are represented by a labor union. The Company believes its relationships with its employees are satisfactory.

ITEM 2.         PROPERTIES

General

During 2002, the Company’s production averaged 190.2 MMcfe per day, of which 170.6 MMcfe per day or 90% was attributed to the Wattenberg Field of Colorado’s D-J Basin. Accordingly, the Company’s proved reserves at December 31, 2002 were concentrated primarily in Wattenberg. The Company also has proven reserves associated with its Elysium acquisition made in late 2000, the grassroots projects initiated in 2001, and the Le Norman and Bravo acquisitions made in late 2002 which comprise the Company’s Mid Continent assets. The following table sets forth summary information with respect to estimated proved reserves at December 31, 2002.

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The following table sets forth summary information with respect to oil and natural gas production for the year ended December 31, 2002.

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 in Colorado. One of the most attractive features of Wattenberg is the presence of several 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.

Drilling in Wattenberg is considered low risk from the perspective of finding oil and gas reserves, with better than 95% of the wells drilled being completed as 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 “drilling windows” on a 320 acre parcel.

In 2002, development expenditures in Wattenberg totaled $82.2 million. The Company’s current Wattenberg activities are primarily focused on the development of J-Sand reserves through drilling new wells or deepening within existing wellbores and refracing 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 2002 in what is considered a mature field.

During 2002, the Company drilled or deepened 58 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 $200,000. 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. Finding and development costs for the J-Sand drilling and deepening projects for 2002 averaged $1.04 per Mcfe with projected rates of return in excess of 30% based on actual prices received through year-end and futures prices thereafter. At December 31, 2002, the Company had 273 proven J-Sand drilling locations or deepening projects in inventory. The Company plans to drill or deepen approximately 80 wells in the J-Sand in 2003.

The Company performed 447 refracs in Wattenberg during 2002. The refrac program continues to be focused primarily on the Codell formation. A typical refrac costs approximately $135,000. The finding and development costs associated with the 2002 refrac program averaged $1.01 per Mcfe with projected rates of return in excess of 125% based on actual prices received through year-end and futures prices thereafter. At December 31, 2002, the Company had over 1,500 proven refrac projects. Given the exceptional results of the refrac program, the budgeted activity has been increased to over 450 refrac projects in 2003.

The Company also performed 11 recompletions and drilled eight Codell wells in the D-J Basin in 2002. The finding and development costs associated with these projects averaged $1.20 per Mcfe with projected rates of return of approximately 50% based on actual prices received through year-end and futures prices thereafter. The Company had an additional 650 Codell / J-Sand / Sussex proven recompletion opportunities and 450 Codell new drill opportunities at December 31, 2002. During 2002, tubing was installed in three wellbores and numerous well

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workovers, reactivations, and commingling of zones were performed. These projects, combined with the new drills, deepenings and refracs, were an integral part of the 2002 capital development program and helped fuel the 22% increase in the Company’s production over the prior year. The Company estimates it had over 500 of these minor projects in inventory at year-end 2002.

At December 31, 2002, the Company had working interests in approximately 3,200 gross (3,050 net) producing oil and gas wells in the D-J Basin with estimated proved reserves of 783.5 Bcfe, including 34.6 million barrels of oil and 576.2 Bcf of gas. Based upon a capital development budget of $150.0 million, the Company anticipates spending $90.9 million in Wattenberg in 2003.

Mid Continent

In November 2002, Patina acquired the stock of Le Norman Energy Corporation for $62.0 million in cash funded with borrowings under the Company’s bank facility and the issuance of 205,301 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., 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. Together the Le Norman and Bravo properties comprise the Company’s Mid Continent assets.

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 have been 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. A typical infill well will encounter in excess of 100 feet of net productive pay. The Company acquired interests in the Field as part of the Le Norman acquisition. A continuous infill-drilling program is under way with plans to drill approximately 80 wells in 2003. Simultaneously, an expansion of the secondary recovery operations will be pursued.

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 plans to continue to evaluate additional exploitation opportunities there. Current plans include the drilling of approximately 40 wells in 2003, primarily to shallow horizons. The Company will continue to optimize and implement secondary recovery operations in the Field.

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 entirely of a series of stratigraphically trapped sands with an average gross interval of 700 feet. An average well will contain 100 feet to 250 feet of net pay. The Field is currently being developed on 80 acre spacing. However, the Company believes the Field could be down spaced to 40-acre locations. The Company has identified potential improvements in stimulation methods to be applied on new completions as well as the restimulation of certain previously treated intervals. The Company plans to drill approximately 30 wells in the Buffalo Wallow Field during 2003.

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The Eakley-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 13,000 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. The Company plans to drill approximately six wells in the area during 2003 while continuing its evaluation of the acreage position. Various wells in the Field exhibit productive behind pipe intervals that will eventually be exploited.

During 2002, development expenditures for the Mid Continent region totaled $4.6 million for the drilling of 33 wells primarily in the Loco and Santa Fe Fields in Oklahoma. Estimated proved reserves attributed to the Mid Continent region totaled 231.9 Bcfe, including 14.8 million barrels of oil and 142.9 Bcf of gas. Based upon a capital development budget of $150.0 million, the Company anticipates spending $42.6 million in the Mid Continent region in 2003. This estimate includes $4.7 million of capital for the development of properties to be acquired in the Le Norman Partners (“LNP”) transaction which is expected to close in March 2003. However, there can be no assurance that the LNP acquisition will be completed.

Elysium

In November 2000, Patina acquired various property interests out of bankruptcy through Elysium Energy, L.L.C., a New York limited liability company, in which Patina holds a 50% interest. The Company proportionately consolidates its 50% interest in Elysium’s assets, liabilities, revenues and expenses. Elysium’s oil and gas properties are located in central Kansas, the Illinois Basin and the San Joaquin Field in California. The Elysium properties primarily produce oil. During 2002, development expenditures for Elysium totaled $11.5 million ($5.7 million net to Patina), for the drilling or deepening of 38 wells and performing 52 recompletions, primarily in the Illinois Basin, Kansas and California. 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). Daily production from these properties (net to Patina) averaged 13,978 Mcfe, comprised of 2,195 barrels and 806 Mcf per day in 2002. Patina’s 50% share of Elysium’s estimated proved reserves totaled 51.8 Bcfe, including 7.9 million barrels of oil and 4.1 Bcf of gas. 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 assets. Based upon a capital development budget of $150.0 million, the Company anticipates spending $8.7 million on the Elysium properties in 2003.

Grassroots Projects

In 2001, the Company earned a 50% non-operated working interest in a coal bed methane project (“Castlegate”) near Price, Utah. This interest included nine existing producing coal bed methane wells and 49,100 gross acres (21,500 net acres). The Company’s interest was earned through a capital expenditure commitment of $7.5 million, which was fulfilled during 2001 by drilling nine additional wells and installing various gas processing and water disposal facilities. During 2002, capital expenditures totaled $555,000 for completing the final stages of the water disposal facility. The project currently has 18 producing wells. At December 31, 2002, the Company had spent $8.9 million on this project, including the capital commitment and additional acquisition costs. Proved reserves at year-end totaled 26.4 Bcfe, all of which were natural gas.

In early 2001, the Company acquired 68,200 gross acres (68,200 net acres) in central Wyoming (“Antelope Arch”) for $3.6 million and formed a Federal unit over a portion of the acreage. There are up to eight potentially productive formations at various depths targeted on the prospect. The Company drilled its first well in December 2001 and completed it in the Frontier, the deepest target formation. The well was productive and is producing 200 Mcf per day. During 2002, capital expenditures totaled $1.6 million related to a horizontal sidetrack in the original Frontier well. As of December 31, 2002, the Company had expended $5.9 million on this project. No proved reserves associated with the project were booked as of year-end.

The Company also accumulated 23,200 gross acres (18,800 net acres) in the Piceance Basin of northwest Colorado (“Sugarloaf”) in 2001. The primary objective of the prospect is the shallow coal bed methane, with additional objectives in the tight-sand Mesa Verde and a deeper fractured shale interval. During 2002, capital expenditures were $2.7 million for the drilling of five wells as part of a coal bed methane pilot program. As of December 31, 2002, roughly $4.4 million had been expended on the project. As these wells are in the early de-watering stages, no proved reserves were recorded as of year-end.

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In July 2001, the Company acquired 19,600 gross acres (19,400 net acres) with 95 producing gas wells in West Texas (“Adams Baggett”). During 2002, capital expenditures totaled $1.4 million for the drilling of four wells. Proved reserves at year-end totaled 7.9 Bcfe, all of which was natural gas. As of December 31, 2002, the Company has expended $5.4 million on this project. The Company anticipates spending $2.1 million for the drilling of approximately eight wells on the project in 2003.

Proved Reserves

The following table sets forth estimated net proved reserves for the three years ended December 31, 2002.

The following table sets forth the estimated pretax future net revenues as of year-end 2002 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 $132.0 million of future development costs in 2003 (in thousands):

______________

   (a)   The after tax present value discounted at 10% of the proved reserves totaled $1.0 billion at year-end 2002.

The Wattenberg Field represents 69% of the pretax PV10% value and 783.5 Bcfe or 71% of Patina’s proved reserves.

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The quantities and values in the preceding tables are based on constant prices in effect at December 31, 2002, which averaged $30.51 per barrel of oil and $3.67 per Mcf of gas. These wellhead average prices were based on year-end NYMEX prices of $31.20 per barrel and $4.74 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 or natural gas could have a material adverse effect on the Company’s financial condition and results of operations.

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

Future prices received from production and future production costs 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. 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, 2002. 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, expenses exclude Patina’s share of overhead charges. In addition, the calculation of estimated future net revenues does not take into account the effect of various cash outlays, including, among other things general and administrative 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, 2002 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, 2002. Wells are classified as oil or natural gas wells according to their predominant production stream.

The Company had 231 wells (223 net) in Wattenberg, 1,438 wells (671 net) in Elysium, and 574 well (546 net) in the Mid Continent region that were shut-in at December 31, 2002. The Company’s average working interest in the Wattenberg wells was approximately 95% and the average working interest in the Elysium wells was approximately 94% (47% net to Patina), while the average working interest in the Mid Continent wells was 72%.

Drilling Results

The following table sets forth the number of wells drilled or deepened by the Company during the past three years. All wells in 2000 were development wells and drilled in Wattenberg. During 2001, the Company drilled or deepened 68 development wells (64 net) in Wattenberg, drilled 16 development wells (eight net) in the Illinois Basin (through Elysium) and drilled nine development coal bed methane wells (five net) in Utah. The Company drilled one exploratory well in Wyoming at the end of 2001. 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 (through Elysium), 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 coal bed methane wells (five net) in the northwest Colorado. 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.

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At December 31, 2002, the Company had ten wells (ten net) in Wattenberg, 22 wells (20 net) in the Mid Continent region, and one well (one net) in Elysium waiting on completion. The Company drilled five (five net) exploratory coal bed methane wells in northwest Colorado. These wells are in the early de-watering stages pending further evaluation.

Acreage

The following table sets forth the leasehold acreage held by the Company at December 31, 2002. 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.

      *   - Patina’s 50% interests in the Elysium acreage.

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, 2002.

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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. All share and per share amounts for all periods have been restated to reflect the 5-for-4 stock split. Prior to their expiration in May 2001, the Company had $10.00 Warrants ($12.50 prior to the stock dividend adjustment) listed on the NYSE under the symbol “POGWT”. The following table sets forth the range of high and low closing prices of the Common Stock and Warrants as reported on the NYSE Composite Tape.

On February 28, 2003, the closing price of the Common Stock was $33.28.

Holders of Record

As of February 28, 2003, there were 112 holders of record of the common stock and 27.2 million shares outstanding, exclusive of the 1.1 million common shares held in treasury stock.

Dividends

Adjusted for the stock dividend, a quarterly cash dividend of $0.008 per common share was initiated in December 1997 and continued through the third quarter of 1999. The dividend was increased to $0.016 per share in the fourth quarter of 1999, to $0.032 per share in the fourth quarter of 2000, to $0.04 per share in the fourth quarter of 2001, to $0.05 per share in the second quarter of 2002, and to $0.06 per share in the fourth quarter of 2002. The Company expects to continue to pay dividends on its common stock. However, continuation of 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 $82.3 million available for dividends and or other restricted payments as of December 31, 2002. In conjunction with entering into the new $500.0 million credit facility in January 2003, the amount available for dividends and other restricted payments was re-set at $25.0 million and 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, 2002 (a):

(a) Although the Company does not maintain a formal plan, common stock is issued to officers and key employees in lieu of cash for bonuses and company matches under the Company's deferred compensation arrangements. All such issuances are approved by the Compensation Committee, which is composed of four 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 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. 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 205,301 shares of common stock to the sellers.

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ITEM 6.         SELECTED FINANCIAL DATA

The following table presents selected historical financial data of the Company for the five-year period ended December 31, 2002. All share and per share amounts for all periods presented have been restated to reflect the 5-for-4 stock split which was effected in the form of a stock dividend to common stockholders of record in June 2002. 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, and the acquisitions of Le Norman and Bravo in November 2002 and December 2002, respectively.