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UNITED STATESSECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM
10-K

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(Mark one)

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

For the fiscal year ended December 31, 2002

OR

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

For the transaction period from ________________ to
________________

Commission file number 1-14344

_____________________

PATINA OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

_____________________



| | Delaware(State or other jurisdiction ofincorporation or organization) |  | 75-2629477(IRS EmployerIdentification No.) | 
| | --------------------------------------------------------------------- |  | ------------------------------------------ | 

| | 1625 BroadwayDenver, Colorado(Address of principal executive offices) |  | 80202(Zip Code) | 
| | --------------------------------------------------------------------- |  | --------------- | 

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

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



| | Title of each classCommon Stock, $.01 par value |  | Name of each exchange on which registeredNew York Stock Exchange | 
| | ----------------------------------------------- |  | ---------------------------------------------------------------- | 

Securities registered pursuant to Section 12(g) of the Act:None(Title of Class)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.x Yes  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 CORPORATIONAnnual Report on Form 10-KDecember 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 iswww.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.



|                                  |  | Year Ended December 31,                                        |       
|--------------------------------- |  | -------------------------------------------------------------- | ------
|                                  |  |                                                                |       
|                                  |  | 1998                                                           |       
|                                  |  |                                                                |       
|                                  |  | (Dollars in thousands, except prices and per Mcfe information) |       
|Production                        |  |                                                                |       
|Oil (MBbl)                        |  |                                                                | 1,699 
|Gas (MMcf)                        |  | 26,522                                                         |       
|MMcfe (a)                         |  | 35,715                                                         |       
|                                  |  |                                                                |       
|Revenues                          |  |                                                                |       
|Oil                               |  | $                                                              | 22,583
|Gas (b)                           |  | 49,594                                                         |       
|                                  |  |                                                                |       
|Subtotal                          |  | 72,177                                                         |       
|Other                             |  | 2,603                                                          |       
|                                  |  |                                                                |       
|Total                             |  | 74,780                                                         |       
|                                  |  |                                                                |       
|                                  |  |                                                                |       
|Direct operating expenses         |  |                                                                |       
|Lease operating expenses          |  |                                                                | 12,399
|Production taxes                  |  | 4,941                                                          |       
|                                  |  |                                                                |       
|Total                             |  | 17,340                                                         |       
|                                  |  |                                                                |       
|                                  |  |                                                                |       
|Direct operating margin           |  | $                                                              | 57,440
|                                  |  |                                                                |       
|                                  |  |                                                                |       
|Average sales price               |  |                                                                |       
|Oil (Bbl)                         |  | $                                                              | 13.29 
|Gas (Mcf) (b)                     |  | 1.94                                                           |       
|Mcfe (a)                          |  | 2.02                                                           |       
|                                  |  |                                                                |       
|Lease operating expense per Mcfe  |  | $                                                              | 0.35  
|Production tax expense per Mcfe   |  | 0.14                                                           |       
|                                  |  |                                                                |       
|Direct operating expense per Mcfe |  | 0.49                                                           |       
|                                  |  |                                                                |       
|Production margin per Mcfe        |  | $                                                              | 1.54  

______________

(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.



|                    |  | Pre-tax Present Value 10% |           |    |  |            |   |                   |       
|------------------- |  | ------------------------- | --------- | -- |  | ---------- | - | ----------------- | ------
|                    |  |                           |           |    |  |            |   |                   |       
|                    |  | Amount(In thousands)      |           | %  |  | Oil(MBbls) |   | Natural Gas(MMcf) |       
|                    |  |                           |           |    |  |            |   |                   |       
|Wattenberg          |  | $                         | 1,017,309 |    |  | 69         |   |                   | 34,551
|Mid Continent       |  | 365,206                   |           | 25 |  | 14,829     |   | 142,921           |       
|Elysium             |  | 80,152                    |           | 5  |  | 7,948      |   | 4,141             |       
|Grassroots projects |  | 22,269                    |           | 1  |  |           |   | 34,299            |       
|                    |  |                           |           |    |  |            |   |                   |       
|Total               |  | $                         | 1,484,936 |    |  | 100        | % |                   | 57,328
|                    |  |                           |           |    |  |            |   |                   |       

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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.



|                    |  | Oil(MBbls) |       | Natural Gas(MMcf) |  | Total(MMcfe) | 
|------------------- |  | ---------- | ----- | ----------------- |  | ------------ | 
|                    |  |            |       |                   |  |              | 
|Wattenberg          |  |            | 2,338 |                   |  | 48,244       | 
|Mid Continent       |  | 133        |       | 673               |  | 1,471        | 
|Elysium             |  | 801        |       | 294               |  | 5,102        | 
|Grassroots projects |  |           |       | 566               |  | 568          | 
|                    |  |            |       |                   |  |              | 
|Total               |  |            | 3,272 |                   |  | 49,777       | 
|                    |  |            |       |                   |  |              | 

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.



|                   |  | December 31, |          
|------------------ |  | ------------ | ---------
|                   |  |              |          
|                   |  | 2000         |          
|                   |  |              |          
|Oil (MBbl)         |  |              |          
|Developed          |  |              |          
|Producing          |  |              | 18,496   
|Non-producing      |  | 16,650       |          
|                   |  |              |          
|Total Developed    |  | 35,146       |          
|Undeveloped        |  | 7,568        |          
|                   |  |              |          
|Total              |  | 42,714       |          
|                   |  |              |          
|                   |  |              |          
|Natural gas (MMcf) |  |              |          
|Developed          |  |              |          
|Producing          |  | 247,934      |          
|Non-producing      |  | 161,169      |          
|                   |  |              |          
|Total Developed    |  | 409,103      |          
|Undeveloped        |  | 112,447      |          
|                   |  |              |          
|Total              |  | 521,550      |          
|                   |  |              |          
|                   |  |              |          
|Total MMcfe        |  | 777,831      |          
|                   |  |              |          
|                   |  |              |          
|Pretax PV10% Value |  | $            | 2,217,825
|                   |  |              |          
|                   |  |              |          
|Oil price (Bbl)    |  | $            | 26.07    
|Gas price (Mcf)    |  | $            | 8.27     

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):



|                       |  | December 31, 2002 |          
|---------------------- |  | ----------------- | ---------
|                       |  |                   |          
|Future Net Revenues    |  |                   | Developed
|                       |  |                   |          
|2003                   |  | $                 | 215,429  
|2004                   |  | 201,345           |          
|2005                   |  | 182,722           |          
|Remainder              |  | 1,448,459         |          
|                       |  |                   |          
|Total                  |  | $                 | 2,047,955
|                       |  |                   |          
|                       |  |                   |          
|Pretax PV10% Value (a) |  | $                 | 1,189,669
|                       |  |                   |          

______________

(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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##### Table of Contents

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.



|PrincipalProduction
Stream     |  |       | GrossWells |       | NetWells | 
|------------------------------ |  | ----- | ---------- | ----- | -------- | 
|                               |  |       |            |       |          | 
|Wattenberg                     |  |       |            |       |         
|Oil                            |  | 2,838 |            | 2,708 |         
|Natural gas                    |  | 375   |            | 344   |         
|                               |  |       |            |       |         
|Total                          |  | 3,213 |            | 3,052 |         
|                               |  |       |            |       |         
|                               |  |       |            |       |         
|Mid Continent                  |  |       |            |       |         
|Oil                            |  | 852   |            | 683   |         
|Natural gas                    |  | 280   |            | 131   |         
|                               |  |       |            |       |         
|Total                          |  | 1,132 |            | 814   |         
|                               |  |       |            |       |         
|                               |  |       |            |       |         
|Elysium                        |  |       |            |       |         
|Oil                            |  | 1,133 |            | 540   |         
|Natural gas                    |  | 13    |            | 4     |         
|                               |  |       |            |       |         
|Total                          |  | 1,146 |            | 544   |         
|                               |  |       |            |       |         
|                               |  |       |            |       |         
|Texas, Utah, Wyoming and other |  |       |            |       |         
|Oil                            |  |      |            |      |         
|Natural gas                    |  | 123   |            | 113   |         
|                               |  |       |            |       |         
|Total                          |  | 123   |            | 113   |         
|                               |  |       |            |       |         
|                               |  |       |            |       |         
|Total                          |  |       |            |       |         
|Oil                            |  | 4,823 |            | 3,931 |         
|Natural gas                    |  | 791   |            | 592   |         
|                               |  |       |            |       |         
|Total                          |  | 5,614 |            | 4,523 |         
|                               |  |       |            |       |         

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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##### Table of Contents

|           |  | 2000 |  | 2001 |  | 2002  | 
|---------- |  | ---- |  | ---- |  | ----- | 
|           |  |      |  |      |  |       | 
|Productive |  |      |  |      |  |       | 
|Gross      |  | 60.0 |  | 93.0 |  | 140.0 | 
|Net        |  | 59.0 |  | 77.0 |  | 114.0 | 
|           |  |      |  |      |  |       | 
|Dry        |  |      |  |      |  |       | 
|Gross      |  | 0.0  |  | 0.0  |  | 4.0   | 
|Net        |  | 0.0  |  | 0.0  |  | 2.0   | 

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.

|                   |  | Developed |  | Undeveloped | 
|------------------ |  | --------- |  | ----------- | 
|                   |  |           |  |             | 
|                   |  | Gross     |  | Net         | 
|                   |  |           |  |             | 
|Patina             |  |           |  |             | 
|Colorado           |  | 201,000   |  | 179,000     | 
|Oklahoma           |  | 210,000   |  | 64,000      | 
|Texas              |  | 47,000    |  | 29,000      | 
|Wyoming            |  | 10,000    |  | 1,000       | 
|Utah               |  | 2,000     |  | 1,000       | 
|Michigan           |  |          |  |            | 
|Other              |  | 17,000    |  | 10,000      | 
|                   |  |           |  |             | 
|Subtotal           |  | 487,000   |  | 284,000     | 
|                   |  |           |  |             | 
|Elysium *          |  |           |  |             | 
|California         |  | 14,000    |  | 7,000       | 
|Illinois / Indiana |  | 46,000    |  | 19,000      | 
|Kansas             |  | 5,000     |  | 2,000       | 
|Louisiana / Texas  |  | 27,000    |  | 7,000       | 
|                   |  |           |  |             | 
|Subtotal           |  | 92,000    |  | 35,000      | 
|                   |  |           |  |             | 
|Total              |  | 579,000   |  | 319,000     | 
|                   |  |           |  |             | 

*- 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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##### Table of Contents

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.

|               |  | Common Stock |       | Warrants |  
|-------------- |  | ------------ | ----- | -------- | -
|               |  |              |       |          |  
|               |  | High         |       | Low      |  
|               |  |              |       |          |  
|2001           |  |              |       |          |  
|First Quarter  |  | $            | 21.36 |          | $
|Second Quarter |  |              | 26.72 |          |  
|Third Quarter  |  |              | 21.30 |          |  
|Fourth Quarter |  |              | 23.26 |          |  
|               |  |              |       |          |  
|2002           |  |              |       |          |  
|First Quarter  |  | $            | 25.30 |          | $
|Second Quarter |  |              | 29.48 |          |  
|Third Quarter  |  |              | 28.50 |          |  
|Fourth Quarter |  |              | 34.13 |          |  

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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##### Table of Contents

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):

|Plan category                                                              |  | Number ofsecurities to beissued
uponexercise ofoutstandingoptions |  | Weighted-averageexercise price ofoutstandingoptions |       | Number ofsecuritiesremaining
availablefor future issuanceunder equity compensation plans |          
|-------------------------------------------------------------------------- |  | ----------------------------------------------------------------- |  | --------------------------------------------------- | ----- | ---------------------------------------------------------------------------------------- | ---------
|                                                                           |  |                                                                   |  |                                                     |       |                                                                                          |          
|                                                                           |  |                                                                   |  |                                                     |       |                                                                                          |          
|Equity compensation plans approved by security holders (stock option
plan) |  | 2,626,000                                                         |  | $                                                   | 14.31 |                                                                                          | 1,124,000
|                                                                           |  |                                                                   |  |                                                     |       |                                                                                          |          
|Equity compensation plans not approved by security holders                 |  |                                                                  |  |                                                    |       |                                                                                         |          
|                                                                           |  |                                                                   |  |                                                     |       |                                                                                          |          
|                                                                           |  |                                                                   |  |                                                     |       |                                                                                          |          
|Total                                                                      |  | 2,626,000                                                         |  | $                                                   | 14.31 |                                                                                          | 1,124,000
|                                                                           |  |                                                                   |  |                                                     |       |                                                                                          |          

(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:

|Year |  | Numberof sharesissued |  | Weighted-averageshareprice |       | Cashproceeds |  
|---- |  | --------------------- |  | -------------------------- | ----- | ------------ | -
|     |  |                       |  |                            |       |              |  
|2002 |  | 223,000               |  | $                          | 22.36 |              | $
|2001 |  | 122,400               |  | $                          | 16.00 |              | $
|2000 |  | 65,500                |  | $                          | 7.27  |              | $

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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##### Table of Contents

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.



|                                          |  | As of or for the Year Ended December 31, |       
|----------------------------------------- |  | ---------------------------------------- | ------
|                                          |  |                                          |       
|                                          |  | 1998                                     |       
|                                          |  |                                          |       
|                                          |  | (In thousands except per share data)     |       
|Statement of Operations Data              |  |                                          |       
|Revenues                                  |  | $                                        | 74,780
|Expenses                                  |  |                                          |       
|Lease operating                           |  | 12,399                                   |       
|Production taxes                          |  | 4,941                                    |       
|Exploration                               |  | 59                                       |       
|General and administrative                |  | 7,244                                    |       
|Interest and other                        |  | 13,001                                   |       
|Impairment of hedges                      |  |                                         |       
|Deferred compensation adjustments         |  | (110                                     | )     
|Depletion, depreciation and amortization  |  | 41,695                                   |       
|                                          |  |                                          |       
|Total expenses                            |  | 79,229                                   |       
|                                          |  |                                          |       
|Pretax income (loss)                      |  | (4,449                                   | )     
|Provision for income taxes                |  |                                         |       
|                                          |  |                                          |       
|Net income (loss)                         |  | $                                        | (4,449
|                                          |  |                                          |       
|                                          |  |                                          |       
|Net income (loss) per share               |  |                                          |       
|Basic                                     |  | $                                        | (0.56 
|                                          |  |                                          |       
|Diluted                                   |  | $                                        | (0.56 
|                                          |  |                                          |       
|                                          |  |                                          |       
|Weighted average shares outstanding       |  |                                          |       
|Basic                                     |  | 19,377                                   |       
|Diluted                                   |  | 19,377                                   |       
|                                          |  |                                          |       
|Cash dividends per common share           |  | 0.032                                    |       
|                                          |  |                                          |       
|Balance Sheet Data                        |  |                                          |       
|Current assets                            |  | $                                        | 23,325
|Oil and gas properties, net               |  | 324,777                                  |       
|Total assets                              |  | 351,829                                  |       
|Current liabilities                       |  | 23,579                                   |       
|Debt                                      |  | 142,021                                  |       
|Stockholders equity                      |  | 174,436                                  |       
|                                          |  |                                          |       
|Cash Flow Data                            |  |                                          |       
|Net cash provided by operating activities |  | $                                        | 34,331
|Net cash used in investing activities     |  | (23,145                                  | )     
|Net cash from financing activities        |  | (13,709                                  | )     



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##### Table of Contents

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



|                                         |  | 2001    |       
|---------------------------------------- |  | ------- | ------
|                                         |  |         |       
|(In thousands, except per share data)    |  | First   |       
|                                         |  |         |       
|                                         |  |         |       
|Revenues                                 |  | $       | 64,431
|Lease operating expenses                 |  | 6,535   |       
|Production taxes                         |  | 5,367   |       
|General and administrative               |  | 2,566   |       
|Deferred compensation adjustment         |  | 2,669   |       
|Depletion, depreciation and amortization |  | 11,901  |       
|Net income                               |  | 20,634  |       
|Net income per share (1)                 |  |         |       
|Basic                                    |  | 0.88    |       
|Diluted                                  |  | 0.77    |       
|                                         |  |         |       
|Average daily production                 |  |         |       
|Oil (Bbl)                                |  | 7,421   |       
|Gas (Mcf)                                |  | 108,176 |       
|Equivalent Mcfe                          |  | 152,702 |       
|                                         |  |         |       
|Average realized prices                  |  |         |       
|Oil (Bbl)                                |  | $       | 27.44 
|Gas (Mcf)                                |  | 4.65    |       
|Equivalent Mcfe                          |  | 4.63    |       



|                                         |  | 2002    |       
|---------------------------------------- |  | ------- | ------
|                                         |  |         |       
|(In thousands, except per share data)    |  | First   |       
|                                         |  |         |       
|                                         |  |         |       
|Revenues                                 |  | $       | 51,886
|Lease operating expenses                 |  | 7,154   |       
|Production taxes                         |  | 2,056   |       
|General and administrative               |  | 2,593   |       
|Deferred compensation adjustment         |  | 4,317   |       
|Depletion, depreciation and amortization |  | 14,795  |       
|Net income                               |  | 13,077  |       
|Net income per share (1)                 |  |         |       
|Basic                                    |  | 0.51    |       
|Diluted                                  |  | 0.48    |       
|                                         |  |         |       
|Average daily production                 |  |         |       
|Oil (Bbl)                                |  | 8,044   |       
|Gas (Mcf)                                |  | 128,189 |       
|Equivalent Mcfe                          |  | 176,450 |       
|                                         |  |         |       
|Average realized prices                  |  |         |       
|Oil (Bbl)                                |  | $       | 23.26 
|Gas (Mcf)                                |  | 2.70    |       
|Equivalent Mcfe                          |  | 3.02    |       

(1)Adjusted for the June 2002 25% stock dividend (5-for-4 split).

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

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##### Table of Contents

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

Critical Accounting Policies and Estimates

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

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##### Table of Contents

Factors Affecting Financial Condition and Liquidity

Liquidity and Capital
Resources

During 2002, the Company spent $97.4 million on the further development of properties and $182.5 million on acquisitions. The acquisition
expenditures included $61.4 million and $119.0 million on the Le Norman and Bravo acquisitions, respectively. 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 on the further development of the Mid Continent (Le Norman and Bravo properties) and $5.7 million on the Elysium properties.
These acquisitions and projects, and the continued success in production enhancement allowed production to increase 22% over the prior year. The Company anticipates incurring approximately $150.0 million on the further development of its properties
during 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. The decision to increase or decrease development activity is heavily dependent on the prices being received for production.

At December 31, 2002, the Company had $719.1 million of assets. Total capitalization was $498.6 million, of which 60% was represented by stockholders equity and 40% by bank debt. During 2002, net cash provided by operations totaled
$152.2 million, as compared to $172.8 million in 2001 ($158.9 million and $145.8 million prior to changes in working capital, respectively). At December 31, 2002, there were no significant commitments for capital expenditures. Based upon a $150.0
million capital budget for 2003, the Company expects production to continue to increase in the coming year. The level of these and other future expenditures is largely discretionary, and the amount of funds devoted to any particular activity may
increase or decrease significantly, depending on available opportunities and market conditions. The Company plans to finance its ongoing development, acquisition and exploration expenditures and additional equity repurchases using internal cash
flow, proceeds from asset sales and bank borrowings. In addition, joint ventures or future public and private offerings of debt or equity securities may be utilized.

The Company received proceeds totaling approximately $14.4 million from stock purchase plan purchases and the exercise of stock options during 2002.

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

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

The following summarizes the Companys contractual obligations at December 31, 2002 and the effect such obligations are expected to have on its liquidity and cash flow in future periods (in thousands):



|                                   |  | Less thanOne Year |       | 1  3Years |   | After3 Years |  | Total |        
|---------------------------------- |  | ----------------- | ----- | ---------- | - | ------------ |  | ----- | -------
|                                   |  |                   |       |            |   |              |  |       |        
|Long term debt*                    |  | $                 |      |            | $ |             |  | $     | 200,000
|Non-cancelable operating leases    |  | 1,130             |       | 2,385      |   | 1,536        |  | 5,051 |        
|                                   |  |                   |       |            |   |              |  |       |        
|Total contractual cash obligations |  | $                 | 1,130 |            | $ | 2,385        |  | $     | 201,536
|                                   |  |                   |       |            |   |              |  |       |        

*Based on the retirement of the Elysium bank facility and the refinancing of the Companys bank facility in January 2003.
See Notes (5) and (12) to the accompanying consolidated financial statements.

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##### Table of Contents

Banking

The following summarizes the Companys
borrowings and availability under Patinas and Elysiums revolving credit facilities (in thousands):



|                            |  | December 31, 2002 |        
|--------------------------- |  | ----------------- | -------
|                            |  |                   |        
|Revolving Credit Facilities |  | BorrowingBase     |        
|                            |  |                   |        
|Patina                      |  | $                 | 200,000
|Elysium (net to Patina)     |  | 10,000            |        
|                            |  |                   |        
|Total                       |  | $                 | 210,000
|                            |  |                   |        

In July 1999, the Company entered into an Amended
Bank Credit Agreement (the Credit Agreement). The Credit Agreement is a revolving credit facility in an aggregate amount up to $200.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1,
and equaled $200.0 million at December 31, 2002. Patina had $7.0 million available under the Credit Agreement at December 31, 2002.

The Company may elect that
all or a portion of the credit facility bear interest at a rate equal to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.00% to 1.50%, or (ii) the prime rate plus a margin which fluctuates from 0.00%
to 0.50%. The margins are determined by a debt to EBITDA ratio, as defined. The weighted average interest rate under the facility was 2.9% during 2002 and 2.5% at December 31, 2002.

The Credit Agreement contains financial covenants, including but not limited to a maximum total debt to EBITDA ratio, as defined, and a minimum current ratio. It also contains negative covenants, including but not
limited to restrictions on indebtedness; certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers;
changes in fiscal year; transactions with affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge
causes; issuance of securities; and non-speculative commodity hedging. At December 31, 2001 and 2002, the Company was in compliance with the covenants. Borrowings under the Credit Agreement mature in July 2003, but may be prepaid at anytime. The
Company had a restricted payment basket under the Credit Agreement of $82.3 million as of December 31, 2002, which may be used to repurchase equity securities, pay dividends or make other restricted payments.

In January 2003, the Company completed the refinancing and expansion of its bank facility. The new agreement provides a revolving credit facility in an aggregate amount of up to
$500.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and was initially set at $300.0 million. The Company may elect that all or a portion of the credit facility bear interest at a rate equal
to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.25% to 1.90%, or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.65%. The margins are determined by a debt to EBITDA ratio, as
defined. The facility matures in January 2007. The restricted payment basket under the Credit Agreement was re-set at $25.0 million and increases quarterly by 20% of cash flow, as defined. See Note (12) to the accompanying consolidated financial
statements.

The Company loaned Elysium $53.0 million at the closing of the Elysium transaction in November 2000. In May 2001, Elysium refinanced this loan
with outside banks and entered into a Bank Credit Agreement (the Elysium Credit Agreement). The Elysium Credit Agreement is a revolving credit facility in an aggregate amount up to $60.0 million. The amount available under the facility
is adjusted semi-annually, each May 1 and November 1, and equaled $20.0 million ($10.0 million net to Patina) at December 31, 2002. Elysium had $6.0 million available under the Elysium Credit Agreement at December 31, 2002.

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The Elysium facility is non-recourse to Patina and contains financial covenants, including but not limited to a maximum total debt to
EBITDA ratio, as defined, a minimum current ratio and minimum tangible net worth. At December 31, 2001 and 2002, Elysium was in compliance with the covenants. Borrowings under the Elysium Credit Agreement mature in May 2004, but may be prepaid at
anytime. Elysium may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.50% to 2.00%, or (ii) the prime rate plus a
margin which fluctuates from 0.25% to 0.75%. The margin is determined by a utilization of borrowing base percentage. The weighted average interest rate under the facility was 3.8% during 2002 and 3.4% at December 31, 2002. In January 2003, the
Elysium facility was terminated in conjunction with the closing of the acquisition by the Company of the remaining 50% interest in Elysium. See Note (12) to the accompanying consolidated financial statements.

Cash Flow

The Companys principal sources of cash are operating cash flow and bank borrowings. The Companys
cash flow is highly dependent on oil and gas prices. Pricing volatility will be somewhat reduced as the Company has entered into hedging agreements for 2003, 2004, and 2005, respectively. The $97.4 million of development expenditures for 2002 were
funded entirely with internal cash flow. The 2003 development capital budget of $150.0 million, comprised primarily of $90.9 million of development expenditures in Wattenberg, $42.6 million in the Mid Continent region, and $8.7 million on the
Elysium properties, is expected to increase production by approximately 30%. The budgeted capital and production growth estimates include capital for the Elysium properties acquired in January 2003 and the LNP properties, which is expected to close
in March 2003. However, there can be no assurance that the LNP acquisition will be completed. The purchase price for the Elysium acquisition was $25.8 million and the estimated purchase price for the LNP properties is $40.0 million. The Company
expects the development program to be funded with internal cash flow. As such, exclusive of any other acquisitions or significant equity repurchases, management expects to reduce long-term debt in 2003.

Net cash provided by operating activities in 2000, 2001 and 2002 was $109.4 million, $172.8 million and $152.2 million, respectively. Cash flow from operations increased in 2001 due to the rise in
oil and gas production. Cash flow from operations decreased in 2002 due to the decline in average oil and gas prices, which was partially offset by increased production.

Net cash used in investing activities in 2000, 2001 and 2002 totaled $86.1 million, $82.4 million and $282.4 million, respectively. Capital expenditures in 2000 were largely comprised of the purchase of Elysium for
$47.5 million and development expenditures in Wattenberg of $40.0 million. The further increase in expenditures in 2001 was due to the increase in development expenditures to $77.3 million ($65.6 million in Wattenberg) and the initiation of our
grassroots projects, somewhat offset by $16.5 million of proceeds from sales of assets, primarily Elysiums properties in the Lake Washington Field in Louisiana. The further increase in expenditures in 2002 was due to the Mid Continent
acquisitions for total cash consideration of $180.4 million and the increase in development expenditures to $97.4 million ($82.2 million in Wattenberg).

Net
cash used in financing activities in 2000 and 2001 was $21.2 million and $92.8 million, respectively, while net cash provided by financing activities was $131.9 million in 2002. Sources of financing have been primarily bank borrowings. In 2000, the
Company borrowed $45.0 million of bank debt. These borrowings were used in conjunction with operating cash flow to fund the Elysium acquisition, repurchase $42.0 million of equity securities and loan Elysium $24.5 million. During 2001, the
combination of operating cash flow, proceeds from the exercise of the Companys $10.00 Warrants for $36.0 million, the refinancing of Elysium loan, and proceeds from the sale of the Lake Washington properties, allowed the Company to repay
$100.0 million of bank debt, repurchase $51.5 million of equity securities and fund capital development and acquisition expenditures of $88.1 million. In 2002, the Company borrowed $123.0 million of bank debt. These borrowings were used in
conjunction with operating cash flow and proceeds of $14.4 million from Stock Purchase Plan purchases and the exercise of Company stock options to fund the Le Norman and Bravo acquisitions and capital development expenditures of $97.4
million.

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##### Table of Contents

Capital Requirements

During 2002, $282.1 million of
capital was expended, including $97.4 million on development projects and $182.5 million on acquisitions. Development expenditures represented approximately 64% of internal cash flow. The Company manages its capital budget with the goal of funding
it with internal cash flow. The 2003 development capital budget of $150.0 million is expected to increase production by approximately 30%. The budgeted capital and production growth estimate includes development capital for the Elysium properties
acquired in January 2003 and the LNP properties, which we expect to close in March 2003. There can be no assurance that the LNP acquisition will be completed. The Company expects the capital program to be funded with internal cash flow. The purchase
price for the Elysium acquisition was $25.8 million and the estimated purchase price for the LNP properties is $40.0 million. As such, exclusive of any other acquisitions or significant equity repurchases, management expects to reduce long-term debt
in 2003. Development and exploration activities are highly discretionary, and, for the foreseeable future, management expects such activities to be maintained at levels equal to or below internal cash flow.

Hedging

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 pre-tax 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 pre-tax 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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Inflation and Changes in Prices

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

The following
table indicates the average oil and gas prices received over the last five years and highlights the price fluctuations by quarter for 2001 and 2002. Average price computations exclude hedging gains and losses and other nonrecurring items to provide
comparability. Average prices per Mcfe indicate the composite impact of changes in oil and natural gas prices. Oil production is converted to natural gas equivalents at the rate of one barrel per six Mcf.



|          |  | Average Prices |      
|--------- |  | -------------- | -----
|          |  |                |      
|          |  | Oil            |      
|          |  |                |      
|          |  | (Per Bbl)      |      
|Annual    |  |                |      
|1998      |  | $              | 13.13
|1999      |  | 17.71          |      
|2000      |  | 29.16          |      
|2001      |  | 24.99          |      
|2002      |  | 25.71          |      
|          |  |                |      
|Quarterly |  |                |      
|          |  |                |      
|2001      |  |                |      
|First     |  | $              | 27.86
|Second    |  | 26.96          |      
|Third     |  | 25.81          |      
|Fourth    |  | 19.69          |      
|          |  |                |      
|2002      |  |                |      
|First     |  | $              | 21.02
|Second    |  | 25.72          |      
|Third     |  | 27.74          |      
|Fourth    |  | 27.51          |      

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Results of Operations

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

Average daily oil and gas production in 2002 totaled 8,965 barrels and 136.4 MMcf (190.2 MMcfe), an increase of 22% on an equivalent basis from 2001. The rise in production was due to the increased
level of capital expenditures in Wattenberg and to a lesser extent from the Le Norman and Bravo properties purchased in the fourth quarter of 2002. During 2002, 66 wells were drilled or deepened and 447 refracs and 11 recompletions were performed in
Wattenberg, compared to 68 new wells or deepenings and 323 refracs and seven recompletions in 2001. The Company drilled or deepened 38 wells and performed 52 recompletions on the Elysium properties during 2002. The Company also drilled 33 wells on
the recently acquired Mid Continent properties in 2002. The Company drilled four wells and five coal bed methane wells in 2002 on its grassroots projects compared to nine coal bed methane wells in 2001. Based upon a $150.0 million development budget
and the Elysium and LNP acquisitions for 2003, the Company expects production to increase by over 30% in the coming year.

Average oil prices decreased 5%
from $25.72 per barrel in 2001 to $24.52 in 2002. Average gas prices decreased 22% from $3.48 per Mcf in 2001 to $2.72 in 2002. Average oil prices include hedging gains of $1.9 million or $0.73 per barrel in 2001 and hedging losses of $3.9 million
or $1.19 per barrel in 2002. Average gas prices included hedging gains of $2.1 million or $0.05 per Mcf in 2001 and $24.3 million or $0.49 per Mcf in 2002. Lease operating expenses totaled $28.0 million or $0.40 per Mcfe for 2002 compared to $25.4
million or $0.45 per Mcfe in the prior year. The increase in operating expenses was primarily attributed to increased production and the Le Norman and Bravo acquisitions. Production taxes totaled $11.8 million or $0.17 per Mcfe in 2002 compared to
$13.5 million or $0.24 per Mcfe in 2001. The $1.7 million decrease was primarily due to lower oil and gas prices.

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

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

Deferred compensation adjustment totaled $10.0 million in 2002, an increase of $6.7 million from the prior year.
The increase relates to the greater increase in value of the Companys common shares and other investments held in a Rabbi Trust for the benefit of participants in the Companys deferred compensation plan during 2002. The Companys
common stock price appreciated by 44% or $9.65 per share in 2002 versus 15% or $2.80 per share in 2001.

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

Provision for income taxes for 2002 totaled $31.2 million, a decrease of $3.9 million from 2001. The decrease was due to a 9% decrease in pretax income and a slight decrease in the
Companys effective tax rate. The Company recorded a 35% tax provision for 2002 compared to a 36% tax provision in 2001. The Company expects to record a 38% provision for income taxes in 2003. The increase in the tax rate is due to the
expiration of Section 29 tax credits as of December 31, 2002.

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Comparison of 2001 to 2000.Revenues for 2001 totaled $214.2 million, a 42%
increase over 2000. Net income for 2001 totaled $62.3 million compared to $42.4 million in 2000. The increases in revenue and net income were due primarily to increases in production and higher oil and gas prices.

Average daily oil and gas production in 2001 totaled 7,291 barrels and 112.3 MMcf (156.1 MMcfe), an increase of 31% on an equivalent basis from 2000. The rise in production was due
to the increased level of capital expenditures in Wattenberg, a full years contribution of the Elysium acquisition and, to a minor degree, the grassroots projects. During 2001, 68 wells were drilled or deepened and 323 refracs and seven
recompletions were performed in Wattenberg, compared to 60 new wells or deepenings and 193 refracs and nine recompletions in 2000. In 2001, the Company accumulated significant acreage positions in three Rocky Mountain basins and a leasehold position
with production in West Texas in efforts to expand and diversify through grassroots projects. The Company drilled nine wells in 2001 on one of the grassroots projects, a coal bed methane play in Castlegate, Utah.

Average oil prices increased 12% from $23.00 per barrel in 2000 to $25.72 in 2001. Average gas prices increased 6% from $3.28 per Mcf in 2000 to $3.48 in 2001. Average oil prices
include hedging losses of $10.4 million or $6.17 per barrel in 2000 and hedging gains of $1.9 million or $0.73 per barrel in 2001. Average gas prices included hedging losses of $13.5 million or $0.40 per Mcf in 2000 and hedging gains of $2.1 million
or $0.05 per Mcf in 2001. Lease operating expenses totaled $25.4 million or $0.45 per Mcfe for 2001 compared to $13.4 million or $0.31 per Mcfe in the prior year. The increase in operating expenses was primarily attributed to $8.9 million of
additional operating expenses associated with the oil properties acquired in the Elysium purchase and $1.4 million associated with the grassroots projects. Production taxes totaled $13.5 million in 2001 compared to $10.6 million in 2000 or $0.24 per
Mcfe in both years. The $2.9 million increase was a result of higher oil and gas prices and production.

General and administrative expenses in 2001, net of
reimbursements, totaled $11.0 million, an increase of $3.8 million or 53% from 2000. The increase was primarily due to $3.2 million of expenses associated with Elysium. In December 2001, Elysiums administrative offices in Texas were closed
down and their functions were moved to Denver, Colorado. Included in general and administrative expenses was $279,000 in 2000 of non-cash expenses related to the common stock grants to officers and managers in conjunction with the redistribution of
SOCOs ownership of the Company in 1997. These grants were fully amortized in 2000.

Interest and other expenses fell to $7.0 million in 2001, a decrease
of 30% from the prior year. Interest expense decreased as a result of lower average debt balances and lower average interest rates. The Companys average interest rate in 2001 was 5.8% compared to 7.7% in 2000.

Deferred compensation adjustment totaled $3.2 million in 2001, a decrease of $9.5 million from the prior year. The decrease relates to the smaller increase in value of the
Companys common shares and other investments held in a Rabbi Trust for the benefit of participants in the Companys deferred compensation plan during 2001. The Companys common stock price appreciated by 15% or $2.80 per share in
2001 versus 178% or $12.30 per share in 2000.

Depletion, depreciation and amortization expense for 2001 totaled $49.9 million, an increase of $9.3 million or
23% from 2000. Depletion expense totaled $48.9 million or $0.86 per Mcfe for 2001 compared to $39.6 million or $0.91 per Mcfe for 2000. The increase in depletion expense resulted primarily from the 31% increase in oil and gas production in 2001,
somewhat offset by a lower depletion rate. The depletion rate was lowered in the first quarter of 2001 in conjunction with the completion of the year-end 2000 reserve report. The reduction reflects additional oil and gas reserves due primarily to
the identification of additional refrac projects and drilling locations, upward revisions due to performance and the increase in oil and gas prices. This was somewhat mitigated by an increase in the depletion rate in the fourth quarter of 2001 as a
result of lower oil and gas reserves resulting from lower year-end oil and gas prices. Depreciation and amortization expense in 2000 and 2001 totaled $1.0 million or $0.02 per Mcfe.

Provision for income taxes for 2001 totaled $35.0 million, an increase of $22.1 million from the same period in 2000. The increase was due to higher earnings and reversal of the deferred tax asset valuation allowance in
2000. The Company recorded a 36% tax provision for 2001 compared to a 23% tax provision in 2000.

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Recent Accounting Pronouncements

In July 2001, the FASB
issued SFAS No. 143, Accounting for Asset Retirement Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair
value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The asset retirement liability will be allocated to operating expense by using a systematic and rational method. The
statement is effective for the Company on January 1, 2003. Upon adoption of the statement, the Company currently expects to record an asset retirement obligation of approximately $21.4 million to reflect the Companys legal obligations related
to abandoned wells. In addition, the Company currently expects to record an addition to oil and gas properties of approximately $17.2 million for the related asset retirement cost, and record a one-time, non-cash charge of approximately $2.6 million
for the cumulative effect of change in accounting principle.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, which provides a single accounting model for long-lived assets to be disposed of and changes the criteria that would have to be met to classify an asset as held-for-sale. The statement also requires expected future operating
losses from discontinued operations to be recognized in the periods in which the losses are incurred, which is a change from the current requirement of recognizing such operating losses as of the measurement date. The statement is effective for
fiscal years beginning after December 15, 2001. The adoption of SFAS No. 144 did not have a material impact on the Companys financial position or results of operations.

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

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

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ITEM 7A.QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

The
Companys major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing domestic price for oil and spot prices applicable to the Rocky Mountain and Mid Continent
regions for its natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Natural gas price realizations during 2002, exclusive of any hedges,
ranged from a monthly low of $1.59 per Mcf to a monthly high of $3.48 per Mcf. Oil prices, exclusive of any hedges, ranged from a monthly low of $18.74 per barrel to a monthly high of $29.26 per barrel during 2002. Oil and gas prices have increased
significantly from late 2001 and early 2002 levels. A significant decline in prices of oil or natural gas could have a material adverse effect on the Companys financial condition and results of operations.

In 2002, a 10% reduction in oil and gas prices, excluding oil and gas quantities that were fixed through hedging transactions, would have reduced revenues by $9.4 million. If oil
and gas future prices at December 31, 2002 had declined by 10%, the unrealized hedging gains at that date would have increased by $32.5 million (from $9.1 million to $41.6 million).

The Company regularly enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. The contracts, which are generally placed with major financial
institutions or with counter parties which management believes to be of high credit quality, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these contracts are based upon oil and natural gas futures,
which have a high degree of historical correlation with actual prices received by the Company. Currently, the Companys oil and gas swap contracts are designated as cash flow hedges.

The Company entered into various swap contracts for oil based on NYMEX prices, recognizing losses of $10.4 million and $3.9 million in 2000 and 2002, respectively, and a gain of $1.9 million in 2001, related to these
contracts. The Company entered into various swap contracts for natural gas based on the Colorado Interstate Gas (CIG) index, recognizing a loss of $13.5 million in 2000, and gains of $2.1 million and $24.3 million in 2001 and 2002,
respectively, related to these contracts.

At December 31, 2002, the Company was a party to swap contracts for oil based on NYMEX prices covering approximately
8,125 barrels of oil per day for 2003 at fixed prices ranging from $22.31 to $27.02 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $24.45 per barrel for 2003. The
Company also entered into swap contracts for oil for 2004 as of December 31, 2002, which are summarized in the table below. The unrealized losses on these contracts totaled $7.3 million based on NYMEX futures prices at December 31, 2002.

At December 31, 2002, the Company was a party to swap contracts for natural gas based on CIG and ANR index prices covering approximately 75,000 MMBtus and 12,000
MMBtus per day, respectively, for 2003 at fixed prices ranging from $2.72 to $4.45 per MMBtu based on CIG and from $3.74 to $4.43 per MMBtu based on ANR. The overall weighted average hedged price for the swap contracts is $3.43 per MMBtu for
2003. The Company also entered into natural gas swap contracts for 2004 and 2005 as of December 31, 2002, which are summarized in the table below. The unrealized gains on these contracts totaled $16.4 million based on CIG and ANR futures prices at
December 31, 2002.

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At December 31, 2002, the Company was a party to the fixed price swaps summarized below:



|                    |  | Oil Swaps (NYMEX) |      
|------------------- |  | ----------------- | -----
|                    |  |                   |      
|Time Period         |  | DailyVolumeBbl    |      
|                    |  |                   |      
|01/01/03 - 03/31/03 |  |                   | 8,250
|04/01/03 - 06/30/03 |  |                   | 8,250
|07/01/03 - 09/30/03 |  | 8,000             |      
|10/01/03 - 12/31/03 |  | 8,000             |      
|                    |  |                   |      
|2004                |  |                   | 3,800



|                    |  | Natural Gas Swaps (CIG Index) |        | Natural Gas Swaps (ANR Index) | 
|------------------- |  | ----------------------------- | ------ | ----------------------------- | 
|                    |  |                               |        |                               | 
|Time Period         |  | DailyVolumeMMBtu              |        | $/MMBtu                       | 
|                    |  |                               |        |                               | 
|01/01/03 - 03/31/03 |  |                               | 75,000 |                               | 
|04/01/03 - 06/30/03 |  |                               | 75,000 |                               | 
|07/01/03 - 09/30/03 |  |                               | 75,000 |                               | 
|10/01/03 - 12/31/03 |  |                               | 75,000 |                               | 
|                    |  |                               |        |                               | 
|2004                |  |                               | 40,000 |                               | 
|2005                |  |                               | 40,000 |                               | 

Basis Differentials

The Company sells the majority of its gas production based on the Colorado Interstate Gas (CIG) index. The realized price of the Companys gas and that of other Rocky Mountain
producers has historically traded at a discount to NYMEX gas. This discount is referred to as a basis differential and averaged $0.78 per MMBtu in 2001, ranging from a positive differential of $0.02 per MMBtu in February 2001 to a
negative differential of $1.43 per MMBtu in July 2001. The CIG basis differential for 2002 averaged $1.25 per MMBtu discount from NYMEX, ranging from a discount of $0.30 per MMBtu in January 2002 to a discount of $2.49 per MMBtu in October 2002.
Based on futures prices as of February 2003, the basis differential for 2003 averages a $1.68 per MMBtu discount, ranging from a discount of $2.46 per MMBtu in February 2003 to a discount of $1.07 per MMBtu in December 2003. The significant increase
in the CIG basis differential is due to the warmer than usual winter in late 2002 resulting in less local heating demand and a corresponding increase in gas held in storage due to the limited pipeline capacity for transportation out of the Rocky
Mountain region. As evidenced by the futures prices, the differential is expected to shrink as additional pipeline capacity out of the Rockies is expected to be available in May 2003 (Kern River expansion of 900 MMBtu per day) combined with
expectations for more normalized winter weather in the region.

Interest Rate Risk

At December 31, 2002, the Company had $193.0 million outstanding under its credit facility with an average interest rate of 2.5% and $7.0 million (net to Patina) outstanding under its Elysium credit facility with an average interest rate of
3.4%. The Company may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.00% to 1.50% on the Patina facility or 1.50%
to 2.00% on the Elysium facility or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.50% on the Patina facility or 0.25% to 0.75% on the Elysium facility. The weighted average interest rates under the Patina and Elysium facilities
approximated 2.9% and 3.8%, respectively during 2002. Assuming no change in the amount outstanding at December 31, 2002, the annual impact on interest expense of a ten percent change in the average interest rate would be approximately $377,000, net
of tax. As the interest rate is variable and is reflective of current market conditions, the carrying value approximates the fair value.

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##### Table of Contents

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

Management Responsibility for Financial
Statements

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

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

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

On July 16, 2002, the Board of Directors of the Company approved the
Audit Committees recommendation to hire Deloitte & Touche, LLP (Deloitte) as the Companys independent auditors to replace Arthur Andersen LLP (Arthur Andersen), who was dismissed immediately. Deloittes
appointment was announced on July 29, 2002.

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PART III

ITEM
10.DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY

The
officers and directors are listed below with a description of their experience and certain other information. Other than Mr. Berenson, each director was elected for a one-year term at the Companys 2002 annual stockholders meeting of
stockholders. Mr. Berenson was approved as a new director in December 2002. Officers are appointed by the Board of Directors.

Directors and Executive
Officers

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

|Name                |  | Age |  | Position                                                   
|------------------- |  | --- |  | -----------------------------------------------------------
|                    |  |     |  |                                                            
|Thomas J. Edelman   |  | 52  |  | Chairman and Chief Executive Officer, Chairman of the Board
|                    |  |     |  |                                                            
|Jay W. Decker       |  | 51  |  | President and Director                                     
|                    |  |     |  |                                                            
|David J. Kornder    |  | 42  |  | Executive Vice President and Chief Financial Officer       
|                    |  |     |  |                                                            
|Andrew M. Ashby     |  | 47  |  | Senior Vice President - Operations                         
|                    |  |     |  |                                                            
|David D. Le Norman  |  | 40  |  | Senior Vice President - Business Development               
|                    |  |     |  |                                                            
|Barton R. Brookman  |  | 40  |  | Vice President                                             
|                    |  |     |  |                                                            
|James A. Lillo      |  | 48  |  | Vice President                                             
|                    |  |     |  |                                                            
|Terry L. Ruby       |  | 44  |  | Vice President                                             
|                    |  |     |  |                                                            
|David W. Siple      |  | 43  |  | Vice President                                             
|                    |  |     |  |                                                            
|Jeffrey L. Berenson |  | 52  |  | Director                                                   
|                    |  |     |  |                                                            
|Robert J. Clark     |  | 58  |  | Director                                                   
|                    |  |     |  |                                                            
|Elizabeth K. Lanier |  | 51  |  | Director                                                   
|                    |  |     |  |                                                            
|Alexander P. Lynch  |  | 50  |  | Director                                                   
|                    |  |     |  |                                                            
|Paul M. Rady        |  | 49  |  | Director                                                   

______________

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

ITEM 11.COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS

Information with respect to
officers compensation is incorporated herein by reference to the Companys 2003 Proxy Statement.

ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information with
respect to security ownership of certain beneficial owners and management is incorporated herein by reference to the Companys 2003 Proxy Statement.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

ITEM 14.CONTROLS AND PROCEDURES

Patinas principal executive officer and principal financial officer have evaluated the effectiveness of Patinas
disclosure controls and procedures, as such term is defined in Rule 13a-14(c) and 15d-14(c) of the Securities Exchange Act of 1934, as amended, within 90 days of the filing date of this Annual Report on Form 10-K. Based upon their
evaluation, the principal executive officer and principal financial officer concluded that the Companys disclosure controls and procedures are effective. There were no significant changes in the Companys internal controls or in other
factors that could significantly affect these controls, since the date the controls were evaluated.

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PART IV

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

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

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

3.
Exhibits.

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

2.1Amended and Restated Agreement and Plan of Merger dated as of January 16, 1996
as amended and restated as of March 20, 1996 (Incorporated by reference to Exhibit 2.1 to Amendment No. 1 to the Registration Statement on Form S-4 of the Company (Registration No. 333-572))

2.2Agreement and Plan of Merger among Patina Oil & Gas Corporation, Patina Bravo Corporation,
Bravo Natural Resources, Inc., and Certain of the Stockholders of Bravo Natural Resources, Inc. dated November 6, 2002 (Incorporated herein by reference to Exhibit 2.1 to the Companys Form 8-K filed on December 9, 2002)

3.1Certificate of Incorporation (Incorporated herein by reference to the Exhibit
3.1 to the Companys Registration Statement on Form S-4 (Registration No. 333-572))

3.2Bylaws (Incorporated herein by reference to Exhibit 3.3 to the Companys Registration Statement on Form S-4 (Registration No. 333-572))

3.3Amended and Restated Bylaws of Patina Oil & Gas Corporation. (Incorporated herein by reference
to Exhibit 3.2 of the Companys Form 8-K filed on May 25, 2001)

3.4Certificate of Ownership and Merger of Gerrity Oil & Gas Corporation with and into the Company, effective March 21, 1997 (Incorporated herein by reference to Exhibit 4.3 of the
Companys Form 10-Q for the quarter ended March 31, 1997)

4.1Rights Agreement. (Incorporated herein by reference to Exhibit 3.2 of the Companys Form 8-K filed on May 25, 2001)

10.1Third Amended and Restated Credit Agreement dated January 28, 2003 by and among the Company, as Borrower, and Bank One, NA, as Administrative Agent, Wachovia Bank, National
Association and Wells Fargo Bank, N.A., as Syndication Agents, Bank of America, N.A. and Credit Lyonnais New York Branch, as Documentation Agents, and certain commercial lending institutions *

10.2Agreement and Plan of Reorganization by and among Patina Oil & Gas Corporation, Le Norman Energy
Corporation, Patina Oklahoma Corp., and The Le Norman Shareholders dated October 23, 2002 (Incorporated herein by reference to Exhibit 10.1 of the Companys Form 8-K filed on November 7, 2002)

10.3Patina Oil & Gas Corporation Profit Sharing and Savings Plan and Trust, effective January 1, 1997
(Incorporated herein by reference to Exhibit 10.3 of the Companys Form 10-K for the year ended, December 31, 1997)

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10.4Amended and Restated Patina Oil & Gas
Corporation Deferred Compensation Plan for Select Employees as adopted May 1, 1996 and amended as of September 30, 1997 and further amended as of August 1, 2001. (Incorporated herein by reference to Exhibit 10.1 of the Companys Form 10-Q for
the quarter ended September 30, 2001)

10.5.1Patina Oil & Gas Corporation 1998 Stock
Purchase Plan. (Incorporated herein by reference to Exhibit 10.3.3 of the Companys Form 10-K for the year ended December 31, 1997)

10.5.2Amendment No. 1 to the Patina Oil & Gas Corporation 1998 Stock Purchase Plan. (Incorporated herein by reference to Exhibit 10.3 of the Companys Form 10-Q for the quarter ended June
30, 1999)

10.5.3Patina Oil & Gas Corporation 1996 Employee Stock Option Plan.
(Incorporated by reference to Amendment No. 2 to the Registration Statement on Form S-4 of the Company (Registration No. 333-572))

10.5.4Amendment No. 1 to the 1996 Employee Stock Option Plan of Patina Oil & Gas Corporation. (Incorporated herein by reference to Exhibit 10.2 of the Companys Form 10-Q for the quarter
ended June 30, 1999)

10.6Lease Agreement dated as of December 21, 2000 by
and between Brookfield Denver, Inc., as landlord, and the Company, as tenant (Incorporated herein by reference to Exhibit 10.5.1 of the Companys Form 10-K for the year ended December 31, 2000)

10.6.1Amendment of Lease Agreement dated December 21, 2000 by and between Brookfield Denver, Inc., as landlord, and the Company, as
tenant *

10.6.2Second Amendment of Lease Agreement dated December 21, 2000 by and between
Brookfield Denver, Inc., as landlord, and the Company, as tenant *

10.7Employment Agreement dated July 31, 1997 by and between the Company and Thomas J. Edelman.(Incorporated herein by reference to Exhibit 10.7 of the Companys Form 10-Q for the quarter ended September 30, 1997)

10.8Standstill Agreement dated April 12, 2000 between the Company and Southwestern
Eagle L.L.C. (Incorporated herein by reference to Exhibit 10.1.1 of the Companys Form 10-Q for the quarter ended March 31, 2000)

21.1Subsidiaries of Registrant *

23.1Consent of independent auditors *

23.2Consent of independent reservoir engineers *

*- Filed herewith

(b)Reports on Form 8-K.

The Company filed a current report on Form 8-K on October 1,
2002 to incorporate by reference a press release dated September 30, 2002 announcing the completion of the reaudit of its financial statements for the three-year period ended December 31, 2001.

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The Company filed a current report on Form 8-K on October 7, 2002 to furnish the certifications of the Chief Executive Officer and the
Chief Financial Officer which accompanied the Companys October 4, 2002 filings of Form 10-K/A Amendment No. 1 for the year ending December 31, 2001, Form 10-Q/A Amendment No. 1 for the quarter ending March 31, 2002, and Form 10-Q/A Amendment
No. 1 for the quarter ending June 30, 2002 pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

The Company filed a current report on Form 8-K on
November 1, 2002 to furnish the certifications of the Chief Executive Officer and the Chief Financial Officer which accompanied the Companys November 1, 2002 filing of Form 10-Q for the quarter ending September 30, 2002 pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.

The Company filed a current report on Form 8-K on November 7, 2002 to incorporate by reference a press release dated
November 5, 2002 announcing the closing of the acquisition of Le Norman Energy Corporation.

The Company filed a current report on Form 8-K on December 9, 2002
to incorporate by reference a press release dated December 9, 2002 announcing the closing on December 6, 2002 of the acquisition of Bravo Natural Resources, Inc.

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

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

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

None.

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

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SIGNATURES

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



|                    | PATINA OIL & GAS CORPORATION                                       
|------------------- | -------------------------------------------------------------------
|                    |                                                                    
|Date: March 5, 2003 | By: /s/ Thomas J.
Edelman                                          
|                    | Thomas J. Edelman              Chairman and Chief Executive
Officer

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



|                      |  |                                                                                                |  |              
|--------------------- |  | ---------------------------------------------------------------------------------------------- |  | -------------
|/s/ THOMASJ.EDELMAN   |  | Chairman and Chief Executive Officer(Principal Executive Officer)                              |  | March 5, 2003
|                     
|Thomas J. Edelman    
|                      |  |                                                                                                |  |              
|/s/ JAYW.DECKER       |  | President and Director                                                                         |  | March 5, 2003
|                     
|Jay W. Decker        
|                      |  |                                                                                                |  |              
|/s/ DAVIDJ.KORNDER    |  | Executive Vice President andChief Financial Officer(Principal Financial
andAccounting Officer) |  | March 5, 2003
|                     
|David J. Kornder     
|                      |  |                                                                                                |  |              
|/s/ JEFFREYL.BERENSON |  | Director                                                                                       |  | March 5, 2003
|                     
|Jeffrey L. Berenson  
|                      |  |                                                                                                |  |              
|/s/ ROBERTJ.CLARK     |  | Director                                                                                       |  | March 5, 2003
|                     
|Robert J. Clark      
|                      |  |                                                                                                |  |              
|/s/ ELIZABETHK.LANIER |  | Director                                                                                       |  | March 5, 2003
|                     
|Elizabeth K. Lanier  
|                      |  |                                                                                                |  |              
|/s/ ALEXANDERP.LYNCH  |  | Director                                                                                       |  | March 5, 2003
|                     
|Alexander P. Lynch   
|                      |  |                                                                                                |  |              
|/s/ PAULM.RADY        |  | Director                                                                                       |  | March 5, 2003
|                     
|Paul M. Rady         
|                      |  |                                                                                                |  |              

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CERTIFICATIONS

I, Thomas J. Edelman, certify that:

1. I have reviewed this annual report on Form 10-K of Patina Oil & Gas Corporation;

2. Based on my knowledge, this
annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the
period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all
material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The
registrants other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a)designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b)evaluated the effectiveness of the registrants disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation
Date); and

c)presented in this annual report our conclusions about the effectiveness of the disclosure
controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrants other certifying officers and I have disclosed, based on our most recent
evaluation, to the registrants auditors and the audit committee of registrants board of directors (or persons performing the equivalent function):

a)all significant deficiencies in the design or operation of internal controls which could adversely affect the registrants ability to record, process, summarize and report financial data
and have identified for the registrants auditors any material weaknesses in internal controls; and

b)any
fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal controls; and

6. The registrants
other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

|Date: March 5, 2003 |  |  |                                                        
|------------------- |  |  | -------------------------------------------------------
|                    |  |  | /s/ THOMASJ.EDELMAN                                    
|                    |  |  |                                                        
|                    |  |  | Thomas J. Edelman, Chairman and Chief Executive Officer

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I, David J. Kornder, certify that:

1. I have reviewed this annual report on Form 10-K
of Patina Oil & Gas Corporation;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of,
and for, the periods presented in this annual report;

4. The registrants other certifying officers and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a)designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in
which this annual report is being prepared;

b)evaluated the effectiveness of the registrants disclosure
controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and

c)presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrants other certifying officers and I have disclosed, based on our most recent evaluation, to the registrants auditors and the audit committee of registrants board of directors (or persons
performing the equivalent function):

a)all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrants ability to record, process, summarize and report financial data and have identified for the registrants auditors any material weaknesses in internal controls; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrants internal controls; and

6. The registrants other certifying officers and I have indicated in this annual report whether there were significant changes in
internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material
weaknesses.

|Date: March 5, 2003 |  |  |                                                                       
|------------------- |  |  | ----------------------------------------------------------------------
|                    |  |  | /s/ DAVIDJ.KORNDER                                                    
|                    |  |  |                                                                       
|                    |  |  | David J. Kornder, Executive Vice President and Chief Financial Officer

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GLOSSARY

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

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

Bcf.One billion cubic feet.

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

Credit Facility.The Patina Oil & Gas Corporation $200.0 million revolving bank facility ($500.0 million revolving bank facility after January 2003).

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

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

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

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

Elysium Energy, L.L.C.A New York
limited liability company in which Patina holds a 50% interest. Elysium is engaged in the development, exploration and acquisition of oil and gas properties primarily located in the Illinois Basin, the San Joaquin Basin of California and in central
Kansas.

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

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

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

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

MBbl. Onethousand barrels of crude oil
or other liquid hydrocarbons.

Mcf.One thousand cubic feet.

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

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

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

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MMcf. Onemillion cubic feet.

MMcfe.One million cubic feet of natural gas equivalents.

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

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

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

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

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

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

Proved developed reserves.Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves.The
estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating
conditions.

Proved undeveloped reserves.Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion.

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

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

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

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

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

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

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



| |  |                             |  |                                                                                                                                                            | Page
| |  | --------------------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------- | ----
| |  |                             |  |                                                                                                                                                            |     
| |  | PATNA OIL & GAS CORPORATION | 
| |  |                             |  |                                                                                                                                                            |     
| |  |                             |  | Report of Independent Auditors                                                                                                                             | F-2 
| |  |                             |  |                                                                                                                                                            |     
| |  |                             |  | Consolidated Balance Sheets as of December 31, 2001 and 2002                                                                                               | F-3 
| |  |                             |  |                                                                                                                                                            |     
| |  |                             |  | Consolidated Statements of Operations for the years ended December 31, 2000, 2001 and 2002                                                                 | F-4 
| |  |                             |  |                                                                                                                                                            |     
| |  |                             |  | Consolidated Statements of Changes in Stockholders Equity and Accumulated Other Comprehensive Income for the years ended December 31, 2000, 2001 and 2002 | F-5 
| |  |                             |  |                                                                                                                                                            |     
| |  |                             |  | Consolidated Statements of Cash Flows for the years ended December 31, 2000, 2001 and 2002                                                                 | F-6 
| |  |                             |  |                                                                                                                                                            |     
| |  |                             |  | Notes to Consolidated Financial Statements                                                                                                                 | F-7 
| |  |                             |  |                                                                                                                                                            |     

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REPORT OF INDEPENDENT AUDITORS

To the Stockholders ofPatina Oil & Gas Corporation:

We have audited the accompanying consolidated balance sheets of Patina Oil & Gas Corporation (a Delaware corporation) and its subsidiaries (the Company) as of December 31, 2001 and 2002, and the related
consolidated statements of operations, changes in stockholders equity and accumulated other comprehensive income and cash flows for each of the three years in the period ended December 31, 2002. These financial statements are the
responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial
statements referred to above present fairly, in all material respects, the financial position of Patina Oil & Gas Corporation and its subsidiaries as of December 31, 2001 and 2002, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2
to the consolidated financial statements, on January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities to conform with Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities.

|                                   |  |  |                      
|---------------------------------- |  |  | ---------------------
|                                   |  |  | DELOITTE & TOUCHE LLP
|Denver, Colorado,February 21, 2003 |  |  |                      

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PATINA OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEETS(In thousands except share
data)



|                                                                                               |  | December 31, |        
|---------------------------------------------------------------------------------------------- |  | ------------ | -------
|                                                                                               |  |              |        
|                                                                                               |  | 2001         |        
|                                                                                               |  |              |        
|ASSETS                                                                                         |  |              |        
|Current assets                                                                                 |  |              |        
|Cash and equivalents                                                                           |  | $            | 250    
|Accounts receivable                                                                            |  | 16,407       |        
|Inventory and other                                                                            |  | 3,880        |        
|Unrealized hedging gains                                                                       |  | 20,134       |        
|                                                                                               |  |              |        
|                                                                                               |  | 40,671       |        
|                                                                                               |  |              |        
|                                                                                               |  |              |        
|Unrealized hedging gains                                                                       |  | 31,872       |        
|                                                                                               |  |              |        
|Oil and gas properties, successful efforts method                                              |  | 780,224      |        
|Accumulated depletion, depreciation and amortization                                           |  | (402,213     | )      
|                                                                                               |  |              |        
|                                                                                               |  | 378,011      |        
|                                                                                               |  |              |        
|                                                                                               |  |              |        
|Field equipment and other                                                                      |  | 6,605        |        
|Accumulated depreciation                                                                       |  | (3,844       | )      
|                                                                                               |  |              |        
|                                                                                               |  | 2,761        |        
|                                                                                               |  |              |        
|                                                                                               |  |              |        
|Other assets, net                                                                              |  | 2,209        |        
|                                                                                               |  |              |        
|                                                                                               |  | $            | 455,524
|                                                                                               |  |              |        
|LIABILITIES AND
STOCKHOLDERS EQUITY                                                           |  |              |        
|Current liabilities                                                                            |  |              |        
|Accounts payable                                                                               |  | $            | 27,380 
|Deferred income taxes                                                                          |  | 6,918        |        
|Accrued liabilities                                                                            |  | 10,767       |        
|Unrealized hedging losses                                                                      |  |             |        
|                                                                                               |  |              |        
|                                                                                               |  | 45,065       |        
|                                                                                               |  |              |        
|                                                                                               |  |              |        
|Bank debt                                                                                      |  | 77,000       |        
|Deferred income taxes                                                                          |  | 39,355       |        
|Other noncurrent liabilities                                                                   |  | 18,891       |        
|Unrealized hedging losses                                                                      |  |             |        
|Deferred compensation liability                                                                |  | 25,639       |        
|                                                                                               |  |              |        
|Commitments and contingencies                                                                  |  |              |        
|                                                                                               |  |              |        
|Stockholders equity                                                                           |  |              |        
|Preferred Stock, $.01 par, 5,000,000 shares authorized, none issued or
outstanding             |  |             |        
|Common Stock, $.01 par, 125,000,000 shares authorized, 26,552,447 and 28,129,786 shares
issued |  | 266          |        
|Less Common Stock Held in Treasury, at cost, 1,076,689 shares and 1,036,271
shares             |  | (5,866       | )      
|Capital in excess of par value                                                                 |  | 146,300      |        
|Retained earnings                                                                              |  | 71,513       |        
|Accumulated other comprehensive income                                                         |  | 37,361       |        
|                                                                                               |  |              |        
|                                                                                               |  | 249,574      |        
|                                                                                               |  |              |        
|                                                                                               |  | $            | 455,524
|                                                                                               |  |              |        

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

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PATINA OIL & GAS CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS(In thousands except per
share data)



|                                         |  | Year Ended December 31, |        
|---------------------------------------- |  | ----------------------- | -------
|                                         |  |                         |        
|                                         |  | 2000                    |        
|                                         |  |                         |        
|Revenues                                 |  |                         |        
|Oil and gas sales                        |  | $                       | 148,665
|Other                                    |  | 1,677                   |        
|                                         |  |                         |        
|                                         |  | 150,342                 |        
|                                         |  |                         |        
|                                         |  |                         |        
|Expenses                                 |  |                         |        
|Lease operating                          |  | 13,426                  |        
|Production taxes                         |  | 10,628                  |        
|Exploration                              |  | 293                     |        
|General and administrative               |  | 7,165                   |        
|Interest and other                       |  | 10,117                  |        
|Impairment of oil and gas hedges         |  |                        |        
|Deferred compensation adjustment         |  | 12,734                  |        
|Depletion, depreciation and amortization |  | 40,600                  |        
|                                         |  |                         |        
|                                         |  | 94,963                  |        
|                                         |  |                         |        
|                                         |  |                         |        
|Pretax income                            |  | 55,379                  |        
|                                         |  |                         |        
|                                         |  |                         |        
|Provision for income taxes               |  |                         |        
|Current                                  |  |                        |        
|Deferred                                 |  | 12,953                  |        
|                                         |  |                         |        
|                                         |  | 12,953                  |        
|                                         |  |                         |        
|                                         |  |                         |        
|Net income                               |  | $                       | 42,426 
|                                         |  |                         |        
|                                         |  |                         |        
|Net income per common share              |  |                         |        
|Basic                                    |  | $                       | 1.87   
|                                         |  |                         |        
|Diluted                                  |  | $                       | 1.53   
|                                         |  |                         |        
|                                         |  |                         |        
|Weighted average shares outstanding      |  |                         |        
|Basic                                    |  | 20,930                  |        
|                                         |  |                         |        
|Diluted                                  |  | 27,373                  |        
|                                         |  |                         |        

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

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PATINA OIL & GAS CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES INSTOCKHOLDERS EQUITY AND
ACCUMULATED OTHER COMPREHENSIVE INCOME(In thousands)



|                                                                         |  | PreferredStockAmount |        | Common Stock |        | TreasuryStock |   | Capital inExcess ofPar
Value |     | DeferredCompensation |        | RetainedEarnings(Deficit) |   | AccumulatedOtherComprehensiveIncome(Loss) |         | Total   |     
|------------------------------------------------------------------------ |  | -------------------- | ------ | ------------ | ------ | ------------- | - | ---------------------------- | --- | -------------------- | ------ | ------------------------- | - | ----------------------------------------- | ------- | ------- | ----
|                                                                         |  |                      |        |              |        |               |   |                              |     |                     
|                                                                         |  |                      | Shares |              | Amount |               |   |                              |     |                      |        |                          
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Balance, December 31, 1999                                               |  | $                    | 24     |              | 20,164 |               | $ | 202                          |     | $                    | (4,077 | )                         | $ | 188,638                                   |         | $       | (279
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Repurchase of common and preferred                                       |  | (5                   | )      | (2,048       | )      | (20           | ) |                             |     | (41,571              | )      |                          |   | (549                                      | )       |        |     
|Conversion of preferred into common                                      |  | (19                  | )      | 6,168        |        | 61            |   |                             |     | (43                  | )      |                          |   |                                          |         |        |     
|Issuance of common stock                                                 |  |                     |        | 771          |        | 8             |   |                             |     | 4,565                |        |                          |   |                                          |         |        |     
|Deferred compensation stock issued, net                                  |  |                     |        |             |        |              |   | (426                         | )   |                     |        |                          |   |                                          |         |        |     
|Stock grant vesting                                                      |  |                     |        |             |        |              |   |                             |     |                     |        | 279                       |   |                                          |         |        |     
|Dividends                                                                |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   | (4,477                                    | )       |        |     
|Net income                                                               |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   | 42,426                                    |         |        |     
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Balance, December 31, 2000                                               |  |                     |        | 25,055       |        | 251           |   | (4,503                       | )   | 151,589              |        |                          |   | 12,814                                    |         |        |     
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Repurchase of common and warrants                                        |  |                     |        | (2,941       | )      | (29           | ) |                             |     | (51,445              | )      |                          |   |                                          |         |        |     
|Issuance of common stock                                                 |  |                     |        | 841          |        | 8             |   |                             |     | 8,052                |        |                          |   |                                          |         |        |     
|Deferred compensation stock issued, net                                  |  |                     |        |             |        |              |   | (1,363                       | )   |                     |        |                          |   |                                          |         |        |     
|Conversion of warrants                                                   |  |                     |        | 3,598        |        | 36            |   |                             |     | 35,939               |        |                          |   |                                          |         |        |     
|Tax benefit from stock options                                           |  |                     |        |             |        |              |   |                             |     | 2,165                |        |                          |   |                                          |         |        |     
|Dividends                                                                |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   | (3,568                                    | )       |        |     
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Comprehensive income:                                                    |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Net income                                                               |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   | 62,267                                    |         |        |     
|Cumulative effect of change in accounting principle, net of income taxes |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   |                                          |         | (25,077 | )   
|Contract settlements reclassed to income                                 |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   |                                          |         | 822     |     
|Change in unrealized hedging gains                                       |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   |                                          |         | 61,616  |     
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Total comprehensive income                                               |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   | 62,267                                    |         | 37,361  |     
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Balance, December 31, 2001                                               |  |                     |        | 26,553       |        | 266           |   | (5,866                       | )   | 146,300              |        |                          |   | 71,513                                    |         | 37,361  |     
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Repurchase of common                                                     |  |                     |        |             |        |              |   |                             |     | (9                   | )      |                          |   |                                          |         |        |     
|Issuance of common stock                                                 |  |                     |        | 1,577        |        | 15            |   |                             |     | 23,001               |        |                          |   |                                          |         |        |     
|Deferred compensation stock issued, net                                  |  |                     |        |             |        |              |   | (951                         | )   | 2,820                |        |                          |   |                                          |         |        |     
|Tax benefit from stock options                                           |  |                      |        |             |        |              |   |                             |     | 3,496                |        |                          |   |                                          |         |        |     
|Dividends                                                                |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   | (5,513                                    | )       |        |     
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Comprehensive income:                                                    |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Net income                                                               |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   | 57,707                                    |         |        |     
|Contract settlements reclassed to income                                 |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   |                                          |         | (11,953 | )   
|Change in unrealized hedging gains                                       |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   |                                          |         | (19,607 | )   
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Total comprehensive income                                               |  |                     |        |             |        |              |   |                             |     |                     |        |                          |   | 57,707                                    |         | (31,560 | )   
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     
|Balance, December 31, 2002                                               |  | $                    |       |              | $      | 28,130        |   | $                            | 281 |                      | $      | (6,817                    | ) | $                                         | 175,608 |         | $   
|                                                                         |  |                      |        |              |        |               |   |                              |     |                      |        |                           |   |                                           |         |         |     

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



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PATINA OIL & GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS(In thousands)

|                                                                                 |  | Year Ended December 31, |       
|-------------------------------------------------------------------------------- |  | ----------------------- | ------
|                                                                                 |  |                         |       
|                                                                                 |  | 2000                    |       
|                                                                                 |  |                         |       
|Operating activities                                                             |  |                         |       
|Net income                                                                       |  | $                       | 42,426
|Adjustments to reconcile net income to net cash provided by operating
activities |  |                         |       
|Exploration expense                                                              |  | 293                     |       
|Depletion, depreciation and amortization                                         |  | 40,600                  |       
|Deferred income taxes                                                            |  | 12,953                  |       
|Tax benefit from exercise of stock options                                       |  |                        |       
|Impairment of oil and gas hedges                                                 |  |                        |       
|Deferred compensation adjustment                                                 |  | 12,734                  |       
|Loss (gain) on deferred compensation asset                                       |  | (10                     | )     
|Other                                                                            |  | (627                    | )     
|Changes in current and other assets and liabilities                              |  |                         |       
|Decrease (increase) in Accounts receivable                                       |  | (13,068                 | )     
|Inventory and other                                                              |  | (432                    | )     
|Increase (decrease) in Accounts payable                                          |  | 7,492                   |       
|Income taxes payable                                                             |  |                        |       
|Accrued liabilities                                                              |  | 334                     |       
|Other assets and liabilities                                                     |  | 6,689                   |       
|                                                                                 |  |                         |       
|Net cash provided by operating activities                                        |  | 109,384                 |       
|                                                                                 |  |                         |       
|                                                                                 |  |                         |       
|Investing activities                                                             |  |                         |       
|Development and exploration                                                      |  | (40,289                 | )     
|Acquisitions, net of cash acquired                                               |  | (49,015                 | )     
|Disposition of oil and gas properties                                            |  |                        |       
|Other                                                                            |  | 3,170                   |       
|                                                                                 |  |                         |       
|Net cash used in investing activities                                            |  | (86,134                 | )     
|                                                                                 |  |                         |       
|                                                                                 |  |                         |       
|Financing activities                                                             |  |                         |       
|Increase (decrease) in indebtedness                                              |  | 45,000                  |       
|Repayment from (loan to) affiliate                                               |  | (24,500                 | )     
|Deferred credits                                                                 |  | 1,446                   |       
|Loan origination fees                                                            |  |                        |       
|Issuance of common stock                                                         |  | 3,568                   |       
|Repurchase of common stock and warrants                                          |  | (28,750                 | )     
|Repurchase of preferred stock                                                    |  | (12,846                 | )     
|Preferred stock redemption premium                                               |  | (549                    | )     
|Preferred stock dividends                                                        |  | (2,776                  | )     
|Common stock dividends                                                           |  | (1,816                  | )     
|                                                                                 |  |                         |       
|Net cash provided by (used in) financing activities                              |  | (21,223                 | )     
|                                                                                 |  |                         |       
|                                                                                 |  |                         |       
|Increase (decrease) in cash                                                      |  | 2,027                   |       
|Cash and equivalents, beginning of period                                        |  | 626                     |       
|                                                                                 |  |                         |       
|Cash and equivalents, end of period                                              |  | $                       | 2,653 
|                                                                                 |  |                         |       

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



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PATINA OIL & GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)ORGANIZATION AND NATURE OF BUSINESS

Patina Oil & Gas Corporation (the Company or Patina), a Delaware corporation, was formed in 1996 to hold the assets of Snyder Oil Corporation (SOCO) in the Wattenberg Field and to facilitate the
acquisition of Gerrity Oil & Gas Corporation (Gerrity). In conjunction with the Gerrity acquisition, SOCO received 17.5 million common shares of Patina. In 1997, a series of transactions eliminated SOCOs ownership in the
Company.

In November 2000, Patina acquired various property interests out of bankruptcy. The assets were acquired through Elysium Energy, L.L.C.
(Elysium), a New York limited liability company, in which Patina holds a 50% interest. Patina invested $21.0 million and provided a $60.0 million credit facility to Elysium. See Notes (10) and (12).

In November 2002, Patina acquired the stock of Le Norman Energy Corporation (Le Norman) for $62.0 million in cash 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 and primarily produce oil. See Note (3).

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

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

The Companys operations currently consist of the acquisition,
development, exploitation and production of oil and gas properties. Historically, Patinas properties were primarily located in the Wattenberg Field of Colorados D-J Basin. Over the past two years, the Company accumulated significant
acreage positions in three Rocky Mountain basins and a leasehold position with production in West Texas in efforts to expand and diversify through grassroots projects (Grassroots Projects). Through Elysium, Le Norman, and Bravo and these
recently initiated exploration and development projects, the Company now has oil and gas properties in central Kansas, the Illinois Basin, Utah, Wyoming, Texas, Oklahoma and the San Joaquin Basin of California.

(2)SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Producing Activities

The Company utilizes the successful efforts method of accounting for its oil and gas properties.
Leasehold costs are capitalized when incurred. Unproved properties are assessed periodically within specific geographic areas and impairments are charged to expense. Exploratory expenses, including geological and geophysical expenses and delay
rentals, are charged to expense as incurred. Exploratory drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Costs of productive wells, unsuccessful developmental wells and productive leases are
capitalized and amortized on a unit-of-production basis over the life of the associated oil and gas reserves. Oil is converted to natural gas equivalents (Mcfe) at the rate of one barrel to six Mcf. Amortization of capitalized costs has generally
been provided on a field-by-field basis. An accrual of approximately $1.0 million had been provided for estimated future abandonment costs on certain Elysium properties as of December 31, 2002. No accrual has been provided for the Wattenberg
properties, as management believes that salvage value will approximate abandonment costs.



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The Company follows the provisions of Statement of Financial Accounting Standards No. 144 (SFAS 144), Accounting for
the Impairment or Disposal of Long-Lived Assets, which requires the Company to assess the need for an impairment of capitalized costs of oil and gas properties on a field-by-field basis (seeRecentAccountingPronouncements). When the net book value of properties exceeds their undiscounted future cash flows, the cost of the property is written
down to fair value, which is determined using discounted future cash flows on a field-by field basis. While no impairments were necessary in 2000, 2001, or 2002, changes in oil and gas prices, underlying assumptions or amortization units
could result in impairments in the future.

Field equipment and other

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

OtherAssets

At December 31, 2001, Other Assets represented $2.0 million in assets held in a Rabbi Trust for the benefit of certain
participants under the Companys deferred compensation plan and $71,000 of net loan origination fees related to the credit facility Elysium entered into in May 2001. See Note (10). At December 31, 2002, the balance represented $5.3 million in
assets held in a Rabbi Trust for the benefit of certain participants under the Companys deferred compensation plan and $4.6 million representing the value assigned under purchase accounting for the Companys 30% interest in Le Norman
Partners which the Company acquired in conjunction with the Le Norman acquisition. See Notes (3), (7), and (12).

Section 29 Tax Credits

Between 1996 and 2000, the Company entered into certain arrangements to monetize its Section 29 tax credits. These arrangements resulted in revenue increases of approximately $0.40
per Mcf on production volumes from qualified properties. The Company recorded additional gas revenues of $3.5 million and $600,000 during 2000 and 2001, respectively. As the Companys profitability allowed it to utilize tax credits, the
arrangements were terminated in March 2001. Approximately $6.0 million in Section 29 tax credits were utilized in the Companys 2001 federal tax return and approximately $9.5 million are expected to be utilized in the Companys 2002
federal tax return.

Gas Imbalances

The Company uses the sales method to account
for gas imbalances. Under this method, revenue is recognized based on the cash received rather than the Companys proportionate share of gas produced. Gas imbalances at December 31, 2001 and 2002 were insignificant.

Accumulated Other Comprehensive Income

The Company follows the provisions of SFAS No. 130,
Reporting Comprehensive Income, which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and
distributions to the owners of the Company. The Company had no such changes prior to 2001. The components of accumulated other comprehensive income and related tax effects for the twelve months ended December 31, 2001 were as follows (in
thousands):



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|                                                    |  | Gross  |         | TaxEffect |   | Net ofTax |  
|--------------------------------------------------- |  | ------ | ------- | --------- | - | --------- | -
|                                                    |  |        |         |           |   |           |  
|Cumulative effect of change in accounting principle |  | $      | (39,183 | )         | $ | 14,106    |  
|Change in fair value of hedges                      |  | 89,905 |         | (32,366   | ) | 57,539    |  
|Impaired oil and gas hedging swaps                  |  | 6,370  |         | (2,293    | ) | 4,077     |  
|Contract settlements during the year                |  | 1,284  |         | (462      | ) | 822       |  
|                                                    |  |        |         |           |   |           |  
|                                                    |  | $      | 58,376  |           | $ | (21,015   | )
|                                                    |  |        |         |           |   |           |  

The impairment relates to a fourth quarter 2001
non-cash provision of $6.4 million ($4.1 million net of taxes) related to the write-off of all outstanding oil and gas hedges with Enron North America (Enron). The write-off reduced earnings per share in the quarter and year by $0.14
(fully diluted). In accordance with generally accepted accounting principles, the Company recorded additional non-cash revenues of an identical amount in the course of 2002, as the impaired value of the hedges would have otherwise
expired.

The components of accumulated other comprehensive income and related tax effects for the twelve months ended December 31, 2002 were as follows (in
thousands):



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

Financial Instruments

The book value and estimated fair value of cash and equivalents was $250,000 and $1.9 million at December 31, 2001 and 2002, respectively. The book value and estimated fair value of the
bank debt was $77.0 million and $200.0 million at December 31, 2001 and 2002, respectively. The book value of these assets and liabilities approximates fair value due to their short maturity or floating rate structure of these
instruments.

Derivative Instruments and Hedging Activities

The Company
regularly enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. The contracts, which are generally placed with major financial institutions or with counter parties which
management believes to be of high credit quality, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these contracts are based upon oil and natural gas futures, which have a high degree of historical
correlation with actual prices received by the Company. Currently, the Companys oil and gas swap contracts are designated as cash flow hedges.

The
Company entered into various swap contracts for oil based on NYMEX prices, recognizing losses of $10.4 million and $3.9 million in 2000 and 2002, respectively, and a gain of $1.9 million in 2001, related to these contracts. The Company entered into
various swap contracts for natural gas based on the Colorado Interstate Gas (CIG) index, recognizing a loss of $13.5 million in 2000, and gains of $2.1 million and $24.3 million in 2001 and 2002, respectively, related to these
contracts.



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At December 31, 2002, the Company was a party to swap contracts for oil based on NYMEX prices covering approximately 8,125 barrels of oil
per day for 2003 at fixed prices ranging from $22.31 to $27.02 per barrel. These swaps are summarized in the table below. The overall weighted average hedged price for the swap contracts is $24.45 per barrel for 2003. The Company also entered into
swap contracts for oil for 2004 as of December 31, 2002, which are summarized in the table below. The unrealized losses on these contracts totaled $7.3 million based on NYMEX futures prices at December 31, 2002.

At December 31, 2002, the Company was a party to swap contracts for natural gas based on CIG and ANR index prices covering approximately 75,000 MMBtus and 12,000 MMBtus
per day, respectively, for 2003 at fixed prices ranging from $2.72 to $4.45 per MMBtu based on CIG and from $3.74 to $4.43 per MMBtu based on ANR. The overall weighted average hedged price for the swap contracts is $3.43 per MMBtu for 2003. The
Company also entered into natural gas swap contracts for 2004 and 2005 as of December 31, 2002, which are summarized in the table below. The unrealized gains on these contracts totaled $16.4 million based on CIG and ANR futures prices at December
31, 2002.

At December 31, 2002, the Company was a party to the fixed price swaps summarized below:



|                    |  | Oil Swaps (NYMEX) |               
|------------------- |  | ----------------- | --------------
|                    |  |                   |               
|Time Period         |  |                   | DailyVolumeBbl
|                    |  |                   |               
|01/01/03 - 03/31/03 |  |                   | 8,250         
|04/01/03 - 06/30/03 |  | 8,250             |               
|07/01/03 - 09/30/03 |  | 8,000             |               
|10/01/03 - 12/31/03 |  | 8,000             |               
|                    |  |                   |               
|2004                |  |                   | 3,800         

|                    |  | Natural Gas Swaps (CIG Index) |                  | Natural Gas Swaps (ANR Index) |        
|------------------- |  | ----------------------------- | ---------------- | ----------------------------- | -------
|                    |  |                               |                  |                               |        
|Time Period         |  |                               | DailyVolumeMMBtu |                               | $/MMBtu
|                    |  |                               |                  |                               |        
|01/01/03 - 03/31/03 |  | 75,000                        |                  | 3.60                          |        
|04/01/03 - 06/30/03 |  | 75,000                        |                  | 3.13                          |        
|07/01/03 - 09/30/03 |  | 75,000                        |                  | 3.18                          |        
|10/01/03 - 12/31/03 |  | 75,000                        |                  | 3.51                          |        
|                    |  |                               |                  |                               |        
|2004                |  | 40,000                        |                  | 3.67                          |        
|2005                |  | 40,000                        |                  | 3.70                          |        

The Company follows SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, as amended, which establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. It also requires that changes in the derivatives fair value be recognized currently in earnings unless specific hedge accounting criteria
are met. Special accounting for qualifying hedges allows a derivatives gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting treatment. The Company adopted SFAS No. 133 on January 1, 2001.



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The balance sheet impact of adopting of SFAS No. 133 on January 1, 2001 was as follows (in millions):



|                                                                                             |  | Amount |      
|-------------------------------------------------------------------------------------------- |  | ------ | -----
|                                                                                             |  |        |      
|Unrealized hedging losses                                                                    |  | $      | (43.2
|Unrealized hedging gains                                                                     |  | 4.0    |      
|Deferred tax liability                                                                       |  | (1.4   | )    
|Deferred tax asset                                                                           |  | 15.5   |      
|                                                                                             |  |        |      
|Cumulative effect of a change in accounting principle (accumulated other
comprehensive loss) |  | $      | (25.1
|                                                                                             |  |        |      

During 2001 (excluding the impairment related to the
Enron hedges), net hedging gains of $1.3 million ($822,000 after tax) were reclassified from Accumulated other comprehensive income to earnings and the changes in the fair value of outstanding derivative net liabilities decreased by $89.9 million
($57.5 million after tax). As the underlying prices in the Companys hedge contracts were consistent with the indices used to sell their oil and gas, no ineffectiveness was recognized related to its hedge contracts in 2001.

During 2002, net hedging gains of $18.7 million ($12.0 million after tax) were reclassified from Accumulated other comprehensive income to earnings and the changes in the
fair value of outstanding derivative net liabilities decreased by $24.3 million ($15.5 million after tax). As the underlying prices in the Companys hedge contracts were consistent with the indices used to sell their oil and gas, no
ineffectiveness was recognized related to its hedge contracts in 2002.

As of December 31, 2002, the Company had net unrealized hedging gains of $9.1 million
($5.8 million after tax), comprised of $8.3 million of current assets, $15.6 million of non-current assets, $13.0 million of current liabilities and $1.8 million of non-current liabilities. The Company expects to reclassify as a decrease to earnings
during the next twelve months $4.7 million ($3.0 million after tax) of net unrealized hedging losses from Accumulated other comprehensive income based on estimated futures prices at December 31, 2002.

Stock Options, Awards and Deferred Compensation Arrangements

The Company accounts for its stock-based compensation plans
under the principles prescribed by the Accounting Principles Boards Opinion No. 25 (APB No. 25), Accounting for Stock Issued to Employees. Stock options awarded under the Employee Plan and the non-employee Directors
Plan do not result in recognition of compensation expense. However, the restricted stock awarded under the Restricted Stock Plan is considered to be compensatory and the Company recognized $279,000 of non-cash general and administrative expenses in
2000. No costs were incurred in 2001 and 2002 as these costs were fully amortized in 2000. See Note (7). The Company accounts for assets held in a rabbi trust for certain participants under the Companys deferred compensation plan in accordance
with EITF 97-14. See Note (7).

Per Share Data

On May 23, 2002, the
Companys Board of Directors approved a 5-for-4 stock split which was affected in the form of a 25% stock dividend to common stockholders of record as of June 10, 2002 with a payment date of June 20, 2002. All share and per share amounts for
all periods have been restated to reflect the 5-for-4 stock split.

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



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Risks and Uncertainties

Historically, oil and gas prices
have experienced significant fluctuations and have been particularly volatile in recent years. Price fluctuations can result from variations in weather, levels of regional or national production and demand, availability of transportation capacity to
other regions of the country and various other factors. Increases or decreases in prices received could have a significant impact on future results.

Supplemental Cash Flow
Information

Over the past three years, the Company incurred the following significant non-cash costs:



|                                                   |  | Year Ended December 31, |    
|-------------------------------------------------- |  | ----------------------- | ---
|                                                   |  |                         |    
|                                                   |  | 2000                    |    
|                                                   |  |                         |    
|Stock Purchase Plan                                |  | $                       | 203
|401(k) profit sharing contribution in common stock |  |                         | 589

Other

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

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

Recent Accounting Pronouncements

In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement
Obligations,  which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs
are capitalized as part of the carrying amount of the long-lived asset. The asset retirement liability will be allocated to operating expense by using a systematic and rational method. The statement is effective for the Company on January 1, 2003.
Upon adoption of the statement, the Company currently expects to record an asset retirement obligation of approximately $21.4 million to reflect the Companys legal obligations related to abandoned wells. In addition, the Company currently
expects to record an addition to oil and gas properties of approximately $17.2 million for the related asset retirement cost, and record a one-time, non-cash charge of approximately $2.6 million for the cumulative effect of change in accounting
principle.

In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which provides a single
accounting model for long-lived assets to be disposed of and changes the criteria that would have to be met to classify an asset as held-for-sale. The statement also requires expected future operating losses from discontinued operations to be
recognized in the periods in which the losses are incurred, which is a change from the current requirement of recognizing such operating losses as of the measurement date. The statement is effective for fiscal years beginning after December 15,
2001. The adoption of SFAS No. 144 did not have a material impact on the Companys financial position or results of operations.



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

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

(3)ACQUISITIONS

On November 5, 2002, through Patina Oklahoma Corporation, a wholly owned subsidiary, Patina acquired the stock of Le Norman Energy Corporation (Le Norman or the Le Norman Acquisition) for $62.0 million in cash funded
with borrowings under the Companys bank facility and the issuance of 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.

On December 6, 2002, Patina acquired the stock of Bravo Natural Resources, Inc. (Bravo or the Bravo
Acquisition), a Delaware corporation, for $119.0 million in cash funded with borrowings under the Companys bank facility. Bravos properties are primarily located in Hemphill County, Texas and Custer and Caddo Counties of western
Oklahoma, within the Anadarko Basin. The Bravo properties primarily produce gas.

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



|                              |  | Le Norman |        | Bravo   |  
|----------------------------- |  | --------- | ------ | ------- | -
|                              |  |           |        |         |  
|Purchase Price:               |  |           |        |         |  
|Cash paid                     |  | $         | 62,023 |         | $
|Stock issued                  |  | 5,779     |        |        |  
|                              |  |           |        |         |  
|Total                         |  | $         | 67,802 |         | $
|                              |  |           |        |         |  
|                              |  |           |        |         |  
|Allocation of Purchase Price: |  |           |        |         |  
|Working capital               |  | $         | 215    |         | $
|Oil and gas properties        |  | 66,805    |        | 159,913 |  
|Other non-current assets      |  | 5,271     |        | 2,622   |  
|Deferred income taxes         |  | (4,489    | )      | (40,653 | )
|Other non-current liabilities |  |          |        | (1,124  | )
|                              |  |           |        |         |  
|Total                         |  | $         | 67,802 |         | $
|                              |  |           |        |         |  



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The following table reflects the unaudited pro forma results of operations for the twelve months ended December 31, 2001 and 2002 as
though the acquisitions had occurred on January 1, 2001 (in thousands, except per share amounts):

|                                      |  | Historical Patina |           | Pro Forma |       | Pro Forma Consolidated | 
|------------------------------------- |  | ----------------- | --------- | --------- | ----- | ---------------------- | 
|                                      |  |                   |           |           |      
|Year ended December 31, 2001          |  |                   | Le Norman |           | Bravo |                        | 
|                                      |  |                   |           |           |       |                        | 
|Revenues                              |  | $                 | 214,173   |           | $     | 16,627                 | 
|Net income                            |  | 62,267            |           | 72        |       | 1,156                  | 
|Net income per common share  basic   |  | 2.50              |           |           |       |                        | 
|Net income per common share  diluted |  | 2.31              |           |           |       |                        | 
|                                      |  |                   |           |           |       |                        | 
|Year ended December 31, 2002          |  |                   |           |           |       |                        | 
|Revenues                              |  | $                 | 222,407   |           | $     | 16,097                 | 
|Net income                            |  | 57,707            |           | 822       |       | 1,548                  | 
|Net income per common share  basic   |  | 2.19              |           |           |       |                        | 
|Net income per common share  diluted |  | 2.09              |           |           |       |                        | 

The pro forma amounts above
are presented for information purposes only and are not necessarily indicative of the results which would have occurred had the acquisitions been consummated on January 1, 2001, nor are the pro forma amounts necessarily indicative of the future
results of operations of the Company.

(4)OIL AND GAS
PROPERTIES

The cost of oil and gas properties at December 31, 2001 and 2002 included approximately $7.3 million and $10.3 million, respectively, in net
unevaluated leasehold and property costs to which proved reserves have not been assigned. These amounts have been excluded from amortization during the respective period. The following table sets forth costs incurred related to oil and gas
properties:

|                          |  | 2000                                    |        | 2001  |   | 2002    |  
|------------------------- |  | --------------------------------------- | ------ | ----- | - | ------- | -
|                          |  |                                         |        |       |   |         |  
|                          |  | (In thousands, except per Mcfe amounts) |       
|                          |  |                                         |        |       |   |         |  
|Development               |  | $                                       | 39,996 |       | $ | 77,343  |  
|Acquisition - evaluated   |  | 47,886                                  |        | 6,603 |   | 182,008 |  
|Acquisition - unevaluated |  | 1,129                                   |        | 3,627 |   | 500     |  
|Exploration and other     |  | 293                                     |        | 513   |   | 2,171   |  
|                          |  |                                         |        |       |   |         |  
|                          |  | $                                       | 89,304 |       | $ | 88,086  |  
|                          |  |                                         |        |       |   |         |  
|                          |  |                                         |        |       |   |         |  
|Disposition of properties |  | $                                       |       |       | $ | (16,468 | )
|                          |  |                                         |        |       |   |         |  
|                          |  |                                         |        |       |   |         |  
|Depletion rate (per Mcfe) |  | $                                       | 0.91   |       | $ | 0.86    |  
|                          |  |                                         |        |       |   |         |  

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

In conjunction with the Le Norman and Bravo acquisitions, the Company recorded additions to oil and gas properties of $4.5 million and $40.7 million, respectively, as a result of the deferred tax
liability for the difference between the tax basis of the properties acquired and the book basis attributed to the properties under the purchase method of accounting. See Note (3).



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(5)INDEBTEDNESS

The following indebtedness was outstanding on the respective dates:



|                             |  | December 31,   |       
|---------------------------- |  | -------------- | ------
|                             |  |                |       
|                             |  | 2001           |       
|                             |  |                |       
|                             |  | (In thousands) |       
|Bank facility - Patina       |  | $              | 71,000
|Bank facility  Elysium, net |  | 6,000          |       
|Less current portion         |  |               |       
|                             |  |                |       
|Bank debt, net               |  | $              | 77,000
|                             |  |                |       

In July 1999, the Company entered into an Amended
Bank Credit Agreement (the Credit Agreement). The Credit Agreement is a revolving credit facility in an aggregate amount up to $200.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1,
and equaled $200.0 million at December 31, 2002. Patina had $7.0 million available under the Credit Agreement at December 31, 2002.

The Company may elect that
all or a portion of the credit facility bear interest at a rate equal to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.00% to 1.50%, or (ii) the prime rate plus a margin which fluctuates from 0.00%
to 0.50%. The margins are determined by a debt to EBITDA ratio, as defined. The weighted average interest rate under the facility was 2.9% during 2002 and 2.5% at December 31, 2002.

The Credit Agreement contains financial covenants, including but not limited to a maximum total debt to EBITDA ratio, as defined, and a minimum current ratio. It also contains negative covenants, including but not
limited to restrictions on indebtedness; certain liens; guaranties, speculative derivatives and other similar obligations; asset dispositions; dividends, loans and advances; creation of subsidiaries; investments; leases; acquisitions; mergers;
changes in fiscal year; transactions with affiliates; changes in business conducted; sale and leaseback and operating lease transactions; sale of receivables; prepayment of other indebtedness; amendments to principal documents; negative pledge
causes; issuance of securities; and non-speculative commodity hedging. At December 31, 2001 and 2002, the Company was in compliance with the covenants. Borrowings under the Credit Agreement mature in July 2003, but may be prepaid at anytime. The
Company had a restricted payment basket under the Credit Agreement of $82.3 million as of December 31, 2002, which may be used to repurchase equity securities, pay dividends or make other restricted payments.

In January 2003, the Company completed the refinancing and expansion of its bank facility. The new agreement provides a revolving credit facility in an aggregate amount of up to
$500.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November 1, and was initially set at $300.0 million. The Company may elect that all or a portion of the credit facility bear interest at a rate equal
to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.25% to 1.90%, or (ii) the prime rate plus a margin which fluctuates from 0.00% to 0.65%. The margins are determined by a debt to EBITDA ratio, as
defined. The facility matures in January 2007. The restricted payment basket under the Credit Agreement was re-set at $25.0 million and increases quarterly by 20% of cash flow, as defined. See Note (12).

The Company loaned Elysium $53.0 million at the closing of the Elysium transaction in November 2000. In May 2001, Elysium refinanced this loan with outside banks and entered into a Bank Credit
Agreement (the Elysium Credit Agreement). The Elysium Credit Agreement is a revolving credit facility in an aggregate amount up to $60.0 million. The amount available under the facility is adjusted semi-annually, each May 1 and November
1, and equaled $20.0 million ($10.0 million net to Patina) at December 31, 2002. Elysium had $6.0 million available under the Elysium Credit Agreement at December 31, 2002.



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The Elysium facility is non-recourse to Patina and contains financial covenants, including but not limited to a maximum total debt to
EBITDA ratio, as defined, a minimum current ratio and minimum tangible net worth. At December 31, 2001 and 2002, Elysium was in compliance with the covenants. Borrowings under the Elysium Credit Agreement mature in May 2004, but may be prepaid at
anytime. Elysium may elect that all or a portion of the credit facility bear interest at a rate equal to: (i) the Eurodollar rate for one, two, three or six months plus a margin which fluctuates from 1.50% to 2.00%, or (ii) the prime rate plus a
margin which fluctuates from 0.25% to 0.75%. The margin is determined by a utilization of borrowing base percentage. The weighted average interest rate under the facility was 3.8% during 2002 and 3.4% at December 31, 2002. In January 2003, the
Elysium facility was terminated in conjunction with the closing of the acquisition by the Company of the remaining 50% interest in Elysium. See Note (12).

Based on the new credit facility and the termination of the Elysium facility, scheduled maturities of indebtedness for the next five years are zero in 2003, 2004, 2005, and 2006 and $200.0 million in 2007. Management intends to extend the
maturity of its credit facility on a regular basis; however, there can be no assurance it will be able to do so. Cash payments for interest totaled $10.0 million, $7.2 million and $1.9 million during 2000, 2001 and 2002, respectively.

(6)STOCKHOLDERS EQUITY

A total of 125.0 million common shares, $0.01 par value, are authorized of which 28.1 million were issued at December 31, 2002. The common stock is listed on the New York Stock Exchange. Prior to
December 1997, no dividends had been paid on common stock. In June 2002, a 5-for-4 stock split was affected 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. Adjusted for the stock dividend, a quarterly cash dividend of $0.008 per common share was initiated in December 1997, 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 has a stockholders rights plan designed to ensure that stockholders
receive full value for their shares in the event of certain takeover attempts. The following is a schedule of the changes in the Companys shares of common stock since January 1, 2000:



|                                             |  | 2000       |            | 2001       |   | 2002       |  
|-------------------------------------------- |  | ---------- | ---------- | ---------- | - | ---------- | -
|                                             |  |            |            |            |   |            |  
|Beginning shares                             |  |            | 20,164,100 |            |   | 25,054,800 |  
|                                             |  |            |            |            |   |            |  
|Exercise of stock options                    |  | 311,600    |            | 545,400    |   | 1,010,000  |  
|Issued under Stock Purchase Plan             |  | 65,500     |            | 122,400    |   | 223,000    |  
|Issued in lieu of salaries and bonuses       |  | 160,300    |            | 84,900     |   | 98,400     |  
|Issued for directors fees                    |  | 3,500      |            | 1,900      |   | 2,300      |  
|Issued for Le Norman acquisition             |  |           |            |           |   | 205,300    |  
|Conversion of 7.125% preferred stock         |  | 185,000    |            |           |   |           |  
|Conversion of 8.50% preferred stock          |  | 5,982,000  |            |           |   |           |  
|Exercise of $10.00 warrants                  |  | 3,000      |            | 3,597,500  |   |           |  
|Issued to deferred comp plan (salary match)  |  | 17,200     |            | 14,800     |   | 14,400     |  
|Vesting of stock grant                       |  | 173,200    |            | 41,600     |   |           |  
|Contributed to 401(k) plan                   |  | 37,000     |            | 30,300     |   | 24,200     |  
|                                             |  |            |            |            |   |            |  
|Total shares issued                          |  | 6,938,300  |            | 4,438,800  |   | 1,577,600  |  
|                                             |  |            |            |            |   |            |  
|Repurchases                                  |  | (2,047,600 | )          | (2,941,200 | ) | (200       | )
|                                             |  |            |            |            |   |            |  
|                                             |  |            |            |            |   |            |  
|Ending shares                                |  | 25,054,800 |            | 26,552,400 |   | 28,129,800 |  
|                                             |  |            |            |            |   |            |  
|Treasury shares held in rabbi trust (Note 7) |  | (995,800   | )          | (1,076,700 | ) | (1,036,300 | )
|                                             |  |            |            |            |   |            |  
|                                             |  |            |            |            |   |            |  
|Adjusted shares outstanding                  |  |            | 24,059,000 |            |   | 25,475,700 |  
|                                             |  |            |            |            |   |            |  



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##### Table of Contents

During 2000, 2001 and 2002, the Company repurchased and retired shares of its common stock for $28.8 million, $51.5 million and $9,000,
respectively.

During 2001, 3,597,500 $10.00 warrants ($12.50 prior to the stock split) were converted into common stock with the Company receiving cash
proceeds of $36.0 million. The remaining unexercised warrants expired on May 2, 2001.

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

In January 2000, the Company redeemed all remaining shares of the 7.125% preferred stock. Of the
564,800 shares called, 51,000 were converted into 185,000 shares of common stock and the remaining 513,800 were redeemed for $13.4 million in cash. The cash redemption was financed with borrowings under the bank credit facility. The Company paid
$600,000 in preferred dividends during 2000. Included in the $600,000 of preferred stock dividends paid in 2000 was $549,000 of redemption premiums paid to shareholders that elected to redeem their preferred stock for cash in the first quarter of
2000.

In August 2000, the Company called for redemption the remaining 1,618,500 shares of the 8.50% preferred stock outstanding. The shares were converted
into 6.0 million shares of common stock. The Company paid $2.6 million in preferred dividends during 2000.

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



|                                                |  | Year Ended December 31, |       
|----------------------------------------------- |  | ----------------------- | ------
|                                                |  |                         |       
|                                                |  | 2000                    |       
|                                                |  |                         |       
|                                                |  | NetIncome               |       
|                                                |  |                         |       
|Net income                                      |  | $                       | 42,426
|7.125% preferred dividends                      |  | (600                    | )     
|8.50% preferred dividends                       |  | (2,610                  | )     
|                                                |  |                         |       
|Basic net income attributable to common stock   |  | 39,216                  |       
|                                                |  |                         |       
|                                                |  |                         |       
|Effect of dilutive securities:                  |  |                         |       
|7.125% preferred stock                          |  |                        |       
|8.50% preferred stock                           |  | 2,610                   |       
|Stock options                                   |  |                        |       
|Unvested stock grant                            |  |                        |       
|$10.00 common stock warrants                    |  |                        |       
|                                                |  |                         |       
|Diluted net income attributable to common stock |  | $                       | 41,826
|                                                |  |                         |       





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(7)EMPLOYEE BENEFIT PLANS

401(k) Savings

The Company maintains a 401(k) profit sharing and savings plan (the 401(k)
Plan). Eligible employees may make voluntary contributions to the 401(k) Plan. The Company may, at its discretion, make additional matching or profit sharing contributions to the 401(k) Plan. The Company made profit sharing contributions of
$589,000, $647,000 and $801,000 for 2000, 2001 and 2002, respectively. The contributions were made in common stock. A total of 37,000, 30,300 and 24,200 common shares were contributed in 2000, 2001 and 2002, respectively.

Stock Purchase Plan

The Company maintains a shareholder approved stock purchase plan (Stock
Purchase Plan). Pursuant to the Stock Purchase Plan, officers, directors and certain managers are granted options to purchase shares of common stock at prices ranging from 50% to 85% of the closing price of the stock on the trading day prior
to the date of purchase (Market Price). To date, all purchase prices have been set at 75% of Market Price. In addition, employee participants may be granted the right to purchase shares pursuant to the Stock Purchase Plan with all or a
part of their salary and bonus. A total of 625,000 shares of common stock are reserved for possible purchase under the Stock Purchase Plan. In May 1999, an amendment to the Stock Purchase Plan was approved by the stockholders allowing for the annual
renewal of the 625,000 shares of common stock reserved for possible purchase under the Stock Purchase Plan. Plan years run from the date of the Annual Meeting through the next Annual Meeting. In 2000, the Board of Directors approved 145,400 common
shares (exclusive of shares available for purchase with participants salaries and bonuses) for possible purchase by participants during the plan year. As of December 31, 2000, participants had purchased 172,800 shares of common stock,
including 107,300 shares purchased with participants 1999 bonuses, at an average price of $9.70 per share ($7.27 net price per share), resulting in cash proceeds to the Company of $665,000. In 2001, the Board of Directors approved 151,600
common shares (exclusive of shares available for purchase with participants salaries and bonuses) for possible purchase by participants during the plan year. As of December 31, 2001, participants had purchased 122,400 shares of common stock at
an average price of $21.33 per share ($16.00 net price per share), resulting in cash proceeds to the Company of $2.0 million. In 2002, the Board of Directors approved 177,000 common shares (exclusive of shares available for purchase with
participants salaries and bonuses) for possible purchase by participants during the plan year. As of December 31, 2002, participants had purchased 223,000 shares of common stock at an average price of $29.81 per share ($22.36 net price per
share), resulting in cash proceeds to the Company of $5.0 million. The Company recorded non-cash general and administrative expenses of $203,000, $653,000 and $1.7 million associated with these purchases for 2000, 2001 and 2002, respectively.
Participants had 104,800, 95,100 and zero shares available for purchase under the Plan at December 31, 2000, 2001 and 2002, respectively.

Deferred Compensation
Plan

The Company maintains a shareholder approved deferred compensation plan (Deferred Compensation Plan). This plan is available to officers
and certain managers of the Company. The plan allows participants to defer all or a portion of their salary and annual bonuses (either in cash or Company stock). The Company can make discretionary matching contributions of the participants
salary deferral and those assets are invested in instruments as directed by the participant. The Deferred Compensation Plan does not have dollar limits on tax-deferred contributions. The assets of the Deferred Compensation Plan are held in a Rabbi
Trust (Trust) and, therefore, are available to satisfy the claims of the Companys creditors in the event of bankruptcy or insolvency of the Company. Participants have the ability to direct the Plan Administrator to invest their
salary and bonus deferrals into pre-approved mutual funds held by the Trust. In addition, participants have the right to request that the Plan Administrator re-allocate the portfolio of investments (i.e., cash, mutual funds, Company stock) in the
participants individual account within the Trust, however, the Plan Administrator is not required to honor any such request. Company matching contributions are in the form of either cash or Company stock and vest ratably over a three-year
period. Participants may elect to receive their payments in either cash or the Companys common stock. At December 31, 2002, the balance of the assets in the Trust totaled $38.1 million, including 1,036,271 shares of common stock of the Company
valued at $32.8 million. The Company accounts for the Deferred Compensation Plan in accordance with Emerging Issues Task Force (EITF)



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##### Table of Contents

Abstract 97-14, Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held in a Rabbi Trust and Invested.

Assets of the Trust, other than common stock of the Company, are invested in 11 mutual funds that cover the investment spectrum from equities to money market instruments.
These mutual funds are publicly quoted and reported at market value. The Company accounts for these investments in accordance with SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. The Trust also holds
common shares of the Company. The Companys common stock that is held by the Trust has been classified as treasury stock in the stockholders equity section of the accompanying balance sheets. The market value of the assets held by the
Trust, exclusive of the market value of the shares of the Companys common stock that are reflected as treasury stock, at December 31, 2001 and 2002, was $2.0 million and $5.3 million, respectively, and is classified as Other Assets in the
accompanying balance sheets. The amounts payable to the plan participants at December 31, 2001 and 2002, including the market value of the shares of the Companys common stock that are reflected as treasury stock, was $25.6 million and $38.1
million, respectively, and is classified as Deferred Compensation Liability in the accompanying balance sheets.

In accordance with EITF 97-14, all market
fluctuations in value of the Trust assets have been reflected in the respective income statements. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of the Company, have been included as Other income in
the respective income statements. Increases or decreases in the market value of the deferred compensation liability, including the shares of common stock of the Company held by the Trust, while recorded as treasury stock, are included as Deferred
compensation adjustments in the respective income statement. In response to the changes in total market value of the Trust, the Company recorded deferred compensation adjustments of $12.7 million, $3.2 million, and $10.0 million in 2000, 2001 and
2002, respectively.

Stock Option and Award Plans

The Company maintains a
shareholder approved stock option plan for employees (the Employee Plan) providing for the issuance of options at prices not less than fair market value at the date of grant. Options to acquire the greater of 3.8 million shares of common
stock or 10% of outstanding diluted common shares may be outstanding at any time. The specific terms of grant and exercise are determinable by the Compensation Committee of the Board of Directors. The options vest over a three-year period (30%, 60%,
100%) and expire five years from the date of grant. The following is a summary of stock options granted under the Employee Plan:



|Year |  |         | OptionsGranted |   | WeightedRangeof ExercisePrices |  | AverageExercisePrice |      
|---- |  | ------- | -------------- | - | ------------------------------ |  | -------------------- | -----
|     |  |         |                |   |                                |  |                      |      
|2000 |  | 631,000 |                | $ | 7.35  $  17.55                |  | $                    | 7.47 
|2001 |  | 792,000 |                | $ | 18.09  $  26.42               |  | $                    | 18.33
|2002 |  | 922,000 |                | $ | 20.62  $  31.66               |  | $                    | 21.02

The Company also maintains a
shareholder approved stock grant and option plan for non-employee Directors (the Directors Plan). The Directors Plan provides for each non-employee Director to receive common shares having a market value equal to $2,500
quarterly in payment of one-half of their retainer. A total of 3,500 shares were issued in 2000, 1,900 were issued in 2001 and 2,300 in 2002. It also provides for 6,250 options to be granted to each non-employee Director upon appointment and upon
annual re-election, thereafter. The options vest over a three-year period (30%, 60%, 100%) and expire five years from the date of grant. The following is a summary of stock options granted under the Directors Plan:





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##### Table of Contents

|Year |  |        | OptionsGranted |   | WeightedRangeof ExercisePrices |  | AverageExercisePrice |      
|---- |  | ------ | -------------- | - | ------------------------------ |  | -------------------- | -----
|     |  |        |                |   |                                |  |                      |      
|2000 |  | 31,000 |                | $ | 13.95                          |  | $                    | 13.95
|2001 |  | 31,000 |                | $ | 19.67  $  26.28               |  | $                    | 24.96
|2002 |  | 31,000 |                | $ | 28.25  $  32.00               |  | $                    | 29.00

In 1997, the shareholders
approved a special stock grant and purchase plan for certain officers and managers (Management Investors) in conjunction with the redistribution of SOCOs ownership in the Company. The granted shares vested 25% per year on January
1, 1998, 1999, 2000 and 2001. The non-vested granted common shares were recorded as Deferred Compensation in the stockholders equity section of the accompanying consolidated balance sheets. The Management Investors simultaneously purchased
additional common shares from the Company at $7.90 per share. A portion of the purchase was financed by the Company, all of which was repaid in January 2001. See Note (10). In conjunction with his appointment in March 1998, the Companys
President was granted 125,000 restricted common shares that vested 33% per year in March 1999, 2000 and 2001. The non-vested granted common shares were recorded as Deferred Compensation in the equity section of the accompanying consolidated balance
sheets. The President simultaneously purchased 125,000 common shares from the Company at $5.50 per share. A portion of this purchase ($584,000) was financed by the Company. As approved by the Board of Directors, the President sold 62,500 common
shares to the Company at $18.80 per share in March 2001, utilizing a portion of these proceeds to repay his note. See Note (10). The Company recognized $279,000 of non-cash general and administrative expenses for 2000 with respect to stock
grants.

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



|                                    |  |             |  | 2000   |        | 2001   |      | 2002   | 
|----------------------------------- |  | ----------- |  | ------ | ------ | ------ | ---- | ------ | 
|                                    |  |             |  |        |        |        |      |        | 
|Net income                          |  | As Reported |  | $      | 42,426 |        | $    | 62,267 | 
|                                    |  | Pro forma   |  | 41,276 |        | 60,698 |      | 54,742 | 
|                                    |  |             |  |        |        |        |      |        | 
|Basic net income per common share   |  | As Reported |  | $      | 1.87   |        | $    | 2.50   | 
|                                    |  | Pro forma   |  | 1.82   |        | 2.43   |      | 2.08   | 
|                                    |  |             |  |        |        |        |      |        | 
|Diluted net income per common share |  | As Reported |  | $      | 1.53   |        | $    | 2.31   | 
|                                    |  | Pro forma   |  |        | 1.49   |        | 2.26 |        | 

The fair value of each option grant is estimated
on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 2000, 2001 and 2002: dividend yield of 1%, 1% and 1%; expected volatility of 49%, 48% and 46%; risk-free interest
rate of 6.6%, 4.7% and 4.2%; and expected life of 4.0 years, 3.6 years and 3.8 years, respectively.



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A summary of the status of the Companys stock option plans as of December 31, 2000, 2001 and 2002 and changes during the years are
presented below:

|                                                               |  | 2000      |           | 2001                         |      | 2002    |          
|-------------------------------------------------------------- |  | --------- | --------- | ---------------------------- | ---- | ------- | ---------
|                                                               |  |           |           |                              |      |         |          
|                                                               |  | Shares    |           | WeightedAverageExercisePrice |      | Shares  |          
|                                                               |  |           |           |                              |      |         |          
|                                                               |  |           |           |                              |      |         |          
|Outstanding at beginning of year                               |  |           | 2,175,000 |                              | $    | 5.27    |          
|Granted                                                        |  | 662,000   |           | 7.78                         |      | 822,000 |          
|Exercised                                                      |  |           | (311,000  | )                            |      | 6.02    |          
|Forfeited                                                      |  | (12,000   | )         | 7.25                         |      | (40,000 | )        
|                                                               |  |           |           |                              |      |         |          
|Outstanding at end of year                                     |  | 2,514,000 |           | $                            | 5.83 |         | 2,751,000
|                                                               |  |           |           |                              |      |         |          
|                                                               |  |           |           |                              |      |         |          
|Options exercisable at year-end                                |  |           | 1,127,000 |                              |      |         | 1,206,000
|                                                               |  |           |           |                              |      |         |          
|                                                               |  |           |           |                              |      |         |          
|Weighted-average fair value of options granted during the year |  |           |           |                              | $    | 3.39    |          

The following table
summarizes information about stock options outstanding at December 31, 2002:

|                |  | Options Outstanding                  |           | Options Exercisable                    |          
|--------------- |  | ------------------------------------ | --------- | -------------------------------------- | ---------
|                |  |                                      |           |                                        |          
|Exercise Price  |  | NumberOutstanding atDecember
31,2002 |           | Weighted-Avg.RemainingContractual
Life |          
|                |  |                                      |           |                                        |          
|$ 2.35 to  3.15 |  |                                      | 447,000   |                                        | 1.3 years
|4.10 to 11.30   |  | 568,000                              |           | 1.6 years                              |          
|13.95 to 18.09  |  | 635,000                              |           | 3.1 years                              |          
|19.67 to 20.62  |  | 814,000                              |           | 4.1 years                              |          
|21.36 to 32.00  |  | 162,000                              |           | 4.2 years                              |          
|                |  |                                      |           |                                        |          
|$ 2.35 to 32.00 |  |                                      | 2,626,000 |                                        |          
|                |  |                                      |           |                                        |          

(8)INCOME TAXES

A reconciliation of the federal statutory rate to the Companys
effective rate as it applies to the tax provision for the years ended December 31, 2000, 2001 and 2002 follows:

|                                                           |  | 2000 |    | 2001 |    | 2002 |   
|---------------------------------------------------------- |  | ---- | -- | ---- | -- | ---- | --
|                                                           |  |      |    |      |    |      |   
|Federal statutory rate                                     |  | 35   | %  | 35   | %  | 35   | % 
|State income tax rate, net of federal benefit              |  | 3    | %  | 3    | %  | 3    | % 
|Decrease in valuation allowance against deferred tax asset |  | (12  | %) |     |    |     |   
|Section 29 tax credits and other                           |  | (3   | %) | (2   | %) | (3   | %)
|                                                           |  |      |    |      |    |      |   
|Effective income tax rate                                  |  | 23   | %  | 36   | %  | 35   | % 
|                                                           |  |      |    |      |    |      |   

Current income tax expense in 2002 totaled $6.9
million for federal purposes and $1.9 million for state purposes. The Company expects to utilize approximately $13.6 million of net operating loss carryforwards in 2002 to reduce current taxes.



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For book purposes the components of the net deferred tax asset and liability at December 31, 2001 and 2002 were:

|                                             |  | 2001           |         | 2002     |  
|-------------------------------------------- |  | -------------- | ------- | -------- | -
|                                             |  |                |         |          |  
|                                             |  | (In thousands) |        
|Deferred tax assets                          |  |                |         |          |  
|NOL and depletion carryforwards              |  | $              | 16,442  |          | $
|Deferred compensation deductions             |  | 4,118          |         | 13,517   |  
|Alternative minimum tax credit carryforwards |  | 4,100          |         | 14,200   |  
|Deferred deductions and other                |  | 2,592          |         | 950      |  
|Valuation allowance                          |  |               |         | (3,601   | )
|                                             |  |                |         |          |  
|                                             |  | 27,252         |         | 54,815   |  
|                                             |  |                |         |          |  
|                                             |  |                |         |          |  
|Deferred tax liabilities                     |  |                |         |          |  
|Taxes relating to unrealized hedging gains   |  | (18,392        | )       | (3,444   | )
|Depreciable and depletable property          |  | (55,133        | )       | (147,940 | )
|                                             |  |                |         |          |  
|                                             |  | (73,525        | )       | (151,384 | )
|                                             |  |                |         |          |  
|                                             |  |                |         |          |  
|Net deferred tax liability                   |  | $              | (46,273 | )        | $
|                                             |  |                |         |          |  

For tax purposes, the Company had net operating loss
carryforwards of approximately $72.6 million at December 31, 2002. Utilization of these losses will be limited to a maximum of approximately $9.8 million per year as a result of the Le Norman, Bravo and earlier acquisitions. These carryforwards
expire from 2005 through 2021. The Company has provided a valuation allowance against the loss carryforwards that could expire unutilized. At December 31, 2002, the Company had AMT credit carryforwards of approximately $14.2 million that are
available indefinitely. The Company paid $11.1 million and $4.8 million in federal and state taxes during 2001 and 2002, respectively.

(9)MAJOR CUSTOMERS

During 2000, 2001 and 2002, Duke Energy Field Services, Inc.
accounted for 32%, 29% and 37%, BP Amoco Production Company accounted for 19%, 13% and 9%, E-Prime accounted for 8%, 10%, and 7%, of revenues, respectively. Accounts receivable amounts from these customers at December 31, 2001 and 2002 totaled $7.5
million and $15.2 million, respectively. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

(10)RELATED PARTY TRANSACTIONS

In October 1997, certain officers and managers purchased common shares at $7.90 per share from the Company. A portion of this purchase was financed by the Company through the issuance of 8.50% recourse promissory notes. The notes were fully
repaid in January 2001. In conjunction with his appointment in March 1998, the President purchased 125,000 shares of common stock at $5.50 per share and was granted 125,000 shares. The Company loaned him $584,000, represented by an 8.50% recourse
promissory note. As approved by the Board of Directors, the President sold 62,500 common shares to the Company at $18.80 per share in March 2001, utilizing a portion of these proceeds to repay his note. In March 2001, the Company loaned an officer
$50,000, represented by a 7.00% recourse promissory note. The note was scheduled for annual principal reductions each March, with payment in full due in 2004. The loan was repaid in September 2002. In May 2001, a director purchased 12,500 common
shares from the Company under the Stock Purchase Plan. The Company loaned the director $136,000 to finance a portion of this purchase. The loan was due May 2004 and was represented by a 7.50% recourse promissory note. The note was repaid in
September 2002.



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In conjunction with the acquisition of Elysium in November 2000, Patina agreed to loan Elysium up to $60.0 million of which $49.0 million
was outstanding at December 31, 2000. In May 2001, Elysium entered into a credit facility with a third party bank. The proceeds from this facility were used to repay Patina. Elysium paid interest of $371,000 in 2000 and $1.0 million in 2001 to
Patina while the loan was outstanding.

Patina provides certain administrative services to Elysium under an operating agreement. The Company was paid $36,000,
$850,000, and $2.9 million for these services in 2000, 2001 and 2002, respectively. In December 2001, Elysiums office in The Woodlands, Texas was closed and all administrative functions were moved to Denver, Colorado. As such, the Company
entered into a management agreement with Elysium providing for an indirect monthly reimbursement of $243,000 and any direct charges for providing this service. As the Company purchased the remaining 50% interest in Elysium in January 2003, there
will be no future indirect monthly reimbursements. See Note (12).

(11)COMMITMENTS AND
CONTINGENCIES

The Company leases office space and certain equipment under non-cancelable operating leases. Future minimum lease payments under such leases
approximate $1.2 million per year from 2003 through 2006.

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

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

(12)SUBSEQUENT
EVENTS

In January 2003, the Company completed the refinancing of its credit facility. The new facility is a $500.0 million revolving line of credit with
an initial borrowing base of $300.0 million due in January 2007. The new facility contains substantially the same terms and covenants of the facility in place at December 31, 2002, except that the interest rate grid was increased by 25 basis
points.

In January 2003, the Company closed a transaction in which it purchased the remaining 50% interest in Elysium for consideration of $25.8 million,
comprised of $16.0 million in cash and the assumption of $9.8 million in debt and other liabilities. The transaction was funded with borrowings under Patinas bank facility. In conjunction with the closing, the Elysium bank credit facility was
retired.

In February 2003, the Company executed a purchase and sale agreement to acquire the remaining 70% interest in Le Norman Partners (LNP)
for $39.8 million, comprised of $18.5 million of cash and the assumption of $21.3 million of debt and other liabilities. LNPs properties are located in Stephens, Garvin, and Carter Counties of southern Oklahoma. The acquisition will be funded
with bank borrowings and is expected to close in March 2003; however, there can be no assurance that the LNP acquisition will be completed.



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(13)UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

Netherland, Sewell & Associates, Inc., independent petroleum consultants, audited the Companys total proved reserves at December 31, 2000, 2001 and 2002. All
reserve estimates are based on economic and operating conditions at that time. Future net cash flows as of each year-end were computed by applying then current prices to estimated future production less estimated future expenditures (based on
current costs) to be incurred in producing and developing the reserves. All reserves are located onshore in the United States.

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

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

Quantities of Proved Reserves

|                                      |  | Oil    |   | Natural Gas |  
|------------------------------------- |  | ------ | - | ----------- | -
|                                      |  |        |   |             |  
|                                      |  | (MBbl) |   | (MMcf)      |  
|Balance, December 31, 1999            |  | 17,420 |   | 361,261     |  
|Revisions                             |  | 1,354  |   | 1,493       |  
|Extensions, discoveries and additions |  | 14,228 |   | 184,104     |  
|Production                            |  | (1,685 | ) | (33,463     | )
|Purchases                             |  | 11,460 |   | 8,862       |  
|Sales                                 |  | (64    | ) | (707        | )
|                                      |  |        |   |             |  
|                                      |  |        |   |             |  
|Balance, December 31, 2000            |  | 42,713 |   | 521,550     |  
|Revisions                             |  | (9,852 | ) | (40,737     | )
|Extensions, discoveries and additions |  | 4,675  |   | 52,713      |  
|Production                            |  | (2,661 | ) | (41,002     | )
|Purchases                             |  | 61     |   | 34,921      |  
|Sales                                 |  | (2,832 | ) | (905        | )
|                                      |  |        |   |             |  
|                                      |  |        |   |             |  
|Balance, December 31, 2001            |  | 32,104 |   | 526,540     |  
|Revisions                             |  | 12,172 |   | 119,952     |  
|Extensions, discoveries and additions |  | 1,231  |   | 14,756      |  
|Production                            |  | (3,272 | ) | (49,777     | )
|Purchases                             |  | 15,136 |   | 146,253     |  
|Sales                                 |  | (43    | ) | (202        | )
|                                      |  |        |   |             |  
|Balance, December 31, 2002            |  | 57,328 |   | 757,522     |  
|                                      |  |        |   |             |  





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|Proved Developed Reserves |  |        | Oil |         | Natural Gas | 
|------------------------- |  | ------ | --- | ------- | ----------- | 
|                          |  |        |     |         |             | 
|                          |  | (MBbl) |     | (MMcf)  |            
|December 31, 1999         |  | 16,633 |     | 307,560 |            
|                          |  |        |     |         |            
|December 31, 2000         |  | 35,146 |     | 409,103 |            
|                          |  |        |     |         |            
|December 31, 2001         |  | 28,220 |     | 430,487 |            
|                          |  |        |     |         |            
|December 31, 2002         |  | 41,833 |     | 522,227 |            
|                          |  |        |     |         |            

|Standardized Measure                     |  |                | December 31 |          
|---------------------------------------- |  | -------------- | ----------- | ---------
|                                         |  |                |             |          
|                                         |  | 2000           |             | 2001     
|                                         |  |                |             |          
|                                         |  | (In thousands) |            
|Future cash inflows                      |  | $              | 5,427,152   |          
|Future costs                             |  |                |             |          
|Production                               |  | (848,093       | )           | (486,526 
|Development                              |  | (412,672       | )           | (379,474 
|                                         |  |                |             |          
|Future net cash flows                    |  | 4,166,387      |             | 1,002,209
|Undiscounted income taxes                |  | (1,478,535     | )           | (279,461 
|                                         |  |                |             |          
|After tax net cash flows                 |  | 2,687,852      |             | 722,748  
|10% discount factor                      |  | (1,248,907     | )           | (331,809 
|                                         |  |                |             |          
|Standardized measure                     |  | $              | 1,438,945   |          
|                                         |  |                |             |          
|                                         |  |                |             |          
|Pretax Standardized measure (SEC PV10) |  | $              | 2,217,825   |          
|                                         |  |                |             |          

|Changes in Standardized Measure         |  |                | December 31, |           
|--------------------------------------- |  | -------------- | ------------ | ----------
|                                        |  |                |              |           
|                                        |  | 2000           |              | 2001      
|                                        |  |                |              |           
|                                        |  | (In thousands) |             
|Standardized measure, beginning of year |  | $              | 362,528      |           
|Revisions:                              |  |                |              |           
|Prices and costs                        |  | 1,026,518      |              | (1,820,512
|Quantities                              |  | 1,927          |              | 9,303     
|Development costs                       |  | (6,170         | )            | (31,998   
|Accretion of discount                   |  | 45,754         |              | 221,782   
|Income taxes                            |  | (683,866       | )            | 642,635   
|Production rates and other              |  | (7,352         | )            | 23,470    
|                                        |  |                |              |           
|Net revisions                           |  | 376,811        |              | (955,320  
|Extensions, discoveries and additions   |  | 659,094        |              | 25,259    
|Production                              |  | (124,611       | )            | (172,454  
|Future development costs incurred       |  | 39,996         |              | 77,343    
|Purchases (a)                           |  | 128,376        |              | 9,241     
|Sales (b)                               |  | (3,249         | )            | (32,075   
|                                        |  |                |              |           
|Standardized measure, end of year       |  | $              | 1,438,945    |           
|                                        |  |                |              |           

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

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



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PATINA OIL & GAS CORPORATION

INDEX
TO EXHIBITS

2.1Amended and Restated Agreement and Plan of Merger dated as of January 16, 1996 as amended and restated as of March 20,
1996 (Incorporated by reference to Exhibit 2.1 to Amendment No. 1 to the Registration Statement on Form S-4 of the Company (Registration No. 333-572))

2.2Agreement and Plan of Merger among Patina Oil & Gas Corporation,
Patina Bravo Corporation, Bravo Natural Resources, Inc., and Certain of the Stockholders of Bravo Natural Resources, Inc. dated November 6, 2002 (Incorporated herein by reference to Exhibit 2.1 to the Companys Form 8-K filed on December 9,
2002)

3.1Certificate of Incorporation (Incorporated herein by reference to the Exhibit 3.1 to the Companys Registration
Statement on Form S-4 (Registration No. 333-572))

3.2Bylaws (Incorporated herein by reference to Exhibit 3.3 to the Companys Registration Statement on Form S-4
(Registration No. 333-572))

3.3Amended and Restated Bylaws of Patina Oil & Gas Corporation. (Incorporated herein by reference to Exhibit 3.2 of the
Companys Form 8-K filed on May 25, 2001)

3.4Certificate of Ownership and Merger of Gerrity Oil & Gas Corporation with and into the Company, effective March 21,
1997 (Incorporated herein by reference to Exhibit 4.3 of the Companys Form 10-Q for the quarter ended March 31, 1997)

4.1Rights Agreement. (Incorporated herein by reference to Exhibit 3.2 of the Companys Form 8-K
filed on May 25, 2001)

10.1Third Amended and Restated Credit Agreement dated January 28, 2003 by and among the Company, as Borrower, and Bank One, NA, as
Administrative Agent, Wachovia Bank, National Association and Wells Fargo Bank, N.A., as Syndication Agents, Bank of America, N.A. and Credit Lyonnais New York Branch, as Documentation Agents, and certain commercial lending institutions *

10.2Agreement and
Plan of Reorganization by and among Patina Oil & Gas Corporation, Le Norman Energy Corporation, Patina Oklahoma Corp., and The Le Norman Shareholders dated October 23, 2002 (Incorporated herein by reference to Exhibit 10.1 of the Companys
Form 8-K filed on November 7, 2002)

10.3Patina Oil & Gas Corporation Profit Sharing and Savings Plan and Trust, effective January 1, 1997 (Incorporated herein by
reference to Exhibit 10.3 of the Companys Form 10-K for the year ended, December 31, 1997)

10.4Amended and Restated Patina Oil & Gas Corporation Deferred Compensation Plan for Select Employees as adopted May 1, 1996 and
amended as of September 30, 1997 and further amended as of August 1, 2001. (Incorporated herein by reference to Exhibit 10.1 of the Companys Form 10-Q for the quarter ended September 30, 2001)

10.5.1Patina Oil & Gas Corporation 1998 Stock Purchase Plan.
(Incorporated herein by reference to Exhibit 10.3.3 of the Companys Form 10-K for the year ended December 31, 1997)



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10.5.2Amendment No. 1 to the Patina Oil & Gas Corporation 1998 Stock Purchase Plan. (Incorporated herein by reference to Exhibit 10.3 of the Companys Form 10-Q for the quarter ended June 30, 1999)

10.5.3Patina Oil & Gas Corporation 1996 Employee Stock Option
Plan. (Incorporated by reference to Amendment No. 2 to the Registration Statement on Form S-4 of the Company (Registration No. 333-572))

10.5.4Amendment No. 1 to the 1996 Employee Stock Option Plan of Patina Oil & Gas Corporation. (Incorporated herein by
reference to Exhibit 10.2 of the Companys Form 10-Q for the quarter ended June 30, 1999)

10.6Lease Agreement dated as of December 21, 2000 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant
(Incorporated herein by reference to Exhibit 10.5.1 of the Companys Form 10-K for the year ended December 31, 2000)

10.6.1Amendment of Lease Agreement dated December 21, 2000 by and between Brookfield Denver, Inc., as landlord, and the Company,
as tenant *

10.6.2Second
Amendment of Lease Agreement dated December 21, 2000 by and between Brookfield Denver, Inc., as landlord, and the Company, as tenant *

10.7Employment Agreement dated July 31, 1997 by and between the Company and Thomas J. Edelman.(Incorporated herein by reference to Exhibit 10.7 of the Companys Form 10-Q for the quarter ended September 30, 1997)

10.8Standstill Agreement dated April 12, 2000 between the Company and Southwestern Eagle L.L.C. (Incorporated
herein by reference to Exhibit 10.1.1 of the Companys Form 10-Q for the quarter ended March 31, 2000)

21.1Subsidiaries of Registrant *

23.1Consent of independent auditors *

23.2Consent of independent reservoir engineers
*

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

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

*- Filed herewith



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