<PAGE>

================================================================================

                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                   ------------------------------------------
                                   FORM 10-K
(Mark one)
[X]               ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                      OF THE SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 2001

                                      OR
[_]             TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                      OF THE SECURITIES EXCHANGE ACT OF 1934
             For the transaction period from _______ to _________

                         Commission file number 1-14344

                          PATINA OIL & GAS CORPORATION
             (Exact name of registrant as specified in its charter)

             Delaware                                      75-2629477
   (State or other jurisdiction of                        (IRS Employer
    incorporation or organization)                      Identification No.)

           1625 Broadway                                      80202
         Denver, Colorado                                   (Zip Code)
(Address of principal executive offices)

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

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

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

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

     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
[X] Yes  [_] No

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

     The aggregate market value of the 14,367,000 shares of voting stock held by
non-affiliates of the registrant, based upon the closing sale price of the
common stock on March 1, 2002 of $27.50 per share as reported on the New York
Stock Exchange, was $395,093,000.  Shares of common stock held by each officer
and director and by each person who owns 5% or more of the outstanding common
stock have been excluded in that such persons may be deemed affiliates. This
determination of affiliate status is not necessarily a conclusive determination
for other purposes.

     As of March 1, 2002, the registrant had 21,659,939 shares of common stock
outstanding.

                       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, 2002.

================================================================================

                                       1
<PAGE>

                          PATINA OIL & GAS CORPORATION
                           Annual Report on Form 10-K
                               December 31, 2001

                                     PART I

ITEM 1.  BUSINESS

GENERAL

   Patina Oil & Gas Corporation ("Patina" or the "Company") is an independent
energy company engaged in the acquisition, development, exploitation and
production of oil and natural gas.  The Company's properties and oil and gas
reserves are predominantly located in the Wattenberg Field ("Wattenberg") of
Colorado's Denver-Julesburg Basin ("D-J Basin"). Patina is one of the largest
producers in the field, currently accounting for over 30% of its production.
Wattenberg is one of the ten largest natural gas fields in the U.S. Since its
discovery in 1970, cumulative production exceeds three trillion cubic feet of
natural gas equivalents.  The Field is located approximately 35 miles northeast
of Denver and stretches over portions of Adams, Boulder, Broomfield and Weld
Counties. One of Wattenberg's most attractive features is that it contains eight
potentially productive formations at depths ranging from 2,000 to 8,000 feet.
Three of the formations, the Codell, the Niobrara and the J-Sand, are "blanket"
zones in the area of the Company's holdings. Other formations, including the
Sussex, Shannon and Dakota are more localized. The existence of several pay
sands allows for multiple completions within a single wellbore, reducing
drilling risks and operating costs.

   The Company was formed in 1996 to hold the Wattenberg assets of Snyder Oil
Corporation ("SOCO") and to facilitate the acquisition of SOCO's then largest
competitor in the field, Gerrity Oil & Gas Corporation ("Gerrity").  In the
Gerrity acquisition, SOCO retained 14.0 million shares of the Company's common
stock and Gerrity's shareholders received 6.0 million shares of common stock,
$40.0 million of 7.125% convertible preferred stock and 3.0 million $12.50
common stock warrants.  In 1997, a series of transactions eliminated SOCO's
ownership in the Company. The 7.125% preferred stock was fully retired in
January 2000 and the remaining $12.50 warrants were converted into common stock
with the Company receiving cash proceeds of $36.0 million in May 2001.

   Through Elysium Energy, L.L.C. ("Elysium"), a limited liability company in
which the Company holds a 50% interest, Patina acquired various property
interests out of bankruptcy in November 2000.  Patina invested $21.0 million to
acquire 50% of Elysium and provided it with a $60.0 million credit facility, on
which $49.0 million was outstanding at December 31, 2000.  In May 2001, Elysium
refinanced this loan with outside banks and repaid Patina. The Company's 50%
interest in Elysium's assets, liabilities, revenues and expenses is
proportionately consolidated in its financial statements.  Elysium's oil and gas
properties are located primarily in central Kansas, the Illinois Basin, and the
San Joaquin Basin of 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).  Approximately 90% of Elysium's production is oil. In late
2001, Patina assumed direct management control of Elysium's properties as the
Elysium office in Texas was closed and relocated to Denver.

   At December 31, 2001, the Company had 719.2 Bcfe of proved reserves, of which
Wattenberg represented 647.7 Bcfe or 90%. The reserves had an estimated pretax
present value of $527.2 million based on unescalated prices and costs in effect
on that date. Total proved reserves fell 59 Bcfe, or 8%, from the prior year's
level. The decrease was largely the result of sharply lower oil and gas prices
at December 31, 2001, which reduced reserves by 112 Bcfe.  Reserve additions and
discoveries added 80 Bcfe, upward performance revisions added 13 Bcfe and
acquisitions, net of sales, added 17 Bcfe, offset by 57 Bcfe of production
during the year.  Exclusive of the impact of lower prices, the Company replaced
roughly 200% of production in 2001.  Approximately 73% of the reserves on a Mcf
equivalent basis were natural gas and over 94% of the pretax present value was
attributable to proved developed reserves. The Company operates over 95% of the
roughly 3,300 producing wells in which it holds a direct working interest in
Wattenberg. At December 31, 2001, the Company's inventory of proven development
projects included 293 drilling or deepening locations, 177 recompletions, 1,783
restimulation ("refrac") projects and over 500 proven production enhancement
projects in Wattenberg. During 2001, the Company's production averaged 156.1
MMcfe per day, of which 140.9 MMcfe per day or 90% was attributed to Wattenberg.
Based on year-end reserves, the Company had a reserve life index of 12.6 years.

                                       2
<PAGE>

   From inception, the Company has focused on consolidating ownership of its
properties, developing an efficient organization, improving operations and
diversifying the asset base through acquisitions and initiating grassroots
projects. In 2001, revenues and net cash provided from operations totaled $214.1
million and $172.8 million, respectively.  This operating cash flow, combined
with $36.0 million in proceeds from the exercise of the $12.50 warrants, the
sale of Elysium's interest in the Lake Washington Field and the subsequent
refinancing of the Elysium loan, funded $88.1 million of capital expenditures,
repayment of $100.0 million of bank debt and repurchases of $51.5 million of the
Company's equity securities. Roughly $10.2 million was spent on acquisitions and
$77.8 million on further development of properties.  The development
expenditures included $65.6 million in Wattenberg for the drilling or deepening
of 61 J-Sand wells, 323 refracs, seven recompletions and the drilling of seven
Codell wells, $9.5 million on grassroots exploration and development and $2.7
million on the Elysium properties.  The benefits of these projects, the full
year contribution of the Elysium acquisition and continued success in production
enhancement allowed production to increase 31% over the prior year.

   As Wattenberg accounted for over 90% of annual production in 2001, it remains
the Company's key asset. With over 2,600 proven development projects in
inventory at year-end, Wattenberg will remain a significant factor in production
growth over the next couple of years. Future Wattenberg activity will focus
primarily on refracing existing Codell wells and the development of J-Sand
reserves through drilling new wells or deepening within existing wellbores.

   The purchase of Elysium in November 2000 marked the beginning of a more
aggressive diversification effort. The acquisition provided the Company a
presence in several areas believed to have significant growth and consolidation
potential, including the Illinois Basin, the San Joaquin Basin of California and
central Kansas. With the move of Elysium's headquarters from Texas to Denver in
late 2001, the Company intends to more fully evaluate and further develop these
properties.

   Over the past twelve months, the Company accumulated sizable acreage
positions in three Rocky Mountain basins and acquired a leasehold position with
existing production in West Texas.  The focus has been on aggregating prospects
with significant reserve potential and long-term development prospects.  The
Company has attempted to target areas where it can apply the tight sand fracture
technology expertise it developed in Wattenberg.  While the grassroots projects
to date have contributed only a minimal amount to production growth and
financial results, they should add significant long-term growth potential to the
Company.

   With over 2,600 proven development projects in Wattenberg combined with the
upside potential in the development of the Elysium properties and our exposure
to significant reserves in the long-term development of our grassroots projects,
the Company anticipates reporting increases in production in 2002.

BUSINESS STRATEGY

   The Company's sizable asset base and cash flow, along with its low production
costs and efficient operating structure, provide it with a competitive advantage
in Wattenberg and in certain analogous basins. These advantages, combined with
management's operational expertise, positions the Company to increase its
reserves, production and cash flows in a cost-efficient manner primarily
through: (i) further Wattenberg development; (ii) generation of grassroots
drilling prospects, and (iii) selectively pursuing consolidation and acquisition
opportunities. The size and timing of such purchases will depend on market
conditions.  The Company's strong financial position appears to afford it the
financial flexibility to execute this strategy.

                                       3
<PAGE>

DEVELOPMENT, ACQUISITION AND EXPLORATION

   During 2001, the Company spent $77.8 million on the further development of
properties and $10.2 million on acquisitions.  The development expenditures
included $65.6 million in Wattenberg for the drilling or deepening of 61 J-Sand
wells, 323 Codell refracs, seven recompletions and the drilling of seven Codell
wells, $9.5 million on grassroots exploration and development and $2.7 million
on the Elysium properties.  These projects, the full year contribution of the
Elysium acquisition and the continued success in production enhancement allowed
production to increase 31% over the prior year.  The Company anticipates
incurring approximately $77.0 million on the further development of its
properties during 2002.

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 acquisition of 50% of Elysium in November 2000.

<TABLE>
<CAPTION>

                                                                                   Year Ended December 31,
                                                                    --------------------------------------------------
                                                                      1997      1998      1999      2000       2001
                                                                    --------   -------   -------   --------  ---------
                                                                          (Dollars in thousands, except prices
                                                                                and per Mcfe information)
<S>                                                                 <C>        <C>       <C>       <C>        <C>
Production
 Oil (MBbl)......................................................      1,889     1,699     1,653      1,685      2,661
 Gas (MMcf)......................................................     26,863    25,522    29,477     33,463     41,002
 MMcfe (a).......................................................     38,194    35,715    39,396     43,572     56,969

Revenues
 Oil.............................................................   $ 37,197   $22,583   $26,218   $ 38,741   $ 68,447
 Gas (b).........................................................     62,342    49,594    64,189    109,924    142,824
                                                                    --------   -------   -------   --------   --------
  Subtotal.......................................................     99,539    72,177    90,407    148,665    211,271
 Other...........................................................        794     2,533     1,164      1,667      2,873
                                                                    --------   -------   -------   --------   --------
  Total..........................................................    100,333    74,710    91,571    150,332    214,144
                                                                    --------   -------   -------   --------   --------
Direct operating expenses
 Lease operating expenses........................................     11,735    12,399    11,902     13,426     25,356
 Production taxes................................................      7,055     4,941     6,271     10,628     13,462
                                                                    --------   -------   -------   --------   --------
  Total..........................................................     18,790    17,340    18,173     24,054     38,818
                                                                    --------   -------   -------   --------   --------
Direct operating margin..........................................   $ 81,543   $57,370   $73,398   $126,278   $175,326
                                                                    ========   =======   =======   ========   ========
Average sales price
 Oil (Bbl).......................................................   $  19.70   $ 13.29   $ 15.86   $  23.00   $  25.72
 Gas (Mcf) (b)...................................................       2.32      1.94      2.18       3.28       3.48
 Mcfe (a)........................................................       2.61      2.02      2.29       3.41       3.71

Lease operating expense per Mcfe.................................   $   0.31   $  0.35   $  0.30   $   0.31   $   0.45
Production tax expense per Mcfe..................................       0.18      0.14      0.16       0.24       0.24
                                                                    --------   -------   -------   --------   --------
Direct operating expense per Mcfe................................       0.49      0.49      0.46       0.55       0.69

Production margin per Mcfe.......................................   $   2.12   $  1.54   $  1.83   $   2.86   $   3.02
</TABLE>
----------
(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.

                                       4
<PAGE>

GATHERING, PROCESSING AND MARKETING

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

   Natural Gas.  The natural gas produced in Wattenberg is high in heating
content (BTU's) and must be processed to extract natural gas liquids ("NGL").
Residue gas is sold to utilities, independent marketers and end users through
intrastate and interstate pipelines. The Company utilizes two separate
arrangements to gather, process and market its gas production. Approximately 30%
of production is sold to Duke Energy Field Services ("Duke Energy") at the
wellhead under percentage of proceeds contracts. Pursuant to this type of
contract, the Company receives a fixed percentage of the proceeds from Duke
Energy's sale of residue gas and NGL's. Substantially all of the Company's
remaining natural gas production is dedicated for gathering to Duke Energy or
Kerr McGee Gathering, LLC, formerly HS 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 market
arrangements 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.

   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 local market posting, which generally approximates a West Texas Intermediate
posting, and is adjusted upward to reflect local demand and quality. BP Amoco
has the right to purchase oil produced from certain of the Company's properties
at market price.

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 eighteen month basis.  Due to the exceptional
gas prices in 2001, the Company extended their hedging program into 2005.  At
December 31, 2001, hedges were in place covering 42.1 Bcf at prices averaging
$3.84 per MMBtu and 710,000 barrels of oil averaging $25.70 per barrel.  The
estimated fair value of the Company's hedge contracts, excluding hedge contracts
with Enron North America Corp. ("Enron"), that would be realized on termination,
approximated a net unrealized pre-tax gain of $52.0 million ($33.3 million gain
net of $18.7 million of deferred taxes) at December 31, 2001, which is presented
on the balance sheet as a short-term gain of $20.1 million and a long-term gain
of $31.9 million based on contract expiration.  The gas contracts expire monthly
through December 2005 while the oil contracts expire monthly through December
2002.  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 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
1999 and 2000 were $4.1 million, $23.9 million, respectively with a pretax gain
of $4.1 million in 2001.   Over the last three years, the Company has recorded
cumulative net pre-tax hedging losses of $23.9 million against income, which,
when combined with the $52.0 million unrealized pre-tax gain at year-end 2001,
results in a $28.1 million cumulative net gain.  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 as Other comprehensive income (loss), a component of Stockholders' Equity.

                                       5
<PAGE>

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 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. In recent years, the Federal Energy Regulatory Commission ("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.

   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.

                                       6
<PAGE>

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 near or intermediate 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 clean-up requirements could adversely affect
the Company's operations and financial position, as well as the industry in
general.  Management believes the Company is in substantial compliance with
current applicable environmental laws and regulations.  The Company has not
experienced any material adverse effect from compliance with environmental
requirements, however, there is no assurance that this will continue.  The
Company did not have any material expenditures in connection with environmental
matters in 2001, nor does it anticipate that such expenditures will be material
in 2002.

   The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), known as the "Superfund" law, imposes 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 general 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

                                       7
<PAGE>

had a material adverse impact on the Company's financial condition and results
of operations. Some oil and gas 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 Resources Conservation and Recovery Act ("RCRA"), as amended, generally
does not regulate most wastes generated by the exploration and production of oil
and gas. 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, 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 solid 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.

RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE SAFE HARBOR PROVISIONS
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

   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 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.  Statements that
are not historical facts contained in this report are forward-looking statements
that involve risks and uncertainties that could cause actual results to differ
from projected results.  Such statements address activities, events or
developments that the Company expects, believes, projects, intends or
anticipates will or may occur, including such matters as future capital,
development and exploration expenditures (including the amount and nature
thereof), drilling, deepening or refracing of wells, reserve estimates
(including estimates of future net revenues associated with such reserves and
the present value of such future net revenues), future production of oil and
natural gas, 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.
Factors that could cause actual results to differ materially ("Cautionary
Disclosures") are described, among other places, in the Gathering, Processing
and Marketing, Competition, and Regulation sections in this Form 10-K and under
the caption "Management's Discussion and Analysis of Financial Condition and
Results of Operations."  Without limiting the Cautionary Disclosures so
described, Cautionary Disclosures include, among others: 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, and regulatory developments. All written and oral
forward-looking statements attributable to the Company or persons acting on its
behalf are expressly qualified in their entirety by the Cautionary Disclosures.
The Company disclaims any obligation to update or revise any forward-looking
statement to reflect events or circumstances occurring hereafter or to reflect
the occurrence of anticipated or unanticipated events.

     With the previous paragraph in mind, you should consider the following
important factors that could cause actual results to differ materially from
those expressed in any forward-looking statement made by the Company or on its
behalf.

                                       8
<PAGE>

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.

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.

                                       9
<PAGE>

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.

     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.

                                       10
<PAGE>

Chief Executive Officers Interest In Another Oil And Gas Company

   Our Chief Executive Officer also serves as the Chairman of Range Resources
Corporation, 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 relationship 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.  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 36,000 square feet and expires
in November 2005.  The monthly rent is approximately $76,000 of which Elysium's
share is $15,000 ($7,500 net to the Company). 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.

EMPLOYEES

   On December 31, 2001, the Company had 185 employees, including 98 that work
in its field office. An additional 102 employees work for Elysium. None of these
employees are represented by a labor union.  The Company believes its
relationship with its employees is satisfactory.


ITEM 2. PROPERTIES

GENERAL

   During 2001, the Company's production averaged 156.1 MMcfe per day, of which
140.9 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, 2001 were
concentrated primarily in Wattenberg.  The Company also has proven reserves
associated with its Elysium acquisition made in late 2000 and the grassroots
projects initiated in 2001. The following table sets forth summary information
with respect to estimated proved reserves at December 31, 2001.

<TABLE>
<CAPTION>
                              Pre-tax Present Value 10%
                              -------------------------
                                   Amount                  Oil     Natural Gas     Total
                               (In thousands)      %     (MBbls)      (MMcf)      (MMcfe)
                               --------------     ----   -------   ------------   --------
<S>                            <C>                <C>    <C>       <C>            <C>
     Wattenberg............       $493,916         94    26,563        488,325    647,703
     Elysium...............         24,713          4     5,541          3,570     36,815
     Grassroots projects...          8,555          2         -         34,645     34,646
                                  --------        ---    ------        -------    -------
     Total.................       $527,184        100    32,104        526,540    719,164
                                  ========        ===    ======        =======    =======
</TABLE>

                                       11
<PAGE>

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 2001, development expenditures in Wattenberg totaled $65.6 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, the benefits of the
Elysium acquisition and continued success with the production enhancement
program allowed the Company to increase its production and to add proved
reserves in 2001 in what is considered a mature field.

   During 2001, the Company drilled or deepened 61 wells to the J-Sand or Dakota
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 $210,000.  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 and Dakota drilling and deepening projects for 2001 averaged $0.86 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, 2001,
the Company had 195 proven J-Sand drilling locations or deepening projects in
inventory.

   The Company performed 323 refracs in Wattenberg during 2001. 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 2001 refrac program averaged $0.85 per Mcfe with projected
rates of return in excess of 100% based on actual prices received through year-
end and futures prices thereafter. At December 31, 2001, the Company had nearly
1,800 proven refrac projects.  Given the exceptional results of the refrac
program, the budgeted activity has been increased to over 400 refrac projects in
2001.

   The Company also performed seven recompletions and drilled seven Codell wells
in the DJ Basin in 2001. The finding and development costs associated with these
projects averaged $1.05 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 177 Codell / J-Sand proven
recompletion opportunities and 98 Codell new drill opportunities at December 31,
2001.  During 2001, tubing was installed in six wellbores and numerous well
workovers, reactivations, and commingling of zones were performed.  These
projects, combined with the new drills, deepenings and refracs, were an integral
part of the 2001 capital development program and helped fuel the 31% 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 2001.

   At December 31, 2001, the Company had working interests in approximately
3,272 gross (3,107 net) producing oil and gas wells in the D-J Basin with
estimated proved reserves of 647.7 Bcfe, including 26.6 million barrels of oil
and 488.3 Bcf of gas.

                                       12
<PAGE>

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 2001, development expenditures for Elysium totaled $5.5
million ($2.7 million net to Patina), for the drilling of 16 wells and
performing 20 recompletions, primarily in the Illinois Basin. 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 14,535 Mcfe, comprised of 2,189 barrels and
1,398 Mcf per day in 2001.  Patina's 50% share of Elysium's estimated proved
reserves totaled 36.8 Bcfe, including 5.5 million barrels of oil and 3.6 Bcf of
gas.

GRASSROOTS PROJECTS

   In 2001, the Company earned a 50% non-operated working interest in a coalbed
methane project ("Castlegate") near Price, Utah. This interest included nine
existing producing coalbed 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 the year by drilling nine
additional wells and installing various gas processing and water disposal
facilities. The project currently has 17 producing wells, with one waiting on
completion. Current gross gas production is approximately 1,700 Mcf per day (700
Mcf per day net to the Company). At December 31, 2001, the Company had spent
$8.3 million on this project, including the capital commitment and additional
acquisition costs.  Proved reserves at year-end totaled 27.1 Bcfe, all of which
was natural gas.  The Company anticipates completing additional water disposal
facilities in 2002 and increasing drilling activity in 2003 and thereafter.

   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 initially produced 350 Mcf per day.  As
of December 31, 2001, the Company had expended $5.5 million on this project. No
proved reserves associated with the project were booked as of year-end.  The
Company anticipates drilling four wells on the prospect in the second half of
2002.

   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 coalbed methane, with additional
objectives in the tight-sand Mesa Verde and a deeper fractured shale interval.
This acreage position came with a shut-in well, which the Company completed and
stimulated in the "Mancos" formation in late 2001. Upon stimulation, the well
initially produced 200 Mcf per day (gross) and five barrels of oil per day.   As
of December 31, 2001, roughly $1.6 million had been expended on the project. No
proved reserves were recorded as of year-end.  The Company anticipates drilling
two coalbed methane wells on the prospect in 2002.

    In July 2001, the Company acquired 19,600 gross acres (19,400 net acres)
with 95 producing gas wells in West Texas ("Adams Baggett").  Current gross gas
production is approximately 1,500 Mcf per day (1,100 Mcf per day net to the
Company).  The Company anticipates increasing value in the project through
improved operating mechanics, recompletions and restimulations in existing
wellbores and down-spaced, infill drilling. Proved reserves at year-end totaled
7.5 Bcfe, all of which was natural gas.  The Company had expended $3.9 million
on this project during 2001. The Company anticipates drilling and refracing ten
wells on the project in 2002.

                                       13
<PAGE>

PROVED RESERVES

   The following table sets forth estimated net proved reserves for the three
years ended December 31, 2001. The 2000 and 2001 estimates include Patina's 50%
share of Elysium's net proved reserves:

<TABLE>
<CAPTION>

                                             December 31,
                                 --------------------------------
         Oil (MBbl)                1999         2000       2001
                                 --------    ---------   --------
<S>                              <C>        <C>          <C>
            Developed
              Producing.......     12,103       18,496     14,898
              Non-producing...      4,530       16,650     13,322
                                 --------    ---------   --------
            Total Developed...     16,633       35,146     28,220
            Undeveloped               787        7,568      3,884
                                 --------    ---------   --------
              Total...........     17,420       42,714     32,104
                                 ========    =========   ========
         Natural gas (MMcf)
            Developed
              Producing.......    225,798      247,934    272,848
              Non-producing...     81,762      161,169    157,639
                                 --------   ----------   --------
            Total Developed       307,560      409,103    430,487
            Undeveloped            53,701      112,447     96,053
                                 --------   ----------   --------
              Total...........    361,261      521,550    526,540
                                 ========   ==========   ========
         Total MMcfe..........    465,781      777,831    719,164
                                 ========   ==========   ========
         Pretax PV10% Value...   $457,542   $2,217,825   $527,184
                                 ========   ==========   ========

         Oil price (Bbl)......     $24.27       $26.07     $19.72
         Gas price (Mcf)......      $2.34        $8.27      $2.35
</TABLE>

   The following table sets forth the estimated pretax future net revenues as of
year-end 2001 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 $78.3 million of future development costs in 2002 (in
thousands):

<TABLE>
<CAPTION>

                                              December 31, 2001
                                     ----------------------------------
Future Net Revenues                  Developed   Undeveloped      Total
-------------------                  ---------   ------------   ----------
<S>                                  <C>         <C>            <C>
         2002.....................    $ 71,267      $(12,973)   $   58,294
         2003.....................      68,152       (22,320)       45,832
         2004.....................      66,676        (2,883)       63,793
         Remainder................     674,417       159,873       834,290
                                      --------      --------    ----------
            Total.................    $880,512      $121,697    $1,002,209
                                      ========      ========    ==========
         Pretax PV10% Value (a)...    $495,886      $ 31,298    $  527,184
                                      ========      ========    ==========
</TABLE>
-----------
(a)  The after tax present value discounted at 10% of the proved reserves
     totaled $390.9 million at year-end 2001. If the reserve estimates were made
     with future prices in affect at December 31, 2001 resulting in average
     wellhead prices of $2.94 per Mcf and $20.42 per barrel over the life of the
     properties, reserves would have approximated 808 Bcfe with a pretax PV10%
     value of $682.0 million.

   The Wattenberg field represents 94% of the pretax PV10% value and 647.7 Bcfe
or 90% of Patina's proved reserves.

   The quantities and values in the preceding tables are based on constant
prices in effect at December 31, 2001, which averaged $19.72 per barrel of oil
and $2.35 per Mcf of gas.  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.

                                       14
<PAGE>

   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, 2001. 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, and estimates of other engineers might differ materially from those shown
above.  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, 2001
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.

                                       15
<PAGE>

PRODUCING WELLS

   The following table sets forth the producing wells in which the Company owned
a working interest at December 31, 2001. Wells are classified as oil or natural
gas wells according to their predominant production stream.

<TABLE>
<CAPTION>
             Principal                  Gross    Net
          Production Stream             Wells   Wells
          -----------------             -----   -----
<S>                                     <C>     <C>
    Wattenberg
    ----------
    Oil..............................   2,890   2,757
    Natural gas......................     382     350
                                        -----   -----
           Total.....................   3,272   3,107
                                        =====   =====

    Elysium
    -------
    Oil..............................   1,087     523
    Natural gas......................      12       4
                                        -----   -----
           Total.....................   1,099     527
                                        =====   =====

    Texas, Utah, Wyoming and other
    ------------------------------
    Oil..............................       -       -
    Natural gas......................     113     104
                                        -----   -----
           Total.....................     113     104
                                        =====   =====

    Total
    -----
    Oil..............................   3,977   3,280
    Natural gas......................     507     458
                                        -----   -----
           Total.....................   4,484   3,738
                                        =====   =====
</TABLE>

    The Company had 168 wells (161 net) in Wattenberg and 1,505 wells (703 net)
in Elysium that were shut-in at December 31, 2001. The Company's average working
interest in the Wattenberg wells was approximately 97%, while the average
working interest in the Elysium wells was approximately 47%.

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 1999 and 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
coalbed methane wells (five net) in Utah.  The Company drilled one exploratory
well in Wyoming at the end of 2001.  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.

<TABLE>
<CAPTION>
                1999   2000   2001
                ----   ----   ----
<S>             <C>    <C>    <C>
Productive
 Gross.......   36.0   60.0   93.0
 Net.........   35.0   59.0   77.0

Dry
 Gross.......    0.0    0.0    0.0
 Net.........    0.0    0.0    0.0
</TABLE>

  At December 31, 2001 the Company had one well in Utah waiting on completion at
year-end.  The above table does not include the exploratory well drilled in
Wyoming, which was productive.  The Company owns a 100% working interest in this
well.

                                       16
<PAGE>

ACREAGE

   The following table sets forth the leasehold acreage held by the Company at
December 31, 2001. 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.

<TABLE>
<CAPTION>
                                 Developed            Undeveloped
                             -----------------   ---------------------
                              Gross      Net      Gross        Net
                             -------   -------   -------   -----------
<S>                          <C>       <C>       <C>       <C>
     Patina
     ------
     Colorado.............   199,000   179,000    70,000        60,000
     Texas................    19,000    19,000         -             -
     Wyoming..............         -         -    68,000        68,000
     Utah.................     2,000     1,000    47,000        20,000
     Michigan.............         -         -    34,000        33,000
                             -------   -------   -------       -------
      Subtotal............   220,000   199,000   219,000       181,000

     Elysium *
     ---------
     California...........    14,000     7,000     3,000         1,000
     Illinois / Indiana...    46,000    19,000     8,000         4,000
     Kansas...............     6,000     3,000    11,000         5,000
     Louisiana / Texas....    27,000     7,000    27,000         4,000
                             -------   -------   -------       -------
      Subtotal............    93,000    36,000    49,000        14,000

     Total................   313,000   235,000   268,000       195,000
                             =======   =======   =======       =======
</TABLE>

----------
     * - 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 2001.

                                       17
<PAGE>

                                    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".  Prior to their expiration in May 2001, the Company had
$12.50 Warrants listed on the NYSE under the symbol "POGWT". Prior to their
redemption in January 2000, the Company's 7.125% Preferred Stock was listed on
the NYSE under the symbol "POGPr".  The Company's 8.50% Preferred Stock, which
was privately held, was converted into Common Stock in September 2000.  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.

<TABLE>
<CAPTION>
                         Common Stock          Warrants
                        ---------------   -----------------
                         High     Low       High      Low
                        ------   ------   --------   ------
<S>                     <C>      <C>      <C>        <C>
  2000
  ----
    First Quarter....   $13.56   $ 8.06     $ 3.13   $ 0.56
    Second Quarter...    20.75    11.25       8.94     2.19
    Third Quarter....    22.19    14.19      10.38     4.00
    Fourth Quarter...    24.00    17.44      11.94     5.81

  2001
  ----
    First Quarter....   $26.70   $19.47     $14.30   $ 7.48
    Second Quarter...    33.40    23.00      14.00    10.30
    Third Quarter....    26.62    21.05          -        -
    Fourth Quarter...    29.07    22.06          -        -
</TABLE>

   On March 1, 2002, the closing price of the Common Stock was $27.50.

HOLDERS OF RECORD

   As of February 27, 2002, there were 115 holders of record of the common stock
and 21.7 million shares outstanding.

DIVIDENDS

   A quarterly cash dividend of $0.01 per common share was initiated in December
1997 and continued through the third quarter of 1999.  The dividend was
increased to $0.02 per share in the fourth quarter of 1999, to $0.04 per share
in the fourth quarter of 2000 and to $0.05 per share in the fourth quarter of
2001. 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 $39.9 million
available for dividends and or other restricted payments as of December 31,
2001.

                                       18
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA

   The following table presents selected historical financial data of the
Company for the five-year period ended December 31, 2001.  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.

<TABLE>
<CAPTION>
                                                       As of or for the Year Ended December 31,
                                               -------------------------------------------------------
                                                 1997        1998        1999        2000        2001
                                               --------    --------    --------    --------   ---------
                                                         (In thousands except per share data)
<S>                                            <C>         <C>         <C>         <C>         <C>
STATEMENT OF OPERATIONS DATA
Revenues....................................   $100,333    $ 74,710    $ 91,571    $150,332    $ 214,144
Expenses
 Lease operating............................     11,735      12,399      11,902      13,426       25,356
 Production taxes...........................      7,055       4,941       6,271      10,628       13,462
 Exploration................................        131          59         666         293          513
 General and administrative.................      7,154       7,139       6,185       7,051       10,602
 Interest and other.........................     16,038      13,001      10,844      10,117        7,034
 Impairment of hedges.......................          -           -           -           -        6,370
 Depletion, depreciation and amortization...     49,076      41,695      40,744      40,600       49,916
 Impairment of oil and gas properties.......     26,047           -           -           -            -
                                               --------    --------    --------    --------    ---------
   Total expenses...........................    117,236      79,234      76,612      82,115      113,253
                                               --------    --------    --------    --------    ---------
Pretax income (loss)........................    (16,903)     (4,524)     14,959      68,217      100,891
Provision for taxes.........................          -           -           -      15,776       36,321
                                               --------    --------    --------    --------    ---------
Net income (loss)...........................   $(16,903)   $ (4,524)   $ 14,959    $ 52,441    $  64,570
                                               ========    ========    ========    ========    =========
Net income (loss) per share
   Basic....................................     $(1.11)     $(0.68)      $0.52       $2.81        $3.10
                                               ========    ========    ========    ========    =========
   Diluted..................................     $(1.11)     $(0.68)      $0.50       $2.28        $2.88
                                               ========    ========    ========    ========    =========
Weighted average shares outstanding
   Basic....................................     18,324      16,025      15,972      17,553       20,834
   Diluted..................................     18,324      16,025      16,471      22,707       22,402

Cash dividends per common share.............      $0.01       $0.04       $0.05       $0.10        $0.17

BALANCE SHEET DATA
  Current assets............................   $ 31,068    $ 23,325    $ 19,350    $ 39,368    $  40,671
  Oil and gas properties, net...............    342,833     324,777     308,035     355,904      378,011
  Total assets..............................    376,875     351,533     330,216     421,254      453,573
  Current liabilities.......................     30,297      23,579      19,108      30,867       45,065
  Debt......................................    146,435     142,021     132,000     177,000       77,000
  Stockholders' equity......................    188,441     175,976     165,890     176,446      269,144

CASH FLOW DATA
  Net cash provided by operations...........   $ 68,645    $ 34,331    $ 49,660    $109,384    $ 172,777
  Net cash used by investing................    (18,801)    (23,145)    (23,669)    (86,134)     (73,725)
  Net cash used by financing................    (43,388)    (13,709)    (35,451)    (21,223)    (101,455)
</TABLE>

                                       19
<PAGE>

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

<TABLE>
<CAPTION>
                                                                 2000
                                              -----------------------------------------
                                                First     Second     Third      Fourth
                                              --------   --------   --------   --------
(In thousands, except per share data)
<S>                                            <C>        <C>        <C>        <C>
Revenues...................................   $ 31,576   $ 31,857   $ 36,136   $ 50,763
Lease operating expenses...................      3,388      2,883      2,947      4,208
Production taxes...........................      2,195      2,026      2,457      3,950
General and administrative.................      1,639      1,755      1,646      2,011
Depletion, depreciation and amortization...     10,281      9,528      9,867     10,924
Net income.................................      9,194     10,613     13,439     19,195
Net income per share
 Basic.....................................       0.47       0.59       0.73       0.96
 Diluted...................................       0.40       0.46       0.57       0.86

Average daily production
 Oil (Bbl).................................      4,607      4,249      4,313      5,240
 Gas (Mcf).................................     89,502     87,564     90,390     98,202
 Equivalent Mcfe...........................    117,144    113,057    116,269    129,639

Average prices
 Oil (Bbl).................................   $  21.53   $  21.92   $  23.64   $  24.60
 Gas (Mcf).................................       2.73       2.90       3.16       4.24
 Equivalent Mcfe...........................       2.93       3.07       3.34       4.20

                                                                2001
                                              -----------------------------------------
                                                First     Second     Third      Fourth
                                              --------   --------   --------   --------
(In thousands, except per share data)
Revenues...................................   $ 64,452   $ 54,703   $ 47,457   $ 47,532
Lease operating expenses...................      6,535      6,213      6,246      6,362
Production taxes...........................      5,367      3,697      2,695      1,703
General and administrative.................      2,566      2,840      2,547      2,649
Depletion, depreciation and amortization...     11,901     11,840     12,159     14,016
Net income.................................     22,355     18,088     14,237      9,890
Net income per share
 Basic.....................................       1.14       0.86       0.67       0.47
 Diluted...................................       1.00       0.79       0.63       0.44

Average daily production
 Oil (Bbl).................................      7,421      7,189      6,933      7,621
 Gas (Mcf).................................    108,176    108,448    112,161    120,422
 Equivalent Mcfe...........................    152,702    151,580    153,761    166,150

Average prices
  Oil (Bbl).................................   $ 27.44   $  26.56   $  25.97   $  23.08
  Gas (Mcf).................................      4.65       3.63       2.97       2.81
  Equivalent Mcfe...........................      4.63       3.86       3.34       3.10
</TABLE>

   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.

                                       20
<PAGE>

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 operation are based upon consolidated financial statements, which have been
prepared in accordance with accounting principles generally adopted in the
United States.  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 analyzes its estimates,
including those related to oil and gas revenues, bad debts, oil and gas
properties, marketable securities, income taxes and contingencies and
litigation.  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.  Oil and gas properties are accounted for under the
successful efforts method of accounting and 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.

FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY

LIQUIDITY AND CAPITAL RESOURCES

   During 2001, the Company spent $77.8 million on the further development of
properties and $10.2 million on acquisitions.  The development expenditures
included $65.6 million in Wattenberg for the drilling or deepening of 61 J-Sand
wells, 323 Codell refracs, seven recompletions and the drilling of seven Codell
wells, $9.5 million on grassroots exploration and development and $2.7 million
on the Elysium properties.  These projects, the full year contribution of the
Elysium acquisition and the continued success in production enhancement allowed
production to increase 31% over the prior year.  The Company anticipates
incurring approximately $77.0 million on the further development of its
properties during 2002. The decision to increase or decrease development
activity is heavily dependent on the prices being received for production.

   At December 31, 2001, the Company had $453.6 million of assets.  Total
capitalization was $346.1 million, of which 78% was represented by stockholders'
equity and 22% by bank debt.  During 2001, net cash provided by operations
totaled $172.8 million, as compared to $109.4 million in 2000 ($148.5 million
and $108.5 million prior to changes in working capital, respectively).  At
December 31, 2001, there were no significant commitments for capital
expenditures. Based upon a $77.0 million capital budget for 2002, 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.

   During 2001, the Company repurchased 2,353,000 shares of its common stock for
$51.5 million. The Company received proceeds totaling approximately $36.0
million from the exercise of the $12.50 common stock warrants in May 2001.  The
warrants expired on May 2, 2001.

   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.

                                       21
<PAGE>

   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, 2001 and the effect such obligations are expected to have on its liquidity
and cash flow in future periods (in thousands):

<TABLE>
<CAPTION>
                                              Less than     1 - 3     After
                                              One Year     Years     3 Years    Total
                                              ---------   -------    -------   -------
<S>                                           <C>         <C>        <C>       <C>
   Long term debt.......................        $  -      $77,000*     $  -    $77,000
   Non-cancelable operating leases......         880        2,770       900      4,550
                                                ----      -------      ----    -------
   Total contractual cash obligations...        $880      $79,770      $900    $81,550
                                                ====      =======      ====    =======
</TABLE>
----------
   * Due at termination dates in each of the Company's credit facilities, which
   the Company expects to renew.

Banking

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

<TABLE>
<CAPTION>
                                          December 31, 2001
                                 -----------------------------------
                                 Borrowing
Revolving Credit Facilities        Base      Outstanding   Available
---------------------------      ---------   -----------   ---------
<S>                              <C>         <C>           <C>
   Patina.....................    $125,000       $71,000     $54,000
   Elysium (net to Patina)....      10,000         6,000       4,000
                                  --------       -------     -------
   Total......................    $135,000       $77,000     $58,000
                                  ========       =======     =======
</TABLE>

   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 $125.0 million
at December 31, 2001.  The borrowing base was reduced at Patina's election to
minimize commitment fees on the facility, as the additional availability was not
needed. Patina had $54.0 million available under the Credit Agreement at
December 31, 2001.  In the course of 2001, $100.0 million of debt was retired,
leaving $77.0 million of bank debt outstanding at year-end.  The debt reduction,
equity repurchases and capital expenditures were funded with internal cash flow,
$36.0 million in proceeds from the exercise of the $12.50 warrants, the sale of
Elysium's interest in the Lake Washington Field and the subsequent refinancing
of the Elysium loan.

   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. The weighted average interest rate under
the facility was 5.8% during 2001 and 3.1% at December 31, 2001.

   The Credit Agreement contains financial covenants, including but not limited
to a maximum total debt to EBITDA ratio 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. Borrowings under
the Credit Agreement mature in July 2003, but may be prepaid at anytime. The
Company has periodically extended the Credit Agreement; however, there is no
assurance it will be able to do so in the future.  The Company had a restricted
payment basket under the Credit Agreement of $39.9 million as of December 31,
2001, which may be used to repurchase equity securities, pay dividends or make
other restricted payments.

                                       22
<PAGE>

   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, 2001. Elysium had $8.0 million
available under the Elysium Credit Agreement at December 31, 2001.

   The Elysium facility is non-recourse to Patina and contains financial
covenants, including but not limited to a maximum total debt to EBITDA ratio, a
minimum current ratio and minimum tangible net worth. 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 6.8% during 2001 and 4.0% at December 31, 2001.

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
favorable hedging agreements for 2002, 2003, 2004 and 2005, respectively.  The
$88.1 million of capital expenditures for 2001 were funded entirely with
internal cash flow.  The 2002 capital budget of $77.0 million, comprised of
approximately $67.0 million of development expenditures in Wattenberg, is
expected to increase production by approximately 10%.  The Company expects the
capital program to be funded with internal cash flow, even in this lower price
environment.  As such, exclusive of any acquisitions or significant equity
repurchases, management expects to continue to reduce long-term debt in 2002.

     Net cash provided by operations in 1999, 2000 and 2001 was $49.7 million,
$109.4 million and $172.8 million, respectively.  Cash flow from operations
increased with the rise in oil and gas production combined with higher prices
and lower interest expense, more than offsetting the increases in lease
operating expenses, production taxes and general and administrative expenses.

     Net cash used by investing in 1999, 2000 and 2001 totaled $23.7 million,
$86.1 million and $73.7 million, respectively.  The 1999 expenditures were
primarily for development of properties in Wattenberg, totaling $21.1 million.
The increase in expenditures in 2000 was due largely to the purchase of Elysium
for $47.5 million and the increase in development expenditures in Wattenberg to
$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.

     Net cash used by financing in 1999, 2000 and 2001 was $35.5 million, $21.2
million and $101.5 million, respectively.  Sources of financing have been
primarily bank borrowings.  During 1999, as operating cash flow exceeded capital
expenditures, $10.0 million of bank debt was repaid and $24.6 million of common
and preferred stock was repurchased.  In 2000, the Company borrowed $45.0
million of bank debt.  These borrowing 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 $12.50 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.

                                       23
<PAGE>

Capital Requirements

     During 2001, $88.1 million of capital was expended, primarily on
development projects. This represented approximately 51% of internal cash flow.
The Company manages its capital budget with the goal of funding it with internal
cash flow. The 2002 capital budget of $77.0 million is expected to increase
production by approximately 10%. The Company expects the capital program to be
funded with internal cash flow, even in this lower price environment. As such,
exclusive of any acquisitions or significant equity repurchases, management
expects to continue to reduce long-term debt in 2002. 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 eighteen month basis.  Due to the exceptional
gas prices in 2001, the Company extended their hedging program into 2005.  At
December 31, 2001, hedges were in place covering 42.1 Bcf at prices averaging
$3.84 per MMBtu and 710,000 barrels of oil averaging $25.70 per barrel.  The
estimated fair value of the Company's hedge contracts, excluding hedge contracts
with Enron North America Corp. ("Enron"), that would be realized on termination,
approximated a net unrealized pre-tax gain of $52.0 million ($33.3 million gain
net of $18.7 million of deferred taxes) at December 31, 2001, which is presented
on the balance sheet as a short-term gain of $20.1 million and a long-term gain
of $31.9 million based on contract expiration.  The gas contracts expire monthly
through December 2005 and the oil contracts expire monthly through December
2002.  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 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 1999 and 2000 were $4.1 million, $23.9 million, respectively with
a pretax gain of $4.1 million in 2001.   Over the last three years, the Company
has recorded cumulative net pre-tax hedging losses of $23.9 million against
income, which, when combined with the $52.0 million unrealized pre-tax gain at
year-end 2001, results in a $28.1 million cumulative net gain.  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 as Other comprehensive income (loss), a component of
Stockholders' Equity.

                                       24
<PAGE>

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 2000
and 2001.  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.

<TABLE>
<CAPTION>
                                  Average Prices
                        -----------------------------------
                                     Natural    Equivalent
                           Oil         Gas          Mcf
                        ---------   ---------   -----------
                        (Per Bbl)   (Per Mcf)   (Per Mcfe)
<S>                     <C>         <C>         <C>
         Annual
         ------
         1997........     $19.54       $2.25         $2.55
         1998........      13.13        1.87          1.96
         1999........      17.71        2.21          2.40
         2000........      29.16        3.69          3.96
         2001........      24.99        3.42          3.63

         Quarterly
         ---------

         2000
         ----
         First.......     $27.30       $2.70         $3.13
         Second......      27.75        3.23          3.55
         Third.......      30.85        3.63          3.96
         Fourth......      30.53        5.03          5.05

         2001
         ----
         First.......     $27.86       $6.09         $5.67
         Second......      26.96        3.70          3.93
         Third.......      25.81        2.21          2.77
         Fourth......      19.69        1.94          2.31
</TABLE>

                                       25
<PAGE>

RESULTS OF OPERATIONS

    COMPARISON OF 2001 TO 2000.  Revenues for 2001 totaled $214.1 million, a 42%
increase over 2000. Net income for 2001 totaled $64.6 million compared to $52.4
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. Over the past year, 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 coalbed
methane play in Castlegate, Utah.  Based upon a $77.0 million development budget
for 2002, the Company expects production to continue to increase in the coming
year.

    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 and
production.

    General and administrative expenses in 2001, net of reimbursements, totaled
$10.6 million, an increase of $3.6 million or 50% 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.  This move should result in over
$500,000 of savings in 2002.  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.

    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 $36.3 million, an increase of
$20.5 million from the same period in 2000.  The increase was due to higher
earnings and utilization of the deferred tax asset in 2000.  The Company
recorded a 36% tax provision for 2001 compared to a 23% tax provision in 2000.

                                       26
<PAGE>

    COMPARISON OF 2000 TO 1999.  Revenues for 2000 totaled $150.3 million, a 64%
increase over 1999. Net income for 2000 totaled $52.4 million compared to $15.0
million in 1999. 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 2000 totaled 4,603 barrels and 91.4
MMcf (119.0 MMcfe), an increase of 11% on an equivalent basis from 1999.  During
2000, 60 wells were drilled or deepened and 193 refracs and nine recompletions
were performed in Wattenberg, compared to 36 new wells or deepenings and 113
refracs and three recompletions in 1999.

    Average oil prices increased 45% from $15.86 per barrel in 1999 to $23.00 in
2000. Average gas prices increased 50% from $2.18 per Mcf in 1999 to $3.28 in
2000. Average oil prices include hedging losses of $3.1 million or $1.85 per
barrel in 1999 and $10.4 million or $6.17 per barrel in 2000. Average gas prices
include hedging losses of $1.0 million or $0.03 per Mcf in 1999 and $13.5
million or $0.40 per Mcf in 2000.  Lease operating expenses totaled $13.4
million or $0.31 per Mcfe for 2000 compared to $11.9 million or $0.30 per Mcfe
in the prior year period. The increase in operating expenses was primarily
attributed to one month of operating expense associated with the Elysium
properties. Production taxes totaled $10.6 million or $0.24 per Mcfe for 2000
compared to $6.3 million or $0.16 per Mcfe in 1999.  The $4.3 million increase
was a result of higher average oil and gas prices and production.

    General and administrative expenses in 2000, net of reimbursements, totaled
$7.1 million, an increase of $866,000 or 14% from 1999. The increase was
primarily due to the Company receiving lower reimbursements from working
interest owners as a result of the Company acquiring various third party working
interests in its oil and gas properties in late 1999.  Included in general and
administrative expenses was $279,000 and $1.0 million for 2000 and 1999 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 $10.1 million in 2000, a decrease of
$727,000 or 7% from the prior year. Interest expense decreased as a result of
lower average debt balances and lower average interest rates on the Company's
debt due to the redemption of the 11.75% Subordinated Notes in July 1999. The
redemption was financed with borrowings under the bank credit facility. The
Company's average interest rate for 2000 was 7.7% compared to 8.1% in 1999.

    Depletion, depreciation and amortization expense for 2000 totaled $40.6
million, a decrease of $144,000 from 1999.  Depletion expense totaled $39.6
million or $0.91 per Mcfe for 2000 compared to $39.8 million or $1.01 per Mcfe
for 1999.  The decrease in depletion expense resulted primarily from a lower
depletion rate, partially offset by higher oil and gas production. The depletion
rate was lowered in the fourth quarter of 1999 and the second quarter of 2000 in
conjunction with the completion of the year-end 1999 and mid-year 2000 reserve
reports.  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.
Depreciation and amortization expense for 2000 totaled $987,000 compared to
$947,000 or $0.02 per Mcfe for both years.

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 2001,
exclusive of any hedges, ranged from a monthly low of $2.13 per Mcf to a monthly
high of $7.65 per Mcf.  Oil prices, exclusive of any hedges, ranged from a
monthly low of $18.76 per barrel to a monthly high of $28.87 per barrel during
2001.  Oil and natural gas prices have decreased significantly from late 2000
and early 2001 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.

                                       27
<PAGE>

   In 2001, a 10% reduction in oil and gas prices, excluding oil and gas
quantities that were fixed through hedging transactions, would have reduced
revenues by $8.1 million.  If oil and gas future prices at December 31, 2001 had
declined by 10%, the unrealized hedging gains at that date would have increased
by $12.8 million (from $52.0 million to $64.8 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 and the remaining discussion will relate exclusively to this
type of derivative instrument.

   The Company entered into various swap contracts for oil based on NYMEX
prices, recognizing losses of $3.1 million and $10.4 million in 1999 and 2000,
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 losses of $1.0 million and
$13.5 million in 1999 and 2000, respectively, and a gain of $2.1 million in
2001, related to these contracts.

   At December 31, 2001, the Company was a party to swap contracts for oil based
on NYMEX prices covering approximately 1,950 barrels of oil per day for 2002 at
fixed prices ranging from $23.11 to $27.32 per barrel.  These swaps are
summarized in the table below.  The overall weighted average hedged price for
the swap contracts is $25.70 per barrel for 2002. The unrecognized gains on
these contracts totaled $3.8 million based on NYMEX futures prices at December
31, 2001.

   At December 31, 2001, the Company was a party to swap contracts for natural
gas based on CIG index prices covering approximately 25,400 MMBtu's per day for
2002 at fixed prices ranging from $3.72 to $5.51 per MMBtu. The overall weighted
average hedged price for the swap contracts is $3.84 per MMBtu for 2002. The
Company also entered into natural gas swap contracts for 2003, 2004 and 2005 as
of December 31, 2001, which are summarized in the table below.  The unrecognized
gains on these contracts totaled $48.2 million based on CIG futures prices at
December 31, 2001.

At December 31, 2001, the Company was a party to the fixed price swaps
summarized below:

<TABLE>
<CAPTION>
                                  Oil Swaps (NYMEX)
                         -----------------------------------
                          Daily                 Unrealized
                          Volume                   Gain
Time Period                Bbl       $/Bbl     ($/thousands)
----------------------   ------   ----------   -------------
<S>                      <C>      <C>          <C>
01/01/02 - 03/31/02...    3,750      26.47        $ 2,150
04/01/02 - 06/30/02...    3,100      25.51          1,409
07/01/02 - 09/30/02...      500      23.65            139
10/01/02 - 12/31/02...      500      23.24            115

                           Natural Gas Swaps (CIG Index)
                         ----------------------------------
                          Daily                 Unrealized
                         Volume                    Gain
Time Period              MMBtu     $/MMBtu     ($/thousands)
----------------------   ------   ----------   ------------
01/01/02 - 03/31/02...   25,000       5.23        $ 6,966
04/01/02 - 06/30/02...   36,650       3.58          5,480
07/01/02 - 09/30/02...   25,000       3.12          2,579
10/01/02 - 12/31/02...   15,000       3.42          1,296

2003..................   30,000       3.78         11,896
2004..................   30,000       3.85         10,306
2005..................   30,000       3.90          9,671
</TABLE>

                                       28
<PAGE>

Interest Rate Risk

   At December 31, 2001, the Company had $71.0 million outstanding under its
credit facility with an average interest rate of 3.1% and $6.0 million (net to
Patina) outstanding under its Elysium credit facility with an average interest
rate of 4.0%.  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 5.8% and 6.8%, respectively
during 2001.  Assuming no change in the amount outstanding at December 31, 2001,
the annual impact on interest expense of a ten percent change in the average
interest rate would be approximately $300,000, net of tax.  As the interest rate
is variable and is reflective of current market conditions, the carrying value
approximates the fair value.


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.

    The Company's independent auditors, Arthur Andersen LLP, are engaged to
audit the financial statements and to express an opinion thereon.  Their audit
is conducted in accordance with generally accepted auditing standards to enable
them to report whether the financial statements present fairly, in all material
respects, the financial position and results of operations in accordance with
generally accepted accounting principles.


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

      None.

                                       29
<PAGE>

                                   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.  Each director was elected for a one-
year term at the Company's 2001 annual stockholders' meeting of stockholders.
Officers are appointed by the Board of Directors.

DIRECTORS AND EXECUTIVE OFFICERS

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

<TABLE>
<CAPTION>
            Name                Age                            Position
            ----                ---                            --------
<S>                             <C>   <C>
       Thomas J. Edelman.....    51   Chairman and Chief Executive Officer, Chairman of the Board
       Jay W. Decker.........    50   President and Director
       David J. Kornder......    41   Executive Vice President and Chief Financial Officer
       Andrew M. Ashby.......    46   Senior Vice President - Operations
       John M. Stafford......    45   Vice President and General Counsel
       Barton R. Brookman....    39   Vice President
       James A. Lillo........    47   Vice President
       Terry L. Ruby.........    43   Vice President
       David W. Siple........    42   Vice President
       Robert J. Clark.......    57   Director
       Elizabeth K. Lanier...    50   Director
       Alexander P. Lynch....    49   Director
       Paul M. Rady..........    48   Director
</TABLE>
--------------------

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

  JAY W. DECKER has served as President since March 1998 and as a Director since
1996. He had been 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, Mr. Decker was the President and Chief Executive
Officer of Consolidated Oil & Gas, Inc., a private independent oil company and
President of a predecessor company. Prior to 1989, Mr. Decker served as Vice
President - Operations for General Atlantic Energy Company and in various
capacities with Peppermill Oil Company, Wainoco Oil & Gas and Shell Oil Company.
Mr. Decker received his Bachelor of Science Degree in Petroleum Engineering from
the University of Wyoming.

  DAVID J. KORNDER has served as Executive Vice President and Chief Financial
Officer since 1996. Prior to that time, he served as Vice President - Finance of
Gerrity beginning in early 1993. From 1989 through 1992, Mr. Kornder was an
Assistant Vice President of Gillett Group Management, Inc.  Prior to that, Mr.
Kornder was an accountant with the independent accounting firm of Deloitte &
Touche 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.

                                       30
<PAGE>

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

  JOHN M. STAFFORD has served as Vice President and General Counsel since
February 2001.  From 1998 to January 2001, Mr. Stafford was an attorney with
Holme Roberts and Owen, LLP. Mr. Stafford worked as an attorney for Holland &
Hart, LLP from 1997 to 1998 and for Michael Best & Friedrich, LLP from 1996 to
1997. Prior to becoming an attorney, he was a Senior Geologist with ARCO Oil and
Gas Company from 1982 to 1993.  Mr. Stafford received his Bachelor of Science
Degree in Geology from Syracuse University, his Master of Science Degree in
Geological Oceanography from Texas A&M University and his Juris Doctorate Degree
from the University of Denver.  From 1999 to 2001, Mr. Stafford served as an ex-
officio Director of the Association of International Petroleum Negotiators.

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

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

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

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

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

                                       31
<PAGE>

  ELIZABETH K. LANIER has served as a Director since 1998.  Effective April
2002, Mrs. Lanier will be the Senior Vice President, General Counsel of
TrizecHahn Corporation, a public real estate investment trust. Mrs. Lanier
served as Vice President and General Counsel of General Electric Power Systems
from 1998 until March 2002.  From 1996 to 1998, Mrs. Lanier served as Vice
President and Chief of Staff of Cinergy Corp.  Mrs. 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.  Mrs. Lanier was awarded
an Honorary Doctorate of Technical Letters by Cincinnati Technical College and
an Honorary Doctorate of Letters from the College of Mt. St. Joseph.  From 1982
to 1984 she was an associate with Frost & Jacobs, a law firm in Cincinnati, Ohio
and a partner from 1984 to 1996.  From 1977 to 1982 she was with the law firm of
Davis Polk & Wardwell in New York City.  She is past Chair of the Ohio Board of
Regents.

  ALEXANDER P. LYNCH has served as a Director since 1996. Mr. Lynch has been a
Managing Director of J.P. Morgan & Company, 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. RADY has served as a Director since April 2001. 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.

  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.

                                       32
<PAGE>

ITEM 11.  COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS

     Information with respect to officers' compensation is incorporated herein
by reference to the Company's 2002 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 2002 Proxy
Statement.


ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     None.


                                 PART IV
                                 -------

ITEM 14.  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 items listed on the accompanying index to exhibits are filed as
          part of this Annual Report on Form 10-K.

     (b)  Reports on Form 8-K.

          None.

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

          Exhibits required to be filed pursuant to Item 601 of Regulation S-K
          are contained in Exhibits listed in response to Item 14 (a)3, and are
          incorporated herein by reference.

     (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.

                                       33
<PAGE>

                                   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.

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 reentry 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.

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 the wholesale money markets in the City of London.
This rate is a yardstick for lenders involved in high value transactions.

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

Mcf. One thousand cubic feet.

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

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

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

MMcf.  One million cubic feet.

MMcfe.  One million cubic feet of natural gas equivalents.

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

                                       34
<PAGE>

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 rues 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.

                                       35
<PAGE>

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                                         Page
                                                                                         ----
<S>                                                                                      <C>
PATINA OIL & GAS CORPORATION

 Report of Independent Public Accountants.............................................   F-2

 Consolidated Balance Sheets as of December 31, 2000 and 2001.........................   F-3

 Consolidated Statements of Operations for the years ended
  December 31, 1999, 2000 and 2001....................................................   F-4

 Consolidated Statements of Changes in Stockholders' Equity and Other Comprehensive
  Income for the years ended December 31, 1999, 2000 and 2001.........................   F-5

 Consolidated Statements of Cash Flows for the years ended
  December 31, 1999, 2000 and 2001....................................................   F-6

 Notes to Consolidated Financial Statements...........................................   F-7

</TABLE>

                                      F-1
<PAGE>

                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders of
Patina Oil & Gas Corporation:

We have audited the accompanying consolidated balance sheets of Patina Oil & Gas
Corporation (a Delaware corporation) and subsidiaries as of December 31, 2000
and 2001, and the related consolidated statements of operations, changes in
stockholders' equity and other comprehensive income and cash flows for each of
the three years in the period ended December 31, 2001.  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.  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 financial statements referred to above present fairly, in
all material respects, the financial position of Patina Oil & Gas Corporation
and subsidiaries as of December 31, 2000 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.

As explained 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.



Denver, Colorado,                         ARTHUR ANDERSEN LLP
February 25, 2002

                                      F-2
<PAGE>

                          PATINA OIL & GAS CORPORATION

                          CONSOLIDATED BALANCE SHEETS
                        (IN THOUSANDS EXCEPT SHARE DATA)
<TABLE>
<CAPTION>

                                                           December 31,
                                                      -----------------------
                                                          2000         2001
                                                      ----------   ----------
<S>                                                    <C>          <C>
                                  ASSETS
Current assets
 Cash and equivalents                                  $   2,653    $     250
 Accounts receivable                                      31,830       16,407
 Inventory and other                                       4,885        3,880
 Unrealized hedging gains                                      -       20,134
                                                       ---------    ---------
                                                          39,368       40,671
                                                       ---------    ---------
Unrealized hedging gains                                       -       31,872

Oil and gas properties, successful efforts method        709,248      780,224
 Accumulated depletion                                  (353,344)    (402,213)
                                                       ---------    ---------
                                                         355,904       378,011
                                                       ---------    ---------

Field equipment and other                                  4,580        6,605
 Accumulated depreciation                                 (3,098)      (3,844)
                                                       ---------    ---------
                                                           1,482        2,761
                                                       ---------    ---------

Other assets, net                                         24,500          258
                                                       ---------    ---------
                                                        $421,254    $ 453,573
                                                       =========    =========

                     LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
 Accounts payable                                      $  23,073    $  27,380
 Income taxes payable                                          -        6,918
 Accrued liabilities                                       7,794       10,767
                                                       ---------    ---------
                                                          30,867       45,065
                                                       ---------    ---------

Senior debt                                              177,000       77,000
Deferred income taxes                                     15,776       43,473
Other noncurrent liabilities                              21,165       18,891

Commitments and contingencies

Stockholders' equity
 Preferred Stock, $.01 par, 5,000,000 shares
  authorized, -0- shares issued
  and outstanding                                              -            -
 Common Stock, $.01 par, 100,000,000 shares
  authorized, 20,043,859 and 21,241,958 shares
  issued and outstanding                                     200          212
 Capital in excess of par value                          151,392      145,715
 Retained earnings                                        24,854       85,856
 Other comprehensive income                                    -       37,361
                                                       ---------    ---------
                                                         176,446      269,144
                                                       ---------    ---------
                                                        $421,254    $ 453,573
                                                       =========    =========
</TABLE>

       The accompanying notes are an integral part of these statements.

                                      F-3
<PAGE>

                          PATINA OIL & GAS CORPORATION

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


<TABLE>
<CAPTION>

                                                 Year Ended December 31,
                                             --------------------------------
                                               1999        2000         2001
                                             --------    --------     -------
<S>                                          <C>         <C>          <C>
Revenues
   Oil and gas sales                          $90,407    $148,665     $211,271
   Other                                        1,164       1,667        2,873
                                              -------    --------     --------
                                               91,571     150,332      214,144
                                              -------    --------     --------
Expenses
   Lease operating                             11,902      13,426       25,356
   Production taxes                             6,271      10,628       13,462
   Exploration                                    666         293          513
   General and administrative                   6,185       7,051       10,602
   Interest and other                          10,844      10,117        7,034
   Impairment of oil and gas hedges                 -           -        6,370
   Depletion, depreciation and amortization    40,744      40,600       49,916
                                              -------    --------     --------
                                               76,612      82,115      113,253
                                              -------    --------     --------
 Pretax income                                 14,959      68,217      100,891
                                              -------    --------     --------
 Provision for income taxes
   Current                                          -           -       11,466
   Deferred                                         -      15,776       24,855
                                              -------    --------     --------
                                                    -      15,776       36,321
                                              -------    --------     --------
 Net income                                   $14,959    $ 52,441     $ 64,570
                                              =======    ========     ========
 Net income per common share
   Basic                                      $  0.52    $   2.81     $   3.10
                                              =======    ========     ========
   Diluted                                    $  0.50    $   2.28     $   2.88
                                              =======    ========     ========
 Weighted average shares outstanding
   Basic                                       15,972      17,553       20,834
                                              =======    ========     ========
   Diluted                                     16,471      22,707       22,402
                                              =======    ========     ========
</TABLE>

       The accompanying notes are an integral part of these statements.

                                      F-4
<PAGE>

                          PATINA OIL & GAS CORPORATION

                     CONSOLIDATED STATEMENTS OF CHANGES IN
              STOCKHOLDERS' EQUITY AND OTHER COMPREHENSIVE INCOME
                                 (In thousands)

<TABLE>
<CAPTION>
                                                                       Capital                                 Other
                                 Preferred Stock      Common Stock       in                     Retained   Comprehensive
                                ----------------   ----------------   Excess of    Deferred      Earnings      Income
                                Shares   Amount    Shares   Amount    Par Value  Compensation   (Deficit)      (Loss)        Total
                                -------  -------   -------  -------   ---------  -------------  ---------  --------------  ---------
<S>                             <C>      <C>       <C>      <C>       <C>        <C>            <C>        <C>             <C>
Balance, December 31, 1998       3,167     $ 32    15,752     $158    $206,792        $(1,038)  $(29,968)       $      -   $175,976

Repurchase of common and
 preferred                        (735)      (7)     (868)      (9)    (24,674)             -       (489)              -    (25,179)

Conversion of preferred into
 common                           (168)      (2)      489        4           -              -          -               -          2

Issuance of common                   -        -       758        8       3,108           (334)         -               -      2,782

Dividends                          119        1         -        -       3,319              -     (7,063)              -     (3,743)

Net income                           -        -         -        -           -          1,093     14,959               -     16,052
                                ------   ------    ------     ----    --------   ------------   --------   -------------   --------
Balance, December 31, 1999       2,383       24    16,131      161     188,545           (279)   (22,561)              -    165,890

Repurchase of common and
 preferred                        (514)      (5)   (1,638)     (16)    (41,575)             -       (549)              -    (42,145)

Conversion of preferred into
 common                         (1,869)     (19)    4,934       49         (31)             -          -               -         (1)

Issuance of common                   -        -       617        6       4,453              -          -               -      4,459

Dividends                            -        -         -        -           -              -     (4,477)              -     (4,477)

Net income                           -        -         -        -           -            279     52,441               -     52,720
                                ------   ------    ------     ----    --------   ------------   --------   -------------   --------
Balance, December 31, 2000           -        -    20,044      200     151,392              -     24,854               -    176,446

Repurchase of common and
 warrants                            -        -    (2,353)     (23)    (51,451)             -          -               -    (51,474)

Issuance of common                   -        -       673        6       7,663              -          -               -      7,669

Conversion of warrants               -        -     2,878       29      35,946              -          -               -     35,975

Tax benefit from stock
 options                             -        -         -        -       2,165              -          -               -      2,165

Dividends                            -        -         -        -           -              -     (3,568)              -     (3,568)

Comprehensive income:
Net income                           -        -         -        -           -              -     64,570               -     64,570
Cumulative effect of
 accounting
 change, net of tax                  -        -         -        -           -              -          -         (25,077)   (25,077)
Contract settlements
 reclassed to income                 -        -         -        -           -              -          -             822        822
Impairment of oil and gas
 hedges,
 net of tax                          -        -         -        -           -              -          -           4,077      4,077
Change in unrealized hedging
 gains                               -        -         -        -           -              -          -          57,539     57,539
                                ------   ------    ------     ----    --------   ------------   --------   -------------   --------
Total comprehensive income           -        -         -        -           -              -     64,570          37,361    101,931
                                ------   ------    ------     ----    --------   ------------   --------   -------------   --------
Balance, December 31, 2001           -     $  -    21,242     $212    $145,715        $     -   $ 85,856        $ 37,361   $269,144
                                ======   ======    ======     ====    ========   ============   ========   =============   ========
</TABLE>


       The accompanying notes are an integral part of these statements.

                                      F-5
<PAGE>

                          PATINA OIL & GAS CORPORATION

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (In thousands)

<TABLE>
<CAPTION>
                                                                              Year Ended December 31,
                                                                    -----------------------------------------
                                                                      1999           2000             2001
                                                                    --------       --------        ----------
<S>                                                                 <C>            <C>             <C>
 Operating activities
   Net income                                                        $ 14,959       $ 52,441        $  64,570
   Adjustments to reconcile net income to net
     cash provided by operations
        Exploration expense                                               666           293               513
        Depletion, depreciation and amortization                       40,744        40,600            49,916
        Deferred income taxes                                               -        15,776            24,855
        Tax benefit from stock options                                      -             -             2,165
        Impairment of oil and gas hedges                                    -             -             6,370
        Deferred compensation expense                                   1,046           279                 -
        Amortization of deferred credits and other                     (1,059)         (906)              113
        Changes in current and other assets and liabilities
          Decrease (increase) in
             Accounts receivable                                       (5,741)      (13,068)           15,423
             Inventory and other                                         (180)         (432)              828
          Increase (decrease) in
             Accounts payable                                          (1,833)        7,492             4,313
             Income taxes payable                                           -             -            (2,623)
             Accrued liabilities                                       (2,412)          334             3,123
             Other assets and liabilities                               3,470         6,575             3,211
                                                                     --------      --------          --------
        Net cash provided by operations                                49,660       109,384           172,777
                                                                     --------      --------          --------
 Investing activities
   Acquisition, development and exploration                           (24,003)      (89,304)          (88,086)
   Disposition of oil and gas properties                                    -             -            16,468
   Other                                                                  334         3,170            (2,107)
                                                                     --------      --------         ---------
        Net cash used by investing                                    (23,669)      (86,134)          (73,725)
                                                                     --------      --------         ---------
 Financing activities
   Increase (decrease) in indebtedness                                (10,021)       45,000          (100,000)
   Repayment from (loan to) affiliate                                       -       (24,500)           24,500
   Deferred credits                                                     2,087         1,446           (13,209)
   Loan origination fees                                                 (455)            -              (169)
   Issuance of common stock                                             2,040         3,568            42,465
   Repurchase of common stock and warrants                             (6,582)      (28,750)          (51,474)
   Repurchase of preferred stock                                      (18,106)      (12,846)                -
   Preferred stock redemption premium                                    (489)         (549)                -
   Preferred dividends                                                 (3,113)       (2,776)                -
   Common dividends                                                      (812)       (1,816)           (3,568)
                                                                     --------      --------         ---------
        Net cash used by financing                                    (35,451)      (21,223)         (101,455)
                                                                     --------      --------         ---------
 Increase (decrease) in cash                                           (9,460)        2,027            (2,403)
 Cash and equivalents, beginning of period                             10,086           626             2,653
                                                                     --------      --------         ---------
 Cash and equivalents, end of period                                 $    626      $  2,653         $     250
                                                                     ========      ========         =========
</TABLE>

       The accompanying notes are an integral part of these statements.

                                      F-6
<PAGE>

                          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 14.0 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 Note (9). The accompanying consolidated financial statements were
prepared on a proportionate consolidation basis, including Patina's 50% interest
in Elysium's assets, liabilities, revenues and expenses. 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 year, 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. Through
Elysium 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 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 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 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, 2001.  No accrual has been provided for the
Wattenberg properties, as management believes that salvage value will
approximate abandonment costs.

   The Company follows the provisions of Statement of Financial Accounting
Standards No. 121 ("SFAS 121"), "Accounting for the Impairment 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.  When the
net book value of properties exceeds the undiscounted future cash flows, the
cost of the property is written down to "fair value," which is determined using
the discounted future cash flows on a field-by field basis. In 1997, the Company
recorded an impairment of $26.0 million to oil and gas properties as the
estimated undiscounted future cash flows expected to result from these assets
and their disposition, largely proven undeveloped drilling locations, was less
than their net book value. The impairment primarily resulted from low year-end
oil and gas prices.  While no impairments have been necessary since 1997,
changes in underlying assumptions or the amortization units could result in
impairments in the future.

                                      F-7
<PAGE>

Field equipment and other

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

Other Assets

   At December 31, 2000, Other Assets was comprised of $24.5 million advance to
Elysium by Patina.  In May 2001, Elysium entered into a credit facility with a
third party bank.  The proceeds from this facility were used to repay Patina.
At December 31, 2001, the balance represented net loan origination fees related
to the credit facility Elysium entered into in May 2001.  See Note (9).

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. As the Company's profitability now allows it to utilize tax credits,
they were reacquired in March 2001.  The Company recorded additional gas
revenues of $2.9 million, $3.5 million and $600,000 during 1999, 2000 and 2001,
respectively.  Subsequent to the repurchase of the tax credits, the Company
generated approximately $6.0 million in tax credits, for utilization against the
Company's current tax provision.

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,
2000 and 2001 were insignificant.

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 other comprehensive income and related tax effects for the twelve
months ended December 31, 2001 were as follows (in thousands):

<TABLE>
<CAPTION>

                                                            Tax       Net of
                                               Gross      Effect        Tax
                                             ---------   ---------   ---------
<S>                                          <C>         <C>         <C>
Cumulative effect of accounting change....   $(39,183)   $ 14,106    $(25,077)
Change in fair value of hedges............     89,905     (32,366)     57,539
Impairment of oil and gas hedging swaps...      6,370      (2,293)      4,077
Contract settlements during the year......      1,284        (462)        822
                                             --------    --------    --------
                                             $ 58,376    $(21,015)   $ 37,361
                                             ========    ========    ========
</TABLE>

   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 $0.18 (fully diluted). In
accordance with generally accepted accounting principles, the Company will
record additional non-cash revenues of an identical amount in the course of
2002, as these hedges would have expired.

                                      F-8
<PAGE>

   The Company has received a written offer of $0.25 on the dollar
(approximately $1.7 million) to sell its Enron bankruptcy claims to a third
party.  While the Company has no immediate plans to accept this offer, should
management determine that acceptance of this or a similar offer provides the
Company with the best opportunity to monetize its Enron bankruptcy claims, the
Company will recognize additional earnings at that time.

   The following table schedules out the reversal of the impairment related to
the Enron hedges recorded in other comprehensive income at December 31, 2001 and
how it will impact earnings by quarter in 2002 (in thousands):

<TABLE>
<CAPTION>

                    Reported     Tax      Reported
    2002            Revenues   Impact     Earnings
   ------           --------   -------    --------
<S>                 <C>        <C>        <C>
First quarter....     $3,568   $(1,284)     $2,284
Second quarter...         88       (32)         56
Third quarter....      1,749      (630)      1,119
Fourth quarter...        965      (347)        618
                      ------   -------      ------
                      $6,370   $(2,293)     $4,077
                      ======   =======      ======
</TABLE>

The write-off of the Enron hedges in the fourth quarter of 2001 and the
subsequent reversal into income in 2002 have no ultimate economic impact on the
financial statements.

Financial Instruments

   The book value and estimated fair value of cash and equivalents was $2.7
million and $250,000 at December 31, 2000 and 2001, respectively.  The book
value and estimated fair value of the senior debt was $177.0 million and $77.0
million at December 31, 2000 and 2001, 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 and the remaining discussion will relate exclusively to this
type of derivative instrument.

   The Company entered into various swap contracts for oil based on NYMEX
prices, recognizing losses of $3.1 million and $10.4 million in 1999 and 2000,
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 losses of $1.0 million and
$13.5 million in 1999 and 2000, respectively, and a gain of $2.1 million in
2001, related to these contracts.

   At December 31, 2001, the Company was a party to swap contracts for oil based
on NYMEX prices covering approximately 1,950 barrels of oil per day for 2002 at
fixed prices ranging from $23.11 to $27.32 per barrel. These swaps are
summarized in the table below. The overall weighted average hedged price for the
swap contracts is $25.70 per barrel for 2002. The unrecognized gains on these
contracts totaled $3.8 million based on NYMEX futures prices at December 31,
2001.

                                      F-9
<PAGE>

   At December 31, 2001, the Company was a party to swap contracts for natural
gas based on CIG index prices covering approximately 25,400 MMBtu's per day for
2002 at fixed prices ranging from $3.72 to $5.51 per MMBtu. The overall weighted
average hedged price for the swap contracts is $3.84 per MMBtu for 2002. The
Company also entered into natural gas swap contracts for 2003, 2004 and 2005 as
of December 31, 2001, which are summarized in the table below.  The unrecognized
gains on these contracts totaled $48.2 million based on CIG futures prices at
December 31, 2001.

   At December 31, 2001, the Company was a party to the fixed price swaps
summarized below:

<TABLE>
<CAPTION>

                                  Oil Swaps (NYMEX)
                         -----------------------------------
                         Daily                   Unrealized
                         Volume                     Gain
Time Period               Bbl       $/Bbl      ($/thousands)
-----------              ------   ----------   -------------
<S>                      <C>      <C>          <C>
01/01/02 - 03/31/02...    3,750        26.47        $ 2,150
04/01/02 - 06/30/02...    3,100        25.51          1,409
07/01/02 - 09/30/02...      500        23.65            139
10/01/02 - 12/31/02...      500        23.24            115

                           Natural Gas Swaps (CIG Index)
                         -----------------------------------
                         Daily                  Unrealized
                         Volume                    Gain
Time Period              MMBtu     $/MMBtu     ($/thousands)
-----------              ------   ----------   ------------
01/01/02 - 03/31/02...   25,000         5.23        $ 6,966
04/01/02 - 06/30/02...   36,650         3.58          5,480
07/01/02 - 09/30/02...   25,000         3.12          2,579
10/01/02 - 12/31/02...   15,000         3.42          1,296

2003..................   30,000         3.78         11,896
2004..................   30,000         3.85         10,306
2005..................   30,000         3.90          9,671
</TABLE>

   The Company follows SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," 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.  The Company adopted SFAS No. 133 on January 1,
2001.

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

<TABLE>
<CAPTION>
                                                                                      Amount
                                                                                      -------
<S>                                                                                   <C>
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 (other comprehensive loss)...   $(25.1)
                                                                                      ======
</TABLE>

                                      F-10
<PAGE>

    During 2001 (excluding the impairment related to the Enron hedges), net
hedging gains of $1.3 million ($822,000 after tax) were transferred from other
comprehensive income to earnings and the change 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. As of December 31, 2001 (excluding the
impaired Enron hedges), the Company had net unrealized hedging gains of $52.0
million ($33.3 million after tax), comprised of $20.1 million of current assets
and $31.9 million of non-current assets.  The Company expects to reclassify as
an increase to earnings during the next twelve months $20.1 million ($12.9
million after tax) of net unrealized hedging gains to other comprehensive income
based on estimated futures prices at December 31, 2001.

   In October 1998, the Company entered into an interest rate swap contract for
a two-year period.  The contract was for $30.0 million principal with a fixed
interest rate of 4.57% payable by the Company and the variable interest rate,
the three-month LIBOR, payable by the third party. The difference between the
fixed rate and the LIBOR rate was reset and received or paid by the Company in
arrears every 90 days. The Company received $184,000 in 1999 and $422,000 in
2000 pursuant to this contract, which expired in October 2000.

Stock Options and Awards

   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." Accordingly, stock options
awarded under the Employee Plan and the non-employee Directors Plan are
considered to be "noncompensatory" and 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 $1.0 million and $279,000 of non-cash general and administrative
expenses in 1999 and 2000, respectively.  No costs were incurred in 2001 as
these costs were fully amortized in 2000.  See Note (6).

Per Share Data

   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 (5)

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:

<TABLE>
<CAPTION>

                                                       Year Ended December 31,
                                                       -----------------------
                                                         1999    2000    2001
                                                        ------  ------  ------
<S>                                                     <C>      <C>     <C>
Stock grant..........................................   $  335   $   -   $  -
Stock Purchase Plan..................................       53      89    261
Dividends and accretion - 8.50% preferred stock......    3,321       -      -
401(k) profit sharing contribution in common stock...      483     589    647
</TABLE>

                                      F-11
<PAGE>

   The 1999 stock grant represents 100,000 common shares, along with 300,000
stock options, granted to the Chief Executive Officer in conjunction with his
voluntary reduction in cash salary, waiver of any 1998 bonus and other
compensation arrangements in the second quarter of 1999.  The Company recognized
$1.0 million and $279,000 of non-cash general and administrative expenses for
1999 and 2000, respectively, related to these stock grants and the stock grants
awarded to officers and managers in conjunction with the redistribution of
SOCO's ownership of the Company. See Note (9).

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
generally accepted accounting principles 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 June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations," which addresses financial accounting and
reporting for business combinations.  SFAS No. 141 is effective for all business
combinations initiated after June 30, 2001.  The adoption of SFAS No. 141 is not
expected to have a material impact on the Company's financial position or
results of operations.

   In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets," which addresses, among other things, the financial accounting and
reporting for goodwill subsequent to an acquisition.  The new standard
eliminates the requirement to amortize acquired goodwill; instead, such goodwill
shall be reviewed at least annually for impairment.  SFAS No. 142 is effective
for fiscal years beginning after December 15, 2001.  The adoption of SFAS No.
142 is not expected to have a material impact on the Company's financial
position or results of operations.

   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 fiscal years
beginning June 15, 2002.  The Company has not yet determined the impact of
adoption of this statement.

   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 Company does not anticipate that the adoption of the statement will
have a material effect on the Company's financial position or results of
operations.

                                      F-12
<PAGE>

(3)  OIL AND GAS PROPERTIES

   The cost of oil and gas properties at December 31, 2000 and 2001 included
approximately $1.1 million and $4.8 million, respectively, in net unevaluated
leasehold costs for acreage that is generally held for exploration or
development to which proved reserves have not been assigned. These amounts have
been excluded from amortization during the respective period. In addition, $2.5
million of costs incurred on our grassroots projects at December 31, 2001 have
been excluded from amortization, as no determination had been made as to the
extent of proved oil and gas reserves.  The Company estimates that these costs
will begin to be amortized in the first quarter of 2002 as production has been
established. The following table sets forth costs incurred related to oil and
gas properties:

<TABLE>
<CAPTION>
                                              1999       2000      2001
                                             -------   -------   --------
                                                 (In thousands, except
                                                   per Mcfe amounts)
<S>                                          <C>       <C>       <C>
Development...............................   $21,122   $39,996   $ 77,343
Acquisition - evaluated...................     2,215    47,886      6,603
Acquisition - unevaluated.................         -     1,129      3,627
Exploration and other.....................       666       293        513
                                             -------   -------   --------
                                             $24,003   $89,304    $88,086
                                             =======   =======    =======
Disposition of properties.................   $     -   $     -   $(16,468)
                                             =======   =======    =======
Depletion rate (per Mcfe).................   $  1.01     $0.91   $   0.86
                                             =======   =======   ========
</TABLE>

   The disposition of properties 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.

(4)  INDEBTEDNESS

   The following indebtedness was outstanding on the respective dates:

<TABLE>
<CAPTION>
                                                DECEMBER 31,
                                            --------------------
                                               2000       2001
                                            ---------   --------
                                             (In thousands)
<S>                                     <C>              <C>
      Bank facility - Patina.........        $177,000    $71,000
      Bank facility - Elysium, net...               -      6,000
      Less current portion...........               -          -
                                             --------    -------
      Senior debt, net...............        $177,000    $77,000
                                             ========    =======
</TABLE>

   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 $125.0 million
at December 31, 2001.  Patina had $54.0 million available under the Credit
Agreement at December 31, 2001.

   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. The weighted average interest rate under
the facility was 5.8% during 2001 and 3.1% at December 31, 2001.

                                      F-13
<PAGE>

   The Credit Agreement contains financial covenants, including but not limited
to a maximum total debt to EBITDA ratio 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. Borrowings under
the Credit Agreement mature in July 2003, but may be prepaid at anytime. The
Company has periodically extended the Credit Agreement; however, there is no
assurance it will be able to do so in the future.  The Company had a restricted
payment basket under the Credit Agreement of $39.9 million as of December 31,
2001, which may be used to repurchase equity securities, pay dividends or make
other restricted payments.

   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, 2001. Elysium had $8.0 million
available under the Elysium Credit Agreement at December 31, 2001.

   The Elysium facility is non-recourse to Patina and contains financial
covenants, including but not limited to a maximum total debt to EBITDA ratio, a
minimum current ratio and minimum tangible net worth. 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 6.8% during 2001 and 4.0% at December 31, 2001.

   Scheduled maturities of indebtedness for the next five years are zero in
2002, $71.0 million in 2003 and $6.0 million in 2004. 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 $14.3 million, $10.0 million and $7.2 million during 1999, 2000 and
2001, respectively.

                                      F-14
<PAGE>

(5)  STOCKHOLDERS' EQUITY

   A total of 100,000,000 common shares, $0.01 par value, are authorized of
which 21,241,958 were issued and outstanding at December 31, 2001. The common
stock is listed on the New York Stock Exchange.  Prior to December 1997, no
dividends had been paid on common stock.  A quarterly cash dividend of $0.01 per
common share was initiated in December 1997, increased to $0.02 per share in the
fourth quarter of 1999, to $0.04 per share in the fourth quarter of 2000 and to
$0.05 per share in the fourth quarter of 2001.  The Company has a stockholders'
rights plan designed to insure 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, 1999:

<TABLE>
<CAPTION>
                                             1999          2000          2001
                                          ----------    ----------    ----------
<S>                                       <C>           <C>           <C>
Beginning shares.......................   15,752,400    16,131,300    20,043,900

Exercise of stock options..............      226,300       249,300       436,300
Issued under Stock Purchase Plan.......       92,900        52,400        98,000
Issued in lieu of salaries & bonuses...      164,800       128,300        67,900
Issued for directors fees..............        8,600         2,800         1,500
Conversion of 7.125% preferred.........      488,800       148,000             -
Conversion of 8.50% preferred..........            -     4,785,600             -
Exercise of $12.50 warrants............            -         2,400     2,878,000
Issued to deferred compensation plan...       35,200        13,700        11,900
Vesting of stock grant.................      168,600       138,600        33,300
Contributed to 401(k) plan.............       61,300        29,600        24,200
                                          ----------    ----------    ----------
Total shares issued....................    1,246,500     5,550,700     3,551,100

Repurchases............................     (867,600)   (1,638,100)   (2,353,000)
                                          ----------    ----------    ----------
Ending shares..........................   16,131,300    20,043,900    21,242,000
                                          ==========    ==========    ==========
</TABLE>

   During 1999, 2000 and 2001, the Company repurchased and retired shares of its
common stock for $6.6 million, $28.8 million and $51.5 million, respectively.

   During 2001, 2,878,000 $12.50 warrants were converted into common stock with
the Company receiving cash proceeds of $36.0 million.  The remaining warrants
expired on May 2, 2001.

   A total of 5,000,000 preferred shares, $0.01 par value, are authorized with
no shares issued and outstanding at December 31, 2001.

   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
148,000 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 $2.7 million and $600,000 in preferred
dividends during 1999 and 2000, respectively.  Included in the $2.7 million and
$600,000 of preferred stock dividends paid in 1999 and 2000 was $489,000 and
$549,000 of redemption premiums paid to shareholders that elected to redeem
their preferred stock for cash in the fourth quarter of 1999 and 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
4.8 million shares of common stock, including more than 500,000 shares of common
stock issued upon conversion in June 2000.  The Company paid $3.7 million and
$2.6 million in preferred dividends during 1999 and 2000, respectively.
Preferred dividends through October 1999 were paid in kind. As such, the Company
issued 119,577 of additional 8.50% preferred shares as dividends in 1999.

                                      F-15
<PAGE>

   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):

<TABLE>
<CAPTION>

                                                                       YEAR ENDED DECEMBER 31,
                                     --------------------------------------------------------------------------------------
                                                 1999                           2000                         2001
                                     ---------------------------    --------------------------   --------------------------
                                       NET      COMMON     PER        NET     COMMON     PER       NET     COMMON    PER
                                      INCOME    SHARES    SHARE     INCOME    SHARES    SHARE    INCOME    SHARES    SHARE
                                     -------    ------   -------    -------   ------   -------   -------   ------   -------
<S>                                  <C>        <C>      <C>        <C>       <C>      <C>       <C>       <C>      <C>
Net income                           $14,959    15,972             $52,441     17,553            $64,570    20,834
7.125% preferred dividends            (2,681)        -                (600)         -                  -         -
8.50% preferred dividends             (3,727)        -              (2,610)         -                  -         -
Preferred stock accretion               (331)        -                   -          -                  -         -
                                     -------    ------             -------     ------            -------    ------
Basic net income attributable
 to common stock                       8,220    15,972   $  0.52    49,231     17,553  $  2.81    64,570    20,834   $3.10
                                                         =======                       =======                       =====

Effect of dilutive securities:
7.125% preferred stock                     -         -                   -          -                  -         -
8.50% preferred stock                      -         -               2,610      3,242                  -         -
Stock options                              -       222                   -      1,111                  -     1,080
Stock grant                                -       277                   -        131                  -         7
$12.50 common stock warrants               -         -                   -        670                  -       481
                                     -------    ------             -------    -------            -------    ------
Diluted net income attributable
 to common stock                     $ 8,220    16,471   $  0.50   $51,841     22,707  $  2.28   $64,570    22,402   $2.88
                                     =======    ======   =======   =======    =======  =======   =======    ======   =====
</TABLE>

   The potential common stock equivalents related to the 7.125% and 8.50%
preferred stock, and $12.50 common stock warrants were anti-dilutive in 1999.


(6)  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 $483,000, $589,000 and $647,000 for 1999, 2000 and 2001, respectively. The
contributions were made in common stock.  A total of 61,300, 29,600 and 24,200
common shares were contributed in 1999, 2000 and 2001, 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 eligible 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 500,000 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 500,000 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 1999, the Board
of Directors approved 136,300 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, 1999, participants had
purchased 92,900 shares of

                                      F-16
<PAGE>

common stock at an average price of $5.67 per share ($4.25 net price per share),
resulting in cash proceeds to the Company of $395,000. In 2000, the Board of
Directors approved 116,300 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 138,200 shares of common stock, including 85,800 shares purchased with
participants' 1999 bonuses, at an average price of $12.12 per share ($9.09 net
price per share), resulting in cash proceeds to the Company of $665,000. In
2001, the Board of Directors approved 121,300 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 98,000 shares of common stock at an average price of
$26.66 per share ($19.99 net price per share), resulting in cash proceeds to the
Company of $2.0 million. The Company recorded non-cash general and
administrative expenses of $53,000, $89,000 and $261,000 associated with these
purchases for 1999, 2000 and 2001, 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.  Options to acquire the greater of three 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:

<TABLE>
<CAPTION>
                                                 Weighted
                                    Range        Average
                     Options     of Exercise     Exercise
Year                 Granted       Prices         Price
----                 -------   ---------------   --------
<S>                  <C>       <C>               <C>
1999..............   630,000   $ 2.94 - $ 9.13     $ 3.54
2000..............   505,000   $ 9.19 - $21.94     $ 9.34
2001..............   634,000   $22.61 - $33.03     $22.91
</TABLE>

   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 8,600 shares were issued in 1999, 2,800 were issued in 2000 and 1,500
in 2001.  It also provides for 5,000 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:

<TABLE>
<CAPTION>
                                                 Weighted
                                    Range        Average
                     Options     of Exercise     Exercise
Year                 Granted       Prices         Price
----                 -------   ---------------   --------
<S>                  <C>       <C>               <C>
1999..............    30,000   $ 2.94 - $ 5.13     $ 4.76
2000..............    25,000       $17.44          $17.44
2001..............    25,000   $24.59 - $32.85     $31.20
</TABLE>

   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 equity
section of the accompanying consolidated balance sheets.  The Management
Investors simultaneously purchased additional common shares from the Company at
$9.875 per share.  A portion of the purchase was financed by the Company, all of
which was repaid in January 2001. See Note (9). In conjunction with his
appointment in March 1998, the Company's President was granted 100,000
restricted common shares that vested 33% per year in March 1999, 2000 and

                                      F-17
<PAGE>

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 100,000 common shares from the
Company at $6.875 per share. A portion of this purchase ($584,000) was financed
by the Company. As approved by the Board of Directors, the President sold 50,000
common shares to the Company at $23.50 per share in March 2001, utilizing a
portion of these proceeds to repay his note. See Note (9). In April 1999, the
Chief Executive Officer was granted 100,000 restricted shares of common stock
and 300,000 stock options in consideration of his voluntary reduction in cash
salary, waiver of any 1998 bonus and other compensation arrangements. The shares
vested ratably throughout 1999. The Company recognized $1.0 million and $279,000
of non-cash general and administrative expenses for 1999 and 2000 with respect
to these stock grants.

   At December 31, 2001, 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.  Accordingly, 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:

<TABLE>
<CAPTION>
                                                      1999      2000      2001
                                                    -------   -------   -------
<S>                                   <C>           <C>       <C>       <C>
Net income                            As Reported   $14,959   $52,441   $64,570
                                      Pro forma      13,954    50,948    62,118

Basic net income per common share     As Reported   $  0.52   $  2.81   $  3.10
                                      Pro forma        0.45      2.72      2.98

Diluted net income per common share   As Reported   $  0.50   $  2.28   $  2.88
                                      Pro forma        0.44      2.24      2.77
</TABLE>

   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 1999, 2000 and 2001: dividend yield of 1%, 1% and
1%; expected volatility of 47%, 49% and 48%; risk-free interest rate of 5.2%,
6.6% and 4.7%; and expected life of 4.5 years, 4.0 years and 3.6 years,
respectively.

   A summary of the status of the Company's stock option plans as of December
31, 1999, 2000 and 2001 and changes during the years are presented below:

<TABLE>
<CAPTION>
                                                  1999                         2000                       2001
                                          ----------------------   --------------------------   -------------------------
                                                       Weighted                     Weighted                    Weighted
                                                       Average                       Average                     Average
                                                       Exercise                     Exercise                    Exercise
                                           Shares       Price         Shares          Price       Shares          Price
                                          ---------    --------   -------------     ---------   -----------   ------------
<S>                                       <C>          <C>        <C>               <C>         <C>            <C>
Outstanding at beginning of year.....     1,526,000      $8.07       1,740,000        $6.59      2,011,000        $ 7.29
Granted..............................       660,000       3.60         530,000         9.73        658,000         23.23
Exercised............................      (226,000)      6.43        (249,000)        7.53       (436,000)         7.40
Forfeited............................      (220,000)      8.05         (10,000)        9.06        (32,000)        11.82
                                          ---------                  ---------                  ----------
Outstanding at end of year...........     1,740,000      $6.59       2,011,000        $7.29      2,201,000        $11.97
                                          =========                  =========                  ==========
Options exercisable at year-end......       747,000                    902,000                     965,000
                                          =========                  =========                  ==========
Weighted-average fair value of
 options granted during the year.....                    $1.48                        $4.24                       $ 8.97
</TABLE>


                                      F-18
<PAGE>

   The following table summarizes information about stock options outstanding at
December 31, 2001:

<TABLE>
<CAPTION>
                                       Options Outstanding                      Options Exercisable
                            -------------------------------------------     ---------------------------
                               Number                                          Number
                             Outstanding    Weighted-Avg.    Weighted-       Exercisable     Weighted-
                                 at          Remaining        Average            at           Average
                            December 31,    Contractual      Exercise        December 31,    Exercise
Exercise Price                  2001           Life            Price            2001           Price
--------------               ----------    ------------     -----------      ------------    ---------
<S>                           <C>          <C>             <C>                  <C>          <C>
$2.94    to    7.06......     740,000       1.9 years         $  4.63           511,000       $  5.12
 7.19    to    9.88......     785,000       2.1 years            9.36           449,000          9.49
11.25    to   33.03......     676,000       4.2 years           23.03             5,000         17.98
                            ---------                                           -------
$2.94    to   33.03......   2,201,000       2.7 years         $ 11.97           965,000       $  7.22
                            =========                                           =======
</TABLE>


(7)  FEDERAL 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, 1999,
2000 and 2001 follows:

<TABLE>
<CAPTION>
                                                                1999     2000     2001
                                                                ----     ----     ----
<S>                                                             <C>      <C>      <C>
Federal statutory rate.......................................     35%      35%     35%
State income tax rate, net of federal benefit................      -        3%      3%
Decrease in valuation allowance against deferred tax asset...    (35%)    (12%)
Section 29 tax credits.......................................      -        -      (2%)
Revision of prior estimates..................................      -       (3%)      -
                                                                ----     ----      --
Effective income tax rate....................................      -       23%     36%
                                                                ====     ====      ==
</TABLE>

    At December 31, 2001, $7.2 million of taxes related to unrealized hedging
gains were included in current income taxes payable. For book purposes the
components of the net deferred tax asset and liability at December 31, 2000 and
2001 were:

<TABLE>
<CAPTION>
                                                                   2000        2001
                                                               --------    --------
                                                                  (In thousands)
<S>                                                            <C>         <C>
Deferred tax assets
 NOL carry forwards and percentage depletion carry forward...  $ 18,603    $ 16,442
 Deferred deductions and other..............................      1,721       6,692
                                                               --------    --------
                                                                 20,324      23,134
                                                               --------    --------
Deferred tax liabilities
 Taxes relating to unrealized hedging gains.................          -     (11,474)
 Depreciable and depletable property........................    (36,100)    (55,133)
                                                               --------    --------
                                                                (36,100)    (66,607)
                                                               --------    --------
Net deferred tax liability..................................   $(15,776)   $(43,473)
                                                               ========    ========
</TABLE>

   For tax purposes, the Company had regular net operating loss carryforwards of
approximately $41.0 million and alternative minimum tax ("AMT") loss
carryforwards of approximately $26.6 million at December 31, 2001. Utilization
of $30.3 million of the regular net operating loss carryforwards will be limited
to approximately $4.7 million per year as a result of the Gerrity acquisition in
1996.  These carryforwards expire from 2010 through 2018.  At December 31, 2001,
the Company had AMT credit carryforwards of $4.1 million that are available
indefinitely.  No cash payments were made by the Company for federal taxes
during 1999 and 2000.  The Company paid $11.1 million in federal taxes during
2001.

                                      F-19
<PAGE>

(8)  MAJOR CUSTOMERS

   During 1999, 2000 and 2001, Duke Energy Field Services, Inc. accounted for
37%, 32% and 29%, BP Amoco Production Company accounted for 24%, 19% and 13%,
E-Prime accounted for 4%, 8%, and 10%, of revenues, 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.


(9)  RELATED PARTY

   In October 1997, certain officers and managers purchased common shares at
$9.875 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 100,000 shares of common stock at $6.875 per share
and was granted 100,000 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 50,000 common shares to the Company at $23.50 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 is scheduled for annual principal reductions each
March, with payment in full due in 2004.  In May 2001, a director purchased
10,000 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 is due May 2004 and is represented by a 7.50% recourse promissory note.

   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 and $850,000 for these services in 2000
and 2001, 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 has entered into a management agreement with
Elysium providing for an indirect monthly reimbursement of $243,000 and any
direct charges for providing this service.


(10) COMMITMENTS AND CONTINGENCIES

   The Company leases office space and certain equipment under non-cancelable
operating leases.  Future minimum lease payments under such leases approximate
$900,000 per year from 2002 through 2005.

   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 on the deductibility of
gathering and transportation costs as to royalty interests has resulted in
uncertainty of these deductions. The Company has not been named as a party to
any related lawsuit and no determination has been made as to the financial
impact to the Company, if any, in the event this decision stands.

                                      F-20
<PAGE>

(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

   Netherland, Sewell & Associates, Inc., independent petroleum consultants,
audited the Company's total proved reserves at December 31, 1999, 2000 and 2001.
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, and estimates of other engineers might differ materially from those
shown below.  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

<TABLE>
<CAPTION>
                                                     OIL        NATURAL GAS
                                                -------------  -------------
                                                    (MBBL)        (MMCF)
<S>                                            <C>             <C>
   Balance, December 31, 1998...............         14,240        286,595
    Revisions...............................          1,665         18,498
    Extensions, discoveries and additions...          3,006         66,191
    Production..............................         (1,653)       (29,477)
    Purchases...............................            202         20,425
    Sales...................................            (40)          (971)
                                                     ------        -------
   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
                                                     ======        =======
</TABLE>

                                      F-21
<PAGE>

PROVED DEVELOPED RESERVES

<TABLE>
<CAPTION>
                                                      OIL        NATURAL GAS
                                                    -------      -----------
                                                     (MBbl)        (MMcf)
<S>                                                 <C>          <C>

December 31, 1998...........................         13,655        244,736
                                                     ======        =======
December 31, 1999...........................         16,633        307,560
                                                     ======        =======
December 31, 2000...........................         35,146        409,103
                                                     ======        =======
December 31, 2001...........................         28,220        430,487
                                                     ======        =======
</TABLE>

STANDARDIZED MEASURE

<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                 ----------------------------------------
                                                    1999          2000           2001
                                                 ----------    -----------    -----------
                                                              (In thousands)
<S>                                              <C>           <C>            <C>
Future cash inflows.........................     $1,273,591    $ 5,427,152    $ 1,868,209
Future costs
 Production.................................       (323,859)      (848,093)      (486,526)
 Development................................       (126,978)      (412,672)      (379,474)
                                                 ----------    -----------    -----------
Future net cash flows.......................        822,754      4,166,387      1,002,209
Undiscounted income taxes...................       (192,956)    (1,478,535)      (279,461)
                                                 ----------    -----------    -----------
After tax net cash flows....................        629,798      2,687,852        722,748
10% discount factor.........................       (267,270)    (1,248,907)      (331,809)
                                                 ----------    -----------    -----------
Standardized measure........................     $  362,528    $ 1,438,945    $   390,939
                                                 ==========    ===========    ===========
Pretax Standardized measure (SEC PV10)......     $  457,542    $ 2,217,825    $   527,184
                                                 ==========    ===========    ===========
</TABLE>

CHANGES IN STANDARDIZED MEASURE

<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                  ---------------------------------------
                                                    1999          2000           2001
                                                 ----------    -----------    -----------
                                                              (In thousands)
<S>                                              <C>           <C>            <C>
Standardized measure, beginning of year.....     $  205,404    $   362,528    $ 1,438,945
Revisions:
  Prices and costs..........................        188,474      1,026,518     (1,820,512)
  Quantities................................          3,642          1,927          9,303
  Development costs.........................         (3,003)        (6,170)       (31,998)
  Accretion of discount.....................         20,540         36,253        221,782
  Income taxes..............................        (75,287)      (683,866)       642,635
  Production rates and other................         (6,299)         2,149         23,470
                                                 ----------    -----------    -----------
  Net revisions.............................        128,067        376,811       (955,320)
Extensions, discoveries and additions.......         64,048        659,094         25,259
Production..................................        (72,234)      (124,611)      (172,454)
Future development costs incurred...........         21,122         39,996         77,343
Purchases (a)...............................         17,026        128,376          9,241
Sales (b)...................................           (905)        (3,249)       (32,075)
                                                 ----------    -----------    -----------
Standardized measure, end of year...........     $  362,528    $ 1,438,945    $   390,939
                                                 ==========    ===========    ===========
</TABLE>
----------
(a)  "Purchases" includes the present value at the end of the period acquired
     during the year plus cash flow received on such properties during the
     period, rather than their estimated present value at the time of the
     acquisition.
(b)  "Sales" represents the present value at the beginning of the period of
     properties sold, less the cash flow received on such properties during the
     period.

                                      F-22
<PAGE>

                                    PART IV

ITEM 14.  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 items listed on the accompanying index to exhibits are filed as
          part of this Annual Report on Form 10-K.

(b)       Reports on Form 8-K.

          No reports on Form 8-K were filed by Registrant during the quarter
          ended December 31, 2001.

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

          Exhibits required to be filed pursuant to Item 601 of Regulation S-K
          are contained in Exhibits listed in response to Item 14 (a)3, and are
          incorporated herein by reference.

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

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

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

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

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

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

10.1.1    Second Amended and Restated Credit Agreement dated July 15, 1999
          by and among the Company, as Borrower, and Chase Bank of Texas,
          National Association, as Administrative Agent, Bank of America, N.A.,
          as Syndication Agent, Bank One, Texas, N.A., as Documentation and
          certain commercial lending institutions. (Incorporated herein by
          reference to Exhibit 10.1 of the Company's Form 10-Q for the quarter
          ended June 30, 1999)

                                      F-23
<PAGE>

10.1.2    First Amendment to the Second Amended and Restated Credit Agreement
          dated July 15, 1999 by and among the Company, as Borrower, and Chase
          Bank of Texas, National Association, as Administrative Agent, Bank of
          America, N.A., as Syndication Agent, Bank One, Texas, N.A., as
          Documentation and certain commercial lending institutions.
          (Incorporated herein by reference to Exhibit 10.1.2 of the Company's
          Form 10-K for the year ended December 31, 1999)

10.1.3    Second Amendment to the Second Amended and Restated Credit Agreement
          dated July 15, 1999 by and among the Company, as Borrower, and Chase
          Bank of Texas, National Association, as Administrative Agent, Bank of
          America, N.A., as Syndication Agent, Bank One, Texas, N.A., as
          Documentation and certain commercial lending institutions.
          (Incorporated herein by reference to Exhibit 10.1.2 of the Company's
          Form 10-K for the year ended December 31, 1999)

10.1.4    Third Amendment to the Second Amended and Restated Credit Agreement
          dated July 15, 1999 by and among the Company, as Borrower, and Chase
          Bank of Texas, National Association, as Administrative Agent, Bank of
          America, N.A., as Syndication Agent, Bank One, Texas, N.A., as
          Documentation and certain commercial lending institutions.
          (Incorporated herein by reference to Exhibit 10.1 of the Company's
          Form 10-Q for the quarter ended June 30, 2000)

10.1.5    Fourth Amendment to the Second Amended and Restated Credit Agreement
          dated July 15, 1999 by and among the Company, as Borrower, and Chase
          Bank of Texas, National Association, as Administrative Agent, Bank of
          America, N.A., as Syndication Agent, Bank One, Texas, N.A., as
          Documentation and certain commercial lending institutions.
          (Incorporated herein by reference to Exhibit 10.1.5 of the Company's
          Form 10-K for the year ended December 31, 2000)

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

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

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

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

10.4.3    Patina 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))

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

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

                                      F-24
<PAGE>

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

10.7      Standstill 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)

10.8      First Amended and Restated Operating Agreement of Elysium Energy,
          L.L.C., a New York limited liability company, dated November 27, 2000.
          (Incorporated herein by reference to Exhibit 10.13 of the Company's
          Form 10-K for the year ended December 31, 2000)

23.1      Consent of independent public accountants. *


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

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

----------
* Filed herewith

                                      F-25
<PAGE>

                                    SIGNATURES


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


/s/ Thomas J. Edelman        Chairman and Chairman of the Board   March 5, 2002
----------------------       (Principal Executive Officer)
Thomas J. Edelman


/s/ Jay W. Decker            President and Director               March 5, 2002
----------------------
Jay W. Decker


/s/ David J. Kornder         Executive Vice President and         March 5, 2002
----------------------       Chief Financial Officer
David J. Kornder


/s/ Robert J. Clark          Director                             March 5, 2002
-----------------------
Robert J. Clark


/s/ Elizabeth K. Lanier      Director                             March 5, 2002
------------------------
Elizabeth K. Lanier


/s/ Alexander P. Lynch       Director                             March 5, 2002
------------------------
Alexander P. Lynch


/s/ Paul M. Rady             Director                             March 5, 2002
------------------------
Paul M. Rady

                                      F-26