<PAGE>

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

                      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, 2000

                                      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

 Title of each class                  Name of each exchange on which registered
---------------------------------     -----------------------------------------
Common Stock, $.01 par value                       New York Stock Exchange
  Common Stock Warrants                            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 12,928,000 shares of voting stock
held by non-affiliates of the registrant, based upon the closing sale price of
the common stock on March 8, 2001 of $25.95 per share as reported on the New
York Stock Exchange, was $335,482,000. 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 7, 2001, the registrant had 19,373,195 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,
2001.

================================================================================
<PAGE>

                         PATINA OIL & GAS CORPORATION

                          Annual Report on Form 10-K
                               December 31, 2000

                                    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" or the
"Field") 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 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 $12.50 warrants will expire on May 2, 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 year-end. 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, the San Joaquin Basin
of California, and the Lake Washington Field of Louisiana. Approximately 90% of
Elysium's production is oil.

       At December 31, 2000, the Company had 777.8 Bcfe of proved reserves, of
which Wattenberg represented 704.8 Bcfe or 91%. The reserves had an estimated
pretax present value of $2.2 billion based on unescalated prices and costs in
effect on that date. Approximately 67% of the reserves on a Mcf equivalent basis
were natural gas and over 84% 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, 2000, the Company's inventory of proven development projects
included 563 drilling or deepening locations, 291 recompletions and 1,849
restimulation ("refrac") projects in Wattenberg. During 2000, the Company's
production averaged 119.0 MMcfe per day, of which 117.7 MMcfe per day or 99% was
attributed to Wattenberg. Based on year-end reserves and calculating production
as if Elysium had been acquired in January 2000, the Company had a reserve life
index of 14.5 years.

                                       2
<PAGE>

       From inception, the Company has focused on consolidating ownership of its
properties, developing an efficient organization, reducing costs and improving
operations. In 2000, revenues and net cash provided from operations totaled
$150.3 million and $109.4 million, respectively. This operating cash flow,
combined with $45.0 million of bank borrowings, funded $40.3 million of capital
expenditures, $21.0 million to acquire 50% of Elysium and $42.1 million of
equity repurchases. In addition, the Company loaned $53.0 million to Elysium, an
amount that was reduced to $49.0 million by year-end. Capital expenditures
funded the drilling or deepening of 57 J-Sand wells, performing 193 refracs,
nine recompletions and drilling three Codell wells in Wattenberg. These
projects, the Elysium purchase and continued success in production enhancement
allowed production to increase 11% over the prior year. Total proved reserves
increased 67% or 312 Bcfe, with 270 Bcfe gained through ongoing Wattenberg
development, acquisitions net of sales adding 70 Bcfe (largely the Elysium
transaction) and upward revisions due to higher prices contributing 16 Bcfe.

       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. These projects, the still to be realized
potential of the Elysium acquisition and continued success in production
enhancement should result in additional increases in production and proved
reserves in 2001.

       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. The Company is actively accumulating acreage in preparation for
launching two grassroots drilling projects in the Rockies, which could have
significant long-term potential.


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>

Production, Revenue and Price History

       The following table sets forth information regarding oil and natural 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 Gerrity in May 1996 and the
acquisition of 50% of Elysium in November 2000.

<TABLE>
<CAPTION>
                                                                           Year Ended December 31,
                                                       --------------------------------------------------------------
                                                          1996         1997         1998         1999         2000
                                                       ---------     --------     --------     ---------    ---------
                                                       (Dollars in thousands, except prices and per Mcfe information)
<S>                                                    <C>           <C>          <C>          <C>          <C>
Production
     Oil (MBbl).....................................       1,688        1,889        1,699         1,653        1,685
     Gas (MMcf).....................................      23,947       26,863       25,522        29,477       33,463
     MMcfe (a)......................................      34,074       38,194       35,715        39,396       43,572

Revenues
     Oil     .......................................   $  34,541     $ 37,197     $ 22,583     $  26,218   $   38,741
     Gas (b) .......................................      47,644       62,342       49,594        64,189      109,924
                                                       ---------     --------     --------     ---------   ----------
         Subtotal...................................      82,185       99,539       72,177        90,407      148,665
     Other   .......................................       1,003          794        2,533         1,164        1,667
                                                       ---------     --------     --------     ---------   ----------
         Total......................................      83,188      100,333       74,710        91,571      150,332
                                                       ---------     --------     --------     ---------   ----------

Direct operating expenses
     Lease operating expenses.......................       8,866       11,735       12,399        11,902       13,426
     Production taxes...............................       5,653        7,055        4,941         6,271       10,628
                                                       ---------     --------     --------     ---------   ----------
         Total......................................      14,519       18,790       17,340        18,173       24,054
                                                       ---------     --------     --------     ---------   ----------

Direct operating margin.............................   $  68,669     $ 81,543     $ 57,370     $  73,398     $126,278
                                                       =========     ========     ========     =========     ========

Average sales price
     Oil (Bbl)......................................   $   20.47     $  19.70     $  13.29      $  15.86      $ 23.00
     Gas (Mcf) (b)..................................        1.99         2.32         1.94          2.18         3.28
     Mcfe (a).......................................        2.41         2.61         2.02          2.29         3.41

Lease operating expense per Mcfe....................   $    0.26     $   0.31     $   0.35      $   0.30      $  0.31
Production tax expense per Mcfe.....................        0.17         0.18         0.14          0.16         0.24
                                                       ---------     --------         ----      --------      -------
Direct operating expense per Mcfe...................        0.43         0.49         0.49          0.46         0.55

Production margin per Mcfe..........................   $    1.99     $   2.12        $1.54      $   1.83      $  2.86
</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>

Marketing

       The Company's oil and natural 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 natural gas can be affected by a number of factors that are beyond the
Company's control and which cannot be accurately predicted. However, the Company
does not believe the loss of any single customer would have a long-term material
adverse effect on its operations.

       Natural Gas. Wattenberg natural gas 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 natural 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 HS Gathering, LLC
("HSG") 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.

Competition

        The oil and natural 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 natural 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 natural 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 natural 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.

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
natural 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 natural 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.

                                       5
<PAGE>

       In the past, the federal government has regulated the prices at which oil
and natural gas could be sold. Prices of oil and natural 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 natural gas resources, protection of the correlative rights of oil
and natural 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 natural 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
natural gas regulations. These ordinances increase the involvement of local
governments in the permitting of oil and natural gas operations, and require
additional restrictions or conditions on the conduct of operations so as to
reduce their impact on the surrounding community. Accordingly, these local
ordinances have the potential to delay and increase the cost of drilling,
refracing and recompletion operations.

       Environmental 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 natural 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 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.

                                       6
<PAGE>

Office and Operations Facilities

       The Company leases its principal executive offices at 1625 Broadway,
Denver, Colorado 80202. The lease covers approximately 29,000 square feet and
expires in November 2005. The monthly rent is approximately $43,000, increasing
to approximately $60,000 in December 2001. The Company owns a 6,000 square foot
production facility in Platteville, Colorado used to support its Wattenberg
Field operations.

       Elysium leases its principal executive offices at 10077 Grogans Mill
Road, The Woodlands, Texas 77380. The lease covers approximately 20,000 square
feet of office space and expires in November 2001. The monthly rent is
approximately $31,000 ($15,500 net to Patina). Elysium maintains six field
offices in the areas of its operations.

Employees

       On December 31, 2000, the Company had 160 employees, including 97 that
work in its field office. An additional 139 employees work for Elysium. None of
these employees are represented by a labor union. The Company believes its
relationship with its employees is satisfactory.

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......................    50     Chairman of the Board and Chief Executive Officer
              Jay W. Decker..........................    49     President and Director
              David J. Kornder.......................    40     Executive  Vice   President and Chief Financial Officer
              John M. Stafford.......................    44     Vice President and General Counsel
              Barton R. Brookman.....................    38     Vice President
              James A. Lillo.........................    46     Vice President
              Terry L. Ruby..........................    42     Vice President
              David W. Siple.........................    41     Vice President
              Christopher C. Behrens.................    40     Director
              Robert J. Clark........................    56     Director
              Elizabeth K. Lanier....................    49     Director
              Alexander P. Lynch.....................    48     Director
</TABLE>

 --------------------

     Thomas J. Edelman founded the Company and has served as Chairman of the
Board 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 Paw Energy LLC, and is a Director of Star
Gas Corporation and Wellogix, Inc.

     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. Mr. Decker also serves as a Director of FX Energy.

                                       7
<PAGE>

     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.

     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. Mr. Stafford also serves 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.

     Christopher C. Behrens has served as a Director since 1999. Mr. Behrens has
been a general partner at J.P. Morgan Partners (formerly Chase Capital Partners)
since 1999 and a principal since 1994. Prior to assuming that position, Mr.
Behrens was a Vice President in the Chase Manhattan Corporation's Merchant
Banking Group. He received his Bachelor of Arts from the University of
California at Berkeley and his M.B.A. from Columbia University. Mr. Behrens also
serves as a Director of Portola Packaging, Carrizo Oil and Gas, Domino's Pizza,
PDI, as well as other private companies, including Bear Paw Energy LLC.

                                       8
<PAGE>

     Robert J. Clark has served as a Director since 1996. Mr. Clark is the
President of Bear Paw Energy LLC, a private gas gathering and processing
company. Mr. Clark formed a predecessor company, Bear Paw Energy Inc., in 1995.
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.

     Elizabeth K. Lanier has served as a Director since 1998. Mrs. Lanier has
served as Vice President and General Counsel of General Electric Power Systems
since 1998. 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 immediate 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.

ITEM 2.   PROPERTIES

General

       The Company's reserves are 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 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 Colorado Oil & Gas Commission 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 the Field can now be drilled, produced and
commingled from any or all of ten "drilling windows" on a 320 acre parcel.

       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 substantially
increase proved reserves in 2000.

                                       9
<PAGE>

       During 2000, the Company drilled or deepened 57 wells to the J-Sand or
Dakota formation. The cost of drilling and completing a J-Sand well approximates
$320,000 while a completed deepening within an existing wellbore costs roughly
$230,000. 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 natural gas prices. Finding and development costs for the J-
Sand and Dakota drilling and deepening projects for 2000 averaged $0.70 per Mcfe
with projected rates of return in excess of over 150% at current commodity
prices. At December 31, 2000, the Company had 289 proven J-Sand drilling
locations or deepening projects in inventory.

       The Company performed 193 Codell refracs during 2000. The refrac program
continues to be focused primarily on the Codell formation. A typical refrac
costs approximately $124,000. The finding and development costs associated with
the 2000 refrac program averaged $0.67 per Mcfe with projected rates of return
in excess of 200% at current commodity prices. At December 31, 2000, the Company
had over 1,800 proven refrac projects. Given the exceptional results of the
refrac program, the budgeted activity has been increased to over 270 refrac
projects in 2001.

       The Company also recompleted nine wells in 2000. The Company has an
additional 291 proven recompletion opportunities at December 31, 2000. During
2000, tubing was installed in 16 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 2000
capital development program and helped fuel continued increases in the Company's
production. The Company estimates it had over 500 of these minor projects in
inventory at year-end 2000.

       At December 31, 2000, the Company had working interests in approximately
3,321 gross (3,202 net) producing oil and natural gas wells in the D-J Basin. As
of December 31, 2000 estimated proved reserves totaled 704.8 Bcfe, including
31.4 million barrels of oil and 516.2 Bcf of gas.

       In November 2000, Patina acquired various property interests out of a
bankruptcy proceeding 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, the San Joaquin Field in California, and the Lake
Washington Field of Louisiana. The Elysium properties primarily produce oil.
Patina's working interests in the Elysium properties consisted of 2,610 gross
(1,239 net) producing oil and gas wells. As of December 31, 2000, Patina's 50%
share of Elysium's estimated proved reserves totaled 73.0 Bcfe, including 11.3
million barrels of oil and 5.3 Bcf of gas.

Proved Reserves

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

<TABLE>
<CAPTION>
                                                                                        December 31,
                                                                         --------------------------------------------
                                                                           1998              1999             2000
                                                                         ---------        ---------         ---------
                <S>                                                      <C>              <C>               <C>
                Oil (MBbl)
                         Developed.....................................     13,655           16,633            35,146
                         Undeveloped...................................        585              787             7,568
                                                                         ---------        ---------         ---------
                                 Total.................................     14,240           17,420            42,714
                                                                         =========        =========         =========

                Natural gas (MMcf)
                         Developed.....................................    244,736          307,560           409,103
                         Undeveloped...................................     41,859           53,701           112,447
                                                                         ---------        ---------         ---------
                                 Total.................................    286,595          361,261           521,550
                                                                         =========        =========         =========

                Total MMcfe............................................    372,035          465,781           777,831
                                                                         =========        =========         =========
</TABLE>

                                       10
<PAGE>

       The following table sets forth the estimated pretax future net revenues
as of year-end 2000 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 $62.6 million of future development
costs in 2001.

<TABLE>
<CAPTION>
                                                                                       December 31, 2000
                                                                        ------------------------------------------------
                                                                         Developed          Undeveloped          Total
                                                                         ---------          -----------      -----------
                                                                                          (In thousands)
<S>                                                                    <C>                  <C>             <C>
Future Net Revenues
                2001...............................................    $    292,991         $     5,012     $    298,003
                2002 ..............................................         281,695              33,542          315,237
                2003 ..............................................         276,068              46,435          322,503
                Remainder..........................................       2,514,386             716,258        3,230,644
                                                                       ------------         -----------     ------------
                     Total.........................................    $  3,365,140         $   801,247     $  4,166,387
                                                                       ============         ===========     ============

                Pretax PW 10% Value (a)............................    $  1,854,364         $   363,461     $  2,217,825
                                                                       ============         ===========     ============
</TABLE>

 ------------------

(a)    The after tax present value discounted at 10% of the proved reserves
       totaled $1,438.9 million at year-end 2000. If the reserve estimates were
       made with future prices in affect at December 31, 2000 resulting in
       average wellhead prices of $3.57 per Mcf and $20.70 per barrel over the
       life of the properties, the pretax PW10% value of the reserves would have
       exceeded $925.0 million.

       The Wattenberg field represents 95% of the pre-tax PW10% value and 704.8
Bcfe or 91% of Patina's proved reserves.

       The quantities and values in the preceding tables are based on constant
prices in effect at December 31, 2000, which averaged $26.07 per barrel of oil
and $8.27 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.

       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 average oil and natural gas prices in effect on December 31, 2000.
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.

                                       11
<PAGE>

       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 natural 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 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 natural gas reserves and future revenues as of
December 31, 2000 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.

Producing Wells

       The following table sets forth the producing wells in which the Company
owned a working interest at December 31, 2000. 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........................................................................     2,986             2,841
        Natural gas ...............................................................       395               361
                                                                                     --------           -------
                    Total..........................................................     3,381             3,202
                                                                                     ========           =======

        Elysium
        -------
        Oil........................................................................     2,591             1,231
        Natural gas ...............................................................        19                 8
                                                                                     --------           -------
                    Total..........................................................     2,610             1,239
                                                                                     ========           =======

        Total
        -----
        Oil........................................................................     5,577             4,072
        Natural gas ...............................................................       414               369
                                                                                     --------           -------
                    Total..........................................................     5,991             4,441
                                                                                     ========           =======
</TABLE>

        The Company had 174 wells (166 net) and 1,275 wells (603 net) shut in
the Wattenberg and the Elysium properties at December 31, 2000, respectively.
The Company's average working interest in the Wattenberg wells was approximately
95%, while the average working interest in the Elysium wells was approximately
47%.

                                       12
<PAGE>

Drilling Results

       The following table sets forth the number of wells drilled or deepened by
the Company during the past three years. All the wells were development wells
and drilled in the Wattenberg. 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>
                                                                                1998           1999            2000
                                                                                ----           ----            ----
        <S>                                                                     <C>            <C>             <C>
        Productive
               Gross.........................................................   36.0           36.0            60.0
               Net...........................................................   36.0           35.0            59.0

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

        At December 31, 2000 no development wells were in progress.

Acreage

       The following table sets forth the leasehold acreage held by the Company
at December 31, 2000. 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>
       Colorado...........................       196,000      177,000           67,000          58,000
       Illinois *.........................        46,000       19,000            8,000           4,000
       Kansas *...........................         6,000        3,000           11,000           5,000
       Louisiana / Texas *................        35,000       11,000           32,000           7,000
       California *.......................        14,000        7,000            2,000           1,000
       Other..............................             -            -           16,000          16,000
                                               ---------    ---------         --------       ---------
       Total..............................       297,000      217,000          136,000          91,000
                                               =========    =========         ========       =========
</TABLE>

       * - Patina's 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

       None.

                                       13
<PAGE>

                                    PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SECURITY HOLDER
         MATTERS

       The Company's Common Stock and $12.50 Warrants are listed on the New York
Stock Exchange ("NYSE") under the symbols "POG" and "POGWT", respectively. Prior
to the redemption, the Company's 7.125% Preferred Stock was listed on the NYSE
under the symbol "POGPr". All remaining shares of the 7.125% Preferred Stock
were redeemed in January 2000. The Company's 8.50% Preferred Stock was privately
placed and did not trade publicly. All remaining shares of the 8.50% preferred
stock were converted into Common Stock in September 2000. The $12.50 Warrants
will expire on May 2, 2001. The following table sets forth the range of high and
low closing prices as reported on the NYSE Composite Tape.

<TABLE>
<CAPTION>
                                                              Common Stock           Warrants         Preferred Stock
                                                              ------------           --------         ---------------
                                                             High       Low        High      Low       High       Low
                                                             ----       ---        ----      ---       ----       ---
     <S>                                                    <C>       <C>        <C>        <C>       <C>        <C>
     1999
        First Quarter..................................     $ 4.19    $  2.75    $  0.41    $ 0.25    $ 19.25    $ 15.50
        Second Quarter.................................       6.31       3.88       0.75      0.31      23.25      19.00
        Third Quarter..................................       9.13       6.43       1.50      0.69      28.25      23.25
        Fourth Quarter.................................       9.13       7.13       1.25      0.44      27.13      25.25

     2000
        First Quarter..................................     $13.56    $  8.06    $  3.13    $ 0.56    $ 26.25    $ 26.00
        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           -         -
</TABLE>

       On March 8, 2001, the closing prices of the Common Stock and Warrants
were $25.95 and $13.47, respectively. As of December 31, 2000, there were
approximately 127 holders of record of the common stock and 20.0 million shares
outstanding.

       Dividend Policy. A quarterly cash dividend of $0.01 per common share was
initiated in December 1997 and was continued through the third quarter of 1999.
The dividend was increased to $0.02 per common share in the fourth quarter of
1999 and to $0.04 per common share in the fourth quarter of 2000. 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 $17.2 million available for dividends
as of December 31, 2000.



                                       14
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA

     The following table presents selected historical financial data of the
Company as of or for each of the years in the five-year period ended December
31, 2000. Future results may differ substantially from historical results
because of changes in oil and natural 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 financial data reflects the acquisition of Gerrity in May 1996 and
the acquisition of 50% of Elysium in November 2000.

<TABLE>
<CAPTION>
                                                              As of or for the Year Ended December 31,
                                                  ----------------------------------------------------------------
                                                    1996           1997         1998         1999         2000
                                                  ----------   ----------   ----------   ----------     ----------
                                                                (In thousands except per share data)
<S>                                               <C>          <C>         <C>            <C>            <C>
 Statement of Operations Data
 Revenues......................................    $  83,188   $  100,333   $   74,710   $   91,571     $  150,332
 Expenses
   Direct operating............................       14,519       18,790       17,340       18,173         24,054
   Exploration.................................          224          131           59          666            293
   General and administrative..................        6,151        7,154        7,139        6,185          7,051
   Interest and other..........................       14,304       16,038       13,001       10,844         10,117
   Depletion, depreciation and amortization....       44,822       49,076       41,695       40,744         40,600
   Impairment of oil and gas properties........            -       26,047            -            -              -
                                                   ---------   ----------   ----------   ----------     ----------
     Total expenses............................       80,020      117,236       79,234       76,612         82,115
                                                   ---------   ----------   ----------   ----------     ----------
 Income (loss) before taxes....................        3,168      (16,903)      (4,524)      14,959         68,217
 Provision  (benefit) for income taxes.........         (394)           -            -            -         15,776
                                                   ---------   ----------   ----------   ----------     ----------
 Net income (loss).............................    $   3,562   $  (16,903)  $   (4,524)  $   14,959     $   52,441
                                                   =========   ==========   ==========   ==========     ==========

  Basic net income (loss) per common share.....    $    0.08   $    (1.11)  $    (0.68)  $     0.52     $     2.81
                                                   =========   ==========   ==========   ==========     ==========
  Diluted net income (loss) per common share...    $    0.08   $    (1.11)  $    (0.68)  $     0.50     $     2.28
                                                   =========   ==========   ==========   ==========     ==========

 Basic weighted average shares outstanding.....       17,796       18,324       16,025       15,972         17,553
 Diluted weighted average shares outstanding...       17,796       18,324       16,025       16,471         22,707

 Cash dividends per common share...............    $    0.00   $     0.01   $     0.04   $     0.05     $     0.10

 Balance Sheet Data
    Current assets.............................    $  27,587   $   31,068   $   23,325   $   19,350     $   39,368
    Oil and gas properties, net................      398,640      342,833      324,777      308,035        355,904
    Total assets...............................      430,233      376,875      351,533      330,216        421,254
    Current liabilities........................       26,572       30,297       23,579       19,108         30,867
    Debt.......................................      197,594      146,435      142,021      132,000        177,000
    Stockholders' equity.......................      196,236      188,441      175,976      165,890        176,446

 Cash Flow Data
    Net cash provided by operations............    $  52,996   $   68,645   $   34,331   $   49,660    $   109,384
    Net cash used by investing.................       (9,796)     (18,801)     (23,145)     (23,669)       (86,134)
    Net cash used by financing.................      (38,047)     (43,388)     (13,709)     (35,451)       (21,223)
</TABLE>

                                       15
<PAGE>

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

<TABLE>
<CAPTION>
                                                                                  1999
                                                           ----------------------------------------------------
                                                           First        Second            Third          Fourth
                                                           -----        ------            -----          ------
<S>                                                       <C>          <C>             <C>           <C>
 (In thousands, except per share data)
 Revenues.............................................    $16,656        $20,447         $24,476         $29,992
 Direct operating expenses............................      4,122          4,454           4,762           4,835
 Depletion, depreciation and amortization.............     10,273          9,813          10,292          10,366
 Net income (loss)....................................     (2,018)         1,742           5,280           9,955
 Net income (loss) per share..........................
     Basic............................................      (0.23)          0.01            0.23            0.50
     Diluted..........................................      (0.23)          0.01            0.21            0.41

<CAPTION>
                                                                                  2000
                                                           ----------------------------------------------------
                                                           First        Second            Third          Fourth
                                                           -----        ------            -----          ------

<S>
 (In thousands, except per share data)                    <C>           <C>              <C>             <C>
 Revenues.............................................    $31,576        $31,857         $36,136         $50,763
 Direct operating expenses............................      5,583          4,909           5,404           8,158
 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 common share..........................
     Basic............................................       0.47           0.59            0.73            0.96
     Diluted..........................................       0.40           0.46            0.57            0.86
</TABLE>

                                       16
<PAGE>

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

Results of Operations

        Comparison of 2000 results 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 increase in revenue and net income was
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, compared to 36 new wells or deepenings and 113
refracs and three recompletions in 1999. The Company's current development
activity, the benefits of the Elysium acquisition and continued success with the
production enhancement program have resulted in annual increases in production
since 1998. Based upon a $60.0 million development budget for 2001 and an
additional $15.0 million to $20.0 million to be spent on various grassroots
projects, the Company expects production to continue to increase in the coming
year. The decision to increase development activity is heavily dependent on the
prices being received for production.

        Average oil prices increased 45% from $15.86 per barrel in 1999 to
$23.00 in 2000. Average natural gas prices increased 50% from $2.18 per Mcf in
1999 to $3.28 in 2000. The 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. The average natural 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. Direct
operating expenses, consisting of lease operating and production taxes, totaled
$24.1 million or $0.55 per Mcfe for 2000 compared to $18.2 million or $0.46 per
Mcfe in the prior year period. The increase in direct operating expenses was
primarily attributed to a $4.4 million rise in production taxes as a result of
higher average oil and gas prices.

        General and administrative expenses, net of third party reimbursements,
for 2000 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
third party working interest owners that are offset against general and
administrative expenses. The lower reimbursements were the result of the Company
increasing its working interest ownership in its oil and gas properties as a
result of a property exchange with HS Resources and other minor interest
acquisitions in late 1999. Included in general and administrative expenses is
$279,000 and $1.0 million for 2000 and 1999 of non-cash expenses related to the
common stock grants awarded to officers and managers of the Company 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 over-performance and the increase in oil and gas prices.
Depreciation and amortization expense for 2000 totaled $987,000 or $0.02 per
Mcfe compared to $947,000 or $0.02 per Mcfe for 1999.

                                       17
<PAGE>

        Comparison of 1999 results to 1998. Revenues in 1999 totaled $91.6
million, a 23% increase over 1998. The increase was due primarily to increases
in production and higher oil and gas prices. Net income for 1999 totaled $15.0
million compared to a net loss of $4.5 million in 1998. The increase was
attributed to higher production, cost efficiencies and recovering oil and gas
prices.

        Average daily oil and gas production in 1999 totaled 4,529 barrels and
80.8 MMcf (107.9 MMcfe), an increase of 10% on an equivalent basis from 1998.
During 1999, 36 wells were drilled or deepened and 116 refracs and recompletions
were performed, compared to 36 new wells or deepenings and 75 refracs and
recompletions in 1998.

        Average oil prices increased 19% from $13.29 per barrel in 1998 to
$15.86 in 1999. Average natural gas prices increased 12% from $1.94 per Mcf for
1998 to $2.18 in 1999. The average oil prices include hedging gains of $285,000
or $0.17 per barrel in 1998 and hedging losses of $3.1 million or $1.85 per
barrel in 1999. The average natural gas prices include hedging gains of $1.7
million or $0.06 per Mcf in 1998 and hedging losses of $1.0 million or $0.03 per
Mcf in 1999. Direct operating expenses, consisting of lease operating and
production taxes, totaled $18.2 million or $0.46 per Mcfe for 1999 compared to
$17.3 million or $0.49 per Mcfe in the prior year period. The increase in direct
operating expenses in 1999 was attributed to a $1.3 million rise in production
taxes as a result of higher average oil and gas prices and production offset by
a decrease in lease operating expenses of $497,000.

        General and administrative expenses, net of third party reimbursements,
for 1999 totaled $6.2 million, a $954,000 or 13% decrease from 1998. The
reduction in general and administrative expense was due to a cost reduction
program implemented in late 1998. Included in general and administrative
expenses is $1.0 million and $1.5 million for 1999 and 1998 of non-cash expenses
related to the common stock grants awarded to officers and managers of the
Company in conjunction with the redistribution of SOCO's ownership of the
Company in 1997.

        Interest and other expenses fell to $10.8 million in 1999, a decrease of
$2.2 million or 17% from the prior year. Interest expense decreased as a result
of lower average debt balances and 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 1999 was 8.1% compared to 10.0% in 1998.

        Depletion, depreciation and amortization expense for 1999 totaled $40.7
million, a decrease of $951,000 or 2% from 1998. Depletion expense totaled $39.8
million or $1.01 per Mcfe for 1999 compared to $40.9 million or $1.14 per Mcfe
for 1998. 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 second and fourth quarters of 1999 in conjunction with
the completion of the mid-year and year-end reserve reports reflecting
additional oil and gas reserves due primarily to the identification of
additional refrac projects and drilling locations, upward revisions due to
over-performance and the increase in oil and gas prices. Depreciation and
amortization expense for 1999 totaled $947,000 or $0.02 per Mcfe compared to
$807,000 or $0.02 per Mcfe for 1998.

Development, Acquisition and Exploration

        During 2000, the Company incurred $40.3 million of capital expenditures
for Wattenberg projects and $49.0 million of acquisition costs relating
primarily to the 50% interest acquired in Elysium Energy, L.L.C in late 2000.
Capital expenditures included $40.0 million of development costs in Wattenberg
to drill or deepen 57 J-Sand wells, perform 193 refracs and nine recompletions
and drill three Codell wells. This development activity, the benefits of the
Elysium acquisition and continued success with the production enhancement
program allowed the Company to realize an 11% increase in production over 1999.
The Company anticipates incurring approximately $60.0 million on the further
development of its properties during 2001, with an additional $15.0 million to
$20.0 million budgeted for various grassroots projects. The decision to increase
or decrease development activity is heavily dependent on the prices being
received for production.

                                       18
<PAGE>

Financial Condition and Capital Resources

       At December 31, 2000, the Company had $421.3 million of assets. Total
capitalization was $353.4 million, of which 50% was represented by stockholders'
equity and 50% by bank debt. During 2000, net cash provided by operations
totaled $109.4 million, as compared to $49.7 million in 1999 ($108.5 million and
$56.4 million prior to changes in working capital, respectively). At December
31, 2000, there were no significant commitments for capital expenditures. Based
upon a $60.0 million capital budget for 2000 and an additional $15.0 million to
$20.0 million for various grassroots projects, 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 2000, the Company repurchased 1,638,000 common shares and redeemed
513,800 shares of 7.125% preferred stock for $42.1 million. The repurchases were
financed with borrowings under the Company's bank credit facility. On January
29, 2001, the Company repurchased 758,500 shares of its common stock from J.P.
Morgan Partners (formerly Chase Capital Partners) for $20.50 a share or $15.8
million. As part of the transaction, the Company received an option to purchase
an additional 758,500 shares for the same price through May 1, 2001, which it
expects to exercise. The Company also anticipates receiving approximately $36.1
million in proceeds from the exercise of the $12.50 common stock warrants, which
expire on May 2, 2001.

       In July 1999, in conjunction with the redemption of the 11.75% Senior
Subordinated Notes, the Company entered into a Second Amended and Restated Bank
Credit Agreement (the "Credit Agreement"). The Credit Agreement is a revolving
credit facility in an aggregate amount up to $200.0 million. The amount
available under the facility is adjusted semi-annually, each May 1 and November
1, and equaled $200.0 million at December 31, 2000.

       The Credit Agreement contains certain financial covenants, including but
not limited to a maximum total debt to EBITDA ratio and a minimum current ratio.
The Credit Agreement also contains certain 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 negotiated
extensions of the Credit Agreement; however, there is no assurance the Company
will be able to do so in the future. The Company had a restricted payment
basket, as defined in the Credit Agreement, of $17.2 million as of December 31,
2000, which may be used to repurchase equity securities and pay dividends.

       The Company may elect that all or a portion of the credit facility bear
interest at a rate equal to: (i) the prime rate or (ii) the rate at which
Eurodollar deposits for one, two, three or six months (as selected by the
Company) are offered in the interbank Eurodollar market plus a margin which
fluctuates from 1.00% to 1.50%, determined by a debt to EBITDA ratio. The
average interest rate under the facility approximated 7.7% during 2000 and was
7.8% at December 31, 2000.

       In October 1998, the Company entered into an interest rate swap contract
for a two-year period, extendable for one additional year at the option of the
third party. 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
Company's fixed rate of 4.57% and the three-month LIBOR rate, which was reset
every 90 days, was received or paid by the Company in arrears every 90 days. The
Company received $184,000 in 1999 pursuant to this contract and $422,000 in
2000. In October 2000, the swap contract lapsed as the third party elected not
to extend it.

                                       19
<PAGE>

       The Company had $74.0 million of 11.75% Senior Subordinated Notes due
July 15, 2004 outstanding on December 31, 1998. The Notes had been reflected in
the financial statements at a book value of 105.875% of their principal amount,
the initial call price ($69.9 million of principal amount outstanding as of
December 31, 1998). The Notes became redeemable on July 15, 1999. The Company
redeemed all of the Notes at the call price of 105.875% on July 15, 1999. The
redemption was financed with borrowings under the bank credit facility.

       In conjunction with his appointment in March 1998, the Company's
President purchased 100,000 shares of common stock at $6.875 per share. The
Company loaned him $584,000, or 85% of the purchase price, represented by a
recourse promissory note that bears interest at 8.50% per annum payable each
March 31 until the note is paid. The note matures in March 2001 and is secured
by the shares purchased and granted to him. As approved by the Board of
Directors, the President sold 50,000 common shares to the Company at $23.50 per
share, utilizing a portion of these proceeds to repay the note in March 2001.

       The Company has entered into arrangements to monetize its Section 29 tax
credits. These arrangements result in revenue increases of approximately $0.40
per Mcf on production volumes from qualified Section 29 properties. As a result,
additional gas revenues of $2.1 million, $2.9 million and $3.5 million were
recognized during 1998, 1999 and 2000, respectively. The Company expects to
exercise its option to terminate these arrangements in March 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 natural gas
prices, and there can be no assurance that operations and other capital
resources will provide cash in sufficient amounts to maintain planned levels of
capital expenditures or that increased capital expenditures will not be
undertaken.

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

Certain Factors That May Affect Future Results

       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, prospect 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 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 natural 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.

                                       20
<PAGE>

Market Risk Disclosures

Commodity Price Risk

       The Company's major market risk exposure is in the pricing applicable to
its oil and natural 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 2000, exclusive of any hedges, ranged from a monthly low of $2.41 per Mcf
to a monthly high of $6.20 per Mcf. Oil prices, exclusive of any hedges, ranged
from a monthly low of $24.36 per barrel to a monthly high of $33.85 per barrel
during 2000. Oil and natural gas prices increased significantly during 1999 and
2000. 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.

       From time to time, the Company enters into commodity derivative contracts
and fixed-price physical contracts to manage its exposure to oil and gas price
volatility. The Company uses futures contracts, swaps, options and fixed-price
physical contracts to hedge its commodity prices. Realized gains or losses from
price risk management activities are recognized in oil and gas sales in the
period in which the associated production occurs.

       As of December 31, 2000, the Company had entered into swap contracts for
oil (NYMEX based) for approximately 4,300 barrels of oil per day for 2001 at
fixed prices ranging from $23.05 to $34.43 per barrel and 750 barrels of oil per
day for January 2002 through April 2002 at fixed prices ranging from $26.10 to
$26.92 per barrel. Certain 2001 swap contracts for oil (NYMEX based) contain
"knock-out" provisions. If the average price of NYMEX WTI crude oil falls below
the "knock-out" price for the contract month, the swaps will be considered
"knocked-out" and no payment will be made to the Company for the applicable
month. These swaps are summarized in the table below. The overall weighted
average hedged price for the swap contracts is $27.07 per barrel for 2001 and
$26.51 per barrel for the first four months of 2002. The unrecognized gains on
these contracts totaled $3.0 million and $18,000 based on estimated market
values at December 31, 2000 and March 1, 2001, respectively.

       As of December 31, 2000, the Company had entered into natural gas swap
contracts for approximately 50,400 MMBtu's per day for 2001 at fixed prices
ranging from $2.55 to $5.05 per MMBtu on CIG index based swap contracts. The
Company also has entered into physical natural gas sale contracts for the
delivery of approximately 2,500 MMBtu's per day for the first quarter of 2001 at
prices ranging from $2.67 to $3.08 per MMBtu. The weighted average daily volumes
and prices for these natural gas swaps and physical contracts are 51,000 MMBtu's
per day at $3.58 per MMBtu for 2001. The unrecognized losses on the swap
contracts totaled $42.2 million and $29.5 million based on estimated market
values at December 31, 2000 and March 1, 2001, respectively.

       As of March 1, 2001, the Company was a party to the following fixed price
swap and physical arrangements summarized below:

<TABLE>
<CAPTION>
                                                                   Oil (NYMEX)
                               -----------------------------------------------------------------------------------------------
                                        Swap                    Swap "Knock-out"                   Combined
                               --------------------       ------------------------------     -----------------
                                  Daily                     Daily              "Knock-out"     Daily               Unrealized
                                 Volume                    Volume                 Price       Volume              Gain / (Loss)
Time Period                        Bbl        $/Bbl          Bbl    $/Bbl        $/Bbl          Bbl      $/Bbl    ($/thousand)
--------------                     ---        -----          ----   ------       ------         ---      -----    ------------
<S>                               <C>         <C>           <C>     <C>         <C>           <C>        <C>      <C>
01/01/01 - 03/31/01............   3,250       30.19         1,500     23.41        17.00       4,750     28.05        (327)
04/01/01 - 06/30/01............   3,750       28.77         1,250     23.29        17.00       5,000     27.40         (20)
07/01/01 - 09/30/01............   3,750       27.57           750     23.13        17.00       4,500     26.83          68
10/01/01 - 12/31/01............   3,650       26.98           750     23.13        17.00       4,400     26.32         164

01/01/02 - 04/30/02............     750       26.51           -         -            -           750     26.51         133
</TABLE>

                                       21
<PAGE>

<TABLE>
<CAPTION>
                                                             Natural Gas
                               -----------------------------------------------------------------------------------------------
                                      CIG Swap                   Physical                    Combined
                               --------------------    -----------------------        ----------------------
                                  Daily                    Daily                          Daily                   Unrealized
                                 Volume                   Volume                         Volume                  Gain / (Loss)
Time Period                       MMBtu      $/MMBtu       MMBtu      $/MMBtu             MMBtu      $/MMBtu     ($/thousand)
-----------                       -----      -------   -----------    -------         ---------      -------     ------------
<S>                              <C>         <C>          <C>         <C>                <C>         <C>         <C>
01/01/01 - 03/31/01............  60,800        3.82         2,500        2.87            63,300        3.78        (14,704)
04/01/01 - 06/30/01............  55,000        3.38             -           -            55,000        3.38         (6,364)
07/01/01 - 09/30/01............  45,000        3.50             -           -            45,000        3.50         (4,009)
10/01/01 - 12/31/01............  42,500        3.82             -           -            42,500        3.82         (4,474)

01/01/02 - 03/31/02............  35,000        5.02             -           -            35,000        5.02            178
04/01/02 - 05/31/02............  14,900        3.86             -           -            14,900        3.86            (90)
</TABLE>

Interest Rate Risk

       At December 31, 2000, the Company had $177.0 million outstanding under
its credit facility with an average interest rate of 7.8%. The Company may elect
that all or a portion of the credit facility bear interest at a rate equal to:
(i) the prime rate or (ii) the rate at which Eurodollar deposits for one, two,
three or six months (as selected by the Company) are offered in the interbank
Eurodollar market plus a margin which fluctuates from 1.00% to 1.50%, determined
by a debt to EBITDA ratio. The average interest rate under the facility
approximated 7.7% during 2000. Assuming no change in the amount outstanding
during 2001, the impact on interest expense of a ten percent change in the
average interest rate would be approximately $1.4 million. As the interest rate
is variable and is reflective of current market conditions, the carrying value
approximates the fair value.

                                       22
<PAGE>

Inflation and Changes in Prices

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

       The following table indicates the average oil and natural gas prices
received over the last five years and highlights the price fluctuations by
quarter for 1999 and 2000. 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)
                  Annual
                  ------
                  <S>                                   <C>               <C>              <C>
                  1996...............................    $20.47            $1.99             $2.41
                  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

                  Quarterly
                  ---------
                  1999
                  First..............................    $11.65            $1.65             $1.72
                  Second.............................     16.10             1.99              2.17
                  Third..............................     19.90             2.48              2.68
                  Fourth.............................     23.01             2.63              2.92

                  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
</TABLE>

                                       23
<PAGE>

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



                                                                           Page
                                                                           ----

PATINA OIL & GAS CORPORATION

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

  Consolidated Balance Sheets as of December 31, 1999 and 2000............. F-3

  Consolidated Statements of Operations for the years ended
     December 31, 1998, 1999 and 2000...................................... F-4

  Consolidated Statements of Changes in Stockholders' Equity
     for the years ended December 31, 1998, 1999 and 2000.................. F-5

  Consolidated Statements of Cash Flows for the years ended
     December 31, 1998, 1999 and 2000...................................... F-6

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


                                      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, 1999
and 2000, and the related consolidated statements of operations, changes in
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2000. 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, 1999 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.



Denver, Colorado,                               ARTHUR ANDERSEN LLP
March 5, 2001

                                      F-2
<PAGE>

                         PATINA OIL & GAS CORPORATION

                          CONSOLIDATED BALANCE SHEETS
                       (In thousands except share data)

<TABLE>
<CAPTION>
                                                                                               December 31,
                                                                                   -----------------------------------
                                                                                      1999                    2000
                                                                                   ----------              -----------
<S>                                                                               <C>                      <C>
                                                       ASSETS
Current assets
     Cash and equivalents                                                          $      626              $    2,653
     Accounts receivable                                                               15,694                  31,830
     Inventory and other                                                                3,030                   4,885
                                                                                   ----------              ----------
                                                                                       19,350                  39,368
                                                                                   ----------              ----------

Oil and gas properties, successful efforts method                                     621,767                 709,248
     Accumulated depletion, depreciation and amortization                            (313,732)               (353,344)
                                                                                   ----------              ----------
                                                                                      308,035                 355,904
                                                                                   ----------              ----------

Gas facilities and other                                                                3,790                   4,580
     Accumulated depreciation                                                          (2,251)                 (3,098)
                                                                                   ----------              ----------
                                                                                        1,539                   1,482
                                                                                   ----------              ----------

Other assets, net                                                                       1,292                  24,500
                                                                                   ----------              ----------
                                                                                   $  330,216              $  421,254
                                                                                   ==========              ==========


                                        LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
     Accounts payable                                                              $   14,993              $   23,073
     Accrued liabilities                                                                4,115                   7,794
                                                                                   ----------              ----------
                                                                                       19,108                  30,867
                                                                                   ----------              ----------

Senior debt                                                                           132,000                 177,000
Deferred income taxes                                                                       -                  15,776
Other noncurrent liabilities                                                           13,218                  21,165

Commitments and contingencies

Stockholders' equity
     Preferred Stock, $.01 par, 5,000,000 shares
         authorized, 2,383,328 and -0- shares issued
         and outstanding                                                                   24                       -
     Common Stock, $.01 par, 100,000,000 shares
         authorized, 16,131,310 and 20,043,859 shares
         issued and outstanding                                                           161                     200
     Capital in excess of par value                                                   188,545                 151,392
     Deferred compensation                                                               (279)                      -
     Retained earnings (deficit)                                                      (22,561)                 24,854
                                                                                   ----------              ----------
                                                                                      165,890                 176,446
                                                                                   ----------              ----------
                                                                                   $  330,216              $  421,254
                                                                                   ==========              ==========
</TABLE>

                                      F-3
<PAGE>

                         PATINA OIL & GAS CORPORATION

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

<TABLE>
<CAPTION>
                                                                                           Year Ended December 31,
                                                                              -----------------------------------------------
                                                                                   1998               1999             2000
                                                                              -------------         ---------        --------
<S>                                                                           <C>                   <C>              <C>
   Revenues
     Oil and gas sales                                                          $  72,177           $  90,407        $  148,665
     Other                                                                          2,533               1,164             1,667
                                                                                ---------           ---------        ----------
                                                                                   74,710              91,571           150,332
                                                                                ---------           ---------        ----------

   Expenses
     Direct operating                                                              17,340              18,173            24,054
     Exploration                                                                       59                 666               293
     General and administrative                                                     7,139               6,185             7,051
     Interest and other                                                            13,001              10,844            10,117
                                                                                ---------           ---------        ----------
     Depletion, depreciation and amortization                                      41,695              40,744            40,600
                                                                                ---------           ---------        ----------
                                                                                   79,234              76,612            82,115

   Income (loss) before taxes                                                      (4,524)             14,959            68,217
                                                                                ---------           ---------        ----------

   Provision for income taxes
     Current                                                                            -                   -                 -
     Deferred                                                                           -                   -            15,776
                                                                                ---------           ---------        -----------
                                                                                        -                   -            15,776
                                                                                ---------           ---------        -----------

    Net income (loss)                                                           $  (4,524)          $  14,959        $   52,441

    Net income (loss) per common share
      Basic                                                                     $  (0.68)           $    0.52        $     2.81
                                                                                ========            =========        ==========
      Diluted                                                                   $  (0.68)           $    0.50        $     2.28
                                                                                ========            =========        ==========

    Weighted average shares outstanding
      Basic                                                                       16,025               15,972            17,553
                                                                                ========            =========        ==========
      Diluted                                                                     16,025               16,471            22,707
                                                                                ========            =========        ==========
</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
                                (In thousands)

<TABLE>
<CAPTION>
                                                                                        Capital in                   Retained
                                            Preferred Stock           Common Stock      Excess of      Deferred      Earnings
                                         ---------------------     -----------------
                                         Shares         Amount     Shares     Amount    Par Value    Compensation   (Deficit)
                                         ------         ------     ------     ------    ---------    ------------   ---------
<S>                                      <C>        <C>            <C>       <C>        <C>          <C>             <C>
   Balance, December 31, 1997             3,094     $     31       16,450    $     165    $ 208,525     $  (1,828)   $ (18,452)

   Repurchase of common and preferred       (68)          (1)      (1,338)         (13)      (8,676)           --           --

   Issuance of common                        --           --          640            6        3,224          (688)          --

   Preferred dividends and accretion        141            2           --           --        3,719            --       (6,335)

   Common dividends                          --           --           --           --           --            --         (657)

   Net loss                                  --           --           --           --           --         1,478       (4,524)
                                      ---------     --------     --------    ---------    ---------     ---------    ---------

   Balance, December 31, 1998             3,167           32       15,752          158      206,792        (1,038)     (29,968)

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

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

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

   Preferred dividends                      119            1           --           --        3,319            --       (6,251)

   Common dividends                          --           --           --           --           --            --         (812)

   Net Income                                --           --           --           --           --         1,093       14,959
                                      ---------     --------     --------    ---------    ---------     ---------    ---------

   Balance, December 31, 1999             2,383           24       16,131          161      188,545          (279)     (22,561)

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

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

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

   Preferred dividends                       --           --           --           --           --            --       (2,661)

   Common dividends                          --           --           --           --           --            --       (1,816)

   Net income                                --           --           --           --           --           279       52,441
                                      ---------     --------     --------    ---------    ---------     ---------    ---------

   Balance, December 31, 2000                --     $     --       20,044    $     200    $ 151,392     $      --    $  24,854
                                      =========     ========     ========    =========    =========     =========    =========
</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,
                                                                   -------------------------------------------

                                                                     1998            1999               2000
                                                                   -------         -------            --------
Operating activities
<S>                                                              <C>               <C>               <C>
  Net income (loss)                                              $  (4,524)        $ 14,959          $ 52,441
  Adjustments to reconcile net income (loss) to net
    cash provided by operations
        Exploration expense                                             59              666               293
        Depletion, depreciation and amortization                    41,695           40,744            40,600
        Deferred income taxes                                            -                -            15,776
        Deferred compensation expense                                1,478            1,046               279
        Amortization of deferred credits                              (622)          (1,211)           (1,209)
        Amortization of loan fees                                        -              152               303
        Gain on sale of other assets                                (1,124)               -                 -
        Changes in current and other assets and liabilities
          Decrease (increase) in
                  Accounts receivable                                5,354           (5,741)          (13,068)
                  Inventory and other                                   63             (180)             (432)
          Increase (decrease) in
                  Accounts payable                                  (3,626)          (1,833)            7,492
                  Accrued liabilities                               (3,092)          (2,412)              334
                  Other assets and liabilities                      (1,330)           3,470             6,575
                                                                 ---------         --------          --------
        Net cash provided by operating activities                   34,331           49,660           109,384
                                                                 ---------         --------          --------

Investing activities
  Acquisition, development and exploration                         (24,089)         (24,003)          (89,304)
  Other                                                                944              334             3,170
                                                                 ---------         --------          --------
        Net cash used by investing activities                      (23,145)         (23,669)          (86,134)
                                                                 ---------         --------          --------

Financing activities
  Increase (decrease) in indebtedness                               (4,414)         (10,021)           45,000
  Loan to affiliate                                                      -                -           (24,500)
  Deferred credits                                                   1,271            2,087             1,446
  Loan origination fees                                                  -             (455)                -
  Issuance of common stock                                           1,396            2,040             3,568
  Repurchase of common stock and warrants                           (7,315)          (6,582)          (28,750)
  Repurchase of preferred stock                                     (1,375)         (18,106)          (12,846)
  Preferred stock redemption premium                                     -             (489)             (549)
  Preferred dividends                                               (2,615)          (3,113)           (2,776)
  Common dividends                                                    (657)            (812)           (1,816)
                                                                 ---------         --------          --------
        Net cash used by financing activities                      (13,709)         (35,451)          (21,223)
                                                                 ---------         --------          --------

Increase (decrease) in cash                                         (2,523)          (9,460)            2,027
Cash and equivalents, beginning of period                           12,609           10,086               626
                                                                 ---------         --------          --------
Cash and equivalents, end of period                              $  10,086         $    626          $   2,65
                                                                 =========         ========          ========
</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 completed an acquisition of various property
interests out of a bankruptcy proceeding. 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, on which $53.0 million was drawn at
closing. 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 natural gas properties.
Historically, Patina's properties were primarily in the Wattenberg Field of
Colorado's D-J Basin. With the recent acquisition of Elysium, the Company now
has additional oil and natural gas properties located in central Kansas, the
Illinois Basin, the San Joaquin Field of California, and the Lake Washington
Field of Louisiana.

  (2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Producing Activities

       The Company utilizes the successful efforts method of accounting for its
oil and gas properties. Consequently, 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 initially
capitalized, but charged to expense if and when 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 remaining proved or proved developed reserves, as
applicable. 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 has
been provided for estimated future abandonment costs on certain Elysium
properties as of December 31, 2000. No accrual has been provided for the
Wattenberg properties as management estimates that salvage value will
approximate or exceed such costs.

       The Company follows the provisions of Statement of Financial Accounting
Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of Long-Lived
Assets." SFAS 121 requires the Company to assess the need for an impairment of
capitalized costs of oil and gas properties on a field-by-field basis. During
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 natural 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>

  Gas facilities and other

       Depreciation of gas gathering and transportation facilities is provided
using the straight-line method over an estimated useful life of five years.
Equipment is depreciated using the straight-line method with estimated useful
lives, generally ranging from three to five years.

  Other Assets

       Other Assets at December 31, 1999 were comprised of $988,000 of notes
receivable from certain officers and key managers of the Company. See Note (9).
At December 31, 2000, the remaining notes receivable balance of $690,000 was
classified as a current asset and included in Inventory and other, as these
notes are due in 2001. At December 31, 1999, the balance also included net loan
origination fees of $303,000. These fees were fully amortized in 2000. At
December 31, 2000, Other Assets was comprised of $24.5 million advanced under a
revolving credit facility to Elysium by Patina. Patina provided Elysium a $60.0
million non-recourse revolving credit facility, on which $49.0 million was
outstanding at December 31, 2000. The facility provides for a borrowing base,
which is subject to adjustment semi-annually. At February 22, 2001 the borrowing
base was $60.0 million of which $13.0 million was available. The loan matures in
July 2003. The interest rate is generally based on the Eurodollar rate plus a
margin, which fluctuates from 1.50% to 2.00%, depending upon the utilization of
the borrowing base. See Note (9).

  Section 29 Tax Credits

       The Company has entered into arrangements to monetize its Section 29 tax
credits. These arrangements result in revenue increases of approximately $0.40
per Mcf on production volumes from qualified Section 29 properties. As a result,
additional gas revenues of $2.1 million, $2.9 million and $3.5 million were
recognized during 1998, 1999 and 2000, respectively. The Company expects to
exercise its option to terminate these arrangements in March 2001.

  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,
1999 and December 31, 2000 were insignificant.

  Comprehensive Income

       The Company follows the provisions of SFAS No. 130, "Reporting
Comprehensive Income." SFAS No. 130 establishes standards for reporting and
display of comprehensive income and its components in a full set of general-
purpose financial statements. 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 in 1998, 1999 or 2000, respectively.

  Financial Instruments

       The book value and estimated fair value of cash and equivalents was
$626,000 and $2.7 million at December 31, 1999 and December 31, 2000,
respectively. The book value and estimated fair value of the senior debt was
$132.0 million and $177.0 million at December 31, 1999 and December 31, 2000,
respectively. The book value of these assets and liabilities approximates fair
value due to the short maturity or floating rate structure of these instruments.

       From time to time, the Company enters into commodity derivative contracts
and fixed-price physical contracts to manage its exposure to oil and natural gas
price volatility. Commodity derivative contracts, which are generally placed
with major financial institutions or with counter parties of high credit quality
that the Company believes are minimal credit risks, may take the form of futures
contracts, swaps or options. The oil and gas reference prices of these commodity
derivative contracts are based upon oil and natural gas futures which have a
high degree of historical

                                     F-8
<PAGE>

correlation with actual prices received by the Company. The Company accounts for
its commodity derivative contracts using the hedge (deferral) method of
accounting. Under this method, realized gains and losses on such contracts are
deferred and recognized as an adjustment to oil and gas sales in the period in
which the physical product to which the contracts relate, is actually sold.
Gains and losses on commodity derivative contracts that are closed before the
hedged production occurs are deferred until the production month originally
hedged.

       The Company entered into various swap contracts for oil (NYMEX based)
during 1998, 1999 and 2000. The Company recognized a gain of $238,000 in 1998
and losses of $3.1 million and $10.4 million in 1999 and 2000, respectively,
related to these swap contracts.

       The Company entered into various CIG and PEPL index based swap contracts
for natural gas during 1998, 1999, and 2000. The Company recognized a gain of
$1.5 million in 1998 and losses of $1.0 million and $13.5 million in 1999 and
2000, respectively, related to these swap contracts.

       As of December 31, 2000, the Company had entered into swap contracts for
oil (NYMEX based) for approximately 4,300 barrels of oil per day for 2001 at
fixed prices ranging from $23.05 to $34.43 per barrel and 750 barrels of oil per
day for January 2002 through April 2002 at fixed prices ranging from $26.10 to
$26.92 per barrel. Certain 2001 swap contracts for oil (NYMEX based) contain
"knock-out" provisions. If the average price of NYMEX WTI crude oil falls below
the "knock-out" price for the contract month, the swaps will be considered
"knocked-out" and no payment will be made to the Company for the applicable
month. These swaps are summarized in the table below. The overall weighted
average hedged price for the swap contracts is $27.07 per barrel for 2001 and
$26.51 per barrel for the first four months of 2002. The unrecognized gains on
these contracts totaled $3.0 million and $18,000 based on estimated market
values at December 31, 2000 and March 1, 2001, respectively.

       As of December 31, 2000, the Company had entered into natural gas swap
contracts for approximately 50,400 MMBtu's per day for 2001 at fixed prices
ranging from $2.55 to $5.05 per MMBtu on CIG index based swap contracts. The
Company also has entered into physical natural gas sale contracts for the
delivery of approximately 2,500 MMBtu's per day for the first quarter of 2001 at
prices ranging from $2.67 to $3.08 per MMBtu. The weighted average daily volumes
and prices for these natural gas swaps and physical contracts are 51,000 MMBtu's
per day at $3.58 per MMBtu for 2001. The unrecognized losses on the swap
contracts totaled $42.2 million and $29.5 million based on estimated market
values at December 31, 2000 and March 1, 2001, respectively.

       As of March 1, 2001, the Company was a party to the following fixed price
swap and physical arrangements summarized below:

<TABLE>
<CAPTION>

                                                                   Oil (NYMEX)
                               -----------------------------------------------------------------------------------------------
                                        Swap                    Swap "Knock-out"                   Combined
                               --------------------       ------------------------------     -----------------
                                  Daily                     Daily              "Knock-out"     Daily               Unrealized
                                 Volume                    Volume                 Price       Volume              Gain / (Loss)
Time Period                        Bbl        $/Bbl          Bbl    $/Bbl        $/Bbl          Bbl      $/Bbl    ($/thousand)
--------------                     ---        -----          ----   ------       ------         ---      -----    ------------
<S>                              <C>         <C>           <C>       <C>          <C>         <C>       <C>          <C>
01/01/01 - 03/31/01............   3,250       30.19         1,500     23.41        17.00       4,750     28.05        (327)
04/01/01 - 06/30/01............   3,750       28.77         1,250     23.29        17.00       5,000     27.40         (20)
07/01/01 - 09/30/01............   3,750       27.57           750     23.13        17.00       4,500     26.83          68
10/01/01 - 12/31/01............   3,650       26.98           750     23.13        17.00       4,400     26.32         164

01/01/02 - 04/30/02............     750       26.51           -         -            -           750     26.51         133
</TABLE>

                                      F-9
<PAGE>

<TABLE>
<CAPTION>
                                                             Natural Gas
                               -----------------------------------------------------------------------------------------------
                                      CIG Swap                   Physical                    Combined
                               --------------------    -----------------------        ----------------------
                                  Daily                    Daily                        Daily                     Unrealized
                                 Volume                   Volume                       Volume                    Gain / (Loss)
Time Period                       MMBtu      $/MMBtu       MMBtu      $/MMBtu           MMBtu         $/MMBtu    ($/thousand)
-----------                       -----      -------   -----------    -------         -------         -------    ------------
<S>                             <C>           <C>          <C>          <C>             <C>           <C>         <C>
01/01/01 - 03/31/01............  60,800        3.82         2,500        2.87            63,300        3.78        (14,704)
04/01/01 - 06/30/01............  55,000        3.38             -           -            55,000        3.38         (6,364)
07/01/01 - 09/30/01............  45,000        3.50             -           -            45,000        3.50         (4,009)
10/01/01 - 12/31/01............  42,500        3.82             -           -            42,500        3.82         (4,474)

01/01/02 - 03/31/02............  35,000        5.02             -           -            35,000        5.02            178
04/01/02 - 05/31/02............  14,900        3.86             -           -            14,900        3.86            (90)
</TABLE>

       In 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities." SFAS 133 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 derivative's 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. SFAS 133 is effective for fiscal
years beginning after June 15, 2000.

       The financial statement impact of recording derivative instruments
designated as hedges and derivative instruments not designated as hedges upon
adoption of SFAS 133 on January 1, 2001 is as follows (in millions):

<TABLE>
<CAPTION>

                                                                                                       Amount
                                                                                                       ------
Balance Sheet
<S>                                                                                                <C>
Derivative liability..............................................................                  $  (42.3)
Derivative asset .................................................................                       4.0
Deferred tax liability............................................................                      (1.4)
Deferred tax asset................................................................                      15.2
Cumulative effect of a change in accounting principle (other comprehensive income)                  $   24.5

Statement of Operations
Cumulative effect of a change in accounting principle (derivative loss)...........                  $   (0.6)
</TABLE>

       In October 1998, the Company entered into an interest rate swap contract
for a two-year period, extendable for one additional year at the option of the
third party. 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 Company's
fixed rate of 4.57% and the three-month LIBOR rate, which was reset every 90
days, was received or paid by the Company in arrears every 90 days. The Company
received $184,000 in 1999 pursuant to this contract and $422,000 in 2000. In
October 2000, the swap contract lapsed as the third party elected not to extend
it.

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 $1.5
million, $1.0 million and $279,000 of non-cash general and administrative
expenses for 1998, 1999 and 2000, respectively. These costs were fully amortized
at year-end 2000. See Note (6).

                                     F-10
<PAGE>

Per Share Data

       The Company uses the weighted average number of shares outstanding in
calculating earnings per share data. When dilutive, options and warrants are
included as share equivalents using the treasury stock method and are included
in the calculation of diluted per share data. Common stock issuable upon
conversion of convertible preferred securities is also included in the
calculation of diluted per share data if their effect is dilutive.

Risks and Uncertainties

       Historically, the market for oil and natural gas has experienced
significant price fluctuations. Prices for oil and natural gas in the United
States have been particularly volatile in recent years. The price fluctuations
can result from variations in weather, levels of regional or national
production, 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

<TABLE>
<CAPTION>

       The Company incurred the following significant non-cash items:
                                                                                            Year Ended December 31,
                                                                                      ---------------------------------
                                                                                       1998          1999         2000
                                                                                      -----        ------       ------
      <S>                                                                            <C>           <C>          <C>
       Stock grant award..........................................................    $ 688         $ 335        $   -
       Stock Purchase Plan........................................................      173            53           89
       Dividends and accretion - 8.50% preferred stock............................    3,720         3,321            -
       401(k) profit sharing in common stock......................................      338           483          589
</TABLE>

       The 1998 stock grant award represents 100,000 common shares granted to
the President in conjunction with his appointment in the first quarter of 1998
and was recorded as Deferred Compensation in the equity section of the
accompanying consolidated balance sheets. The 1999 stock grant award represents
100,000 common shares 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
$1.5 million, $1.0 million and $279,000 of non-cash general and administrative
expenses for 1998, 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 an original 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.

                                     F-11
<PAGE>

(3)  OIL AND GAS PROPERTIES

     The cost of oil and gas properties at December 31, 1999 and 2000 included
approximately $225,000 and $1.1 million in net unevaluated leasehold costs. The
value of acreage held for exploration, development or resale and its value, is
excluded from amortization. The following table sets forth costs incurred
related to oil and gas properties:

<TABLE>
<CAPTION>
                                                                    1998               1999               2000
                                                                 ----------         ----------         ----------
                                                                                  (In thousands)
<S>                                                              <C>                 <C>                <C>
            Acquisition......................................    $    2,319          $    2,215         $   49,015
            Development......................................        21,711              21,122             39,996
            Exploration and other............................            59                 666                293
                                                                 ----------          ----------         ----------
                                                                 $   24,089          $   24,003         $   89,304
                                                                 ==========          ==========         ==========
</TABLE>

(4)  INDEBTEDNESS

     The following indebtedness was outstanding on the respective dates:

<TABLE>
<CAPTION>
                                                                                         December 31,
                                                                              --------------------------------
                                                                                1999                    2000
                                                                              --------                --------
                                                                                       (In thousands)
<S>                                                                         <C>                     <C>
            Bank facilities.............................................    $ 132,000               $ 177,000
            Less current portion........................................            -                       -
                                                                            ---------               ---------
            Senior debt, net............................................    $ 132,000               $ 177,000
                                                                            =========               =========
</TABLE>

       In July 1999 the Company entered into a Second Amended and Restated Bank
Credit Agreement (the "Credit Agreement"). The Credit Agreement is a revolving
credit facility in an aggregate amount up to $200.0 million. The amount
available under the facility is adjusted semi-annually, each May 1 and November
1, and equaled $200.0 million at December 31, 2000.

       The Company may elect that all or a portion of the credit facility bear
interest at a rate equal to: (i) the prime rate or (ii) the rate at which
Eurodollar deposits for one, two, three or six months (as selected by the
Company) are offered in the interbank Eurodollar market plus a margin which
fluctuates from 1.00% to 1.50%, determined by a debt to EBITDA ratio. The
average interest rate under the facility approximated 7.7% during 2000 and was
7.8% at December 31, 2000.

       The Credit Agreement contains certain financial covenants, including but
not limited to a maximum total debt to EBITDA ratio and a minimum current ratio.
The Credit Agreement also contains certain 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 negotiated
extensions of the Credit Agreement; however, there is no assurance the Company
will be able to do so in the future. The Company had a restricted payment
basket, as defined in the Credit Agreement, of $17.2 million as of December 31,
2000, which may be used to repurchase equity securities and pay dividends.

       Scheduled maturities of indebtedness for the next five years are zero for
2001 and 2002, and $177.0 million in 2003. Management intends to review the
facility and extend the maturity on a regular basis; however, there can be no
assurance that the Company will be able to do so. Cash payments for interest
totaled $14.0 million, $14.3 million and $10.0 million during 1998, 1999 and
2000, respectively.

                                     F-12
<PAGE>

(5)  STOCKHOLDERS' EQUITY

     A total of 100,000,000 common shares, $0.01 par value, are authorized of
which 20,043,859 were issued and outstanding at December 31, 2000. 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. The dividend was increased to $0.02
per common share in the fourth quarter of 1999 and to $0.04 per common share in
the fourth quarter of 2000. The following is a schedule of the changes in the
Company's shares of common stock:

<TABLE>
<CAPTION>
                                                                      1998                1999               2000
                                                                  ------------        ------------       ------------
<S>                                                               <C>                 <C>                 <C>
     Beginning common shares outstanding.....................     16,450,400           15,752,400          16,131,300
     Sale of shares to management............................        100,000                    -                   -
     Exercise of stock options...............................              -              226,300             249,300
     Shares issued under Stock Purchase Plan.................        180,900               92,900              52,400
     Shares issued in lieu of salaries & bonuses.............         76,700              164,800             128,300
     Shares issued for directors fees........................         11,900                8,600               2,800
     Conversion of 7.125% preferred..........................              -              488,800             148,000
     Conversion of 8.50% preferred...........................              -                    -           4,785,600
     Exercise of $12.50 warrants.............................              -                    -               2,400
     Shares issued to deferred compensation plan.............              -               35,200              13,700
     Stock grant (vested)....................................        131,600              168,600             138,600
     401(K) profit sharing contribution......................        138,500               61,300              29,600
     Shares repurchased and retired..........................     (1,337,600)            (867,600)         (1,638,100)
                                                                  ----------           ----------          ----------
     Ending common shares outstanding........................     15,752,400           16,131,300          20,043,900
                                                                  ==========           ==========          ==========
</TABLE>


       On January 29, 2001, the Company repurchased 758,500 shares of its common
stock from J.P. Morgan Partners (formerly Chase Capital Partners) for $20.50 a
share or $15.8 million. As part of the transaction, the Company received an
option to purchase an additional 758,500 shares at the same price through May 1,
2001.

       At December 31, 2000, the Company had 2,917,090 $12.50 common stock
warrants outstanding. These warrants are exercisable at $12.50 for one share of
common stock and expire on May 2, 2001. The common stock warrants are listed on
the New York Stock Exchange.

       A total of 5,000,000 preferred shares, $0.01 par value, are authorized
with no shares issued and outstanding at December 31, 2000.

       In December 1999, the Company called for redemption all remaining 7.125%
preferred stock. The effective date of the redemption was January 21, 2000. Of
the 564,800 preferred 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 $2.6 million, $2.7 million and $600,000 in preferred
dividends during 1998, 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 all remaining 1,618,500
shares of the 8.50% preferred stock outstanding. The issue was 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 $3.5 million, $3.7
million and $2.6 million in dividends during 1998, 1999 and 2000, respectively.
Dividends through October 21, 1999 were paid in kind. As such, the Company
issued 141,240 and 119,577 of additional 8.50% preferred shares as dividends in
1998 and 1999, respectively. Dividends subsequent to October 1999 were paid in
cash.

                                     F-13
<PAGE>

       The Company follows the provisions of Statement of Financial Accounting
Standards No. 128 ("SFAS 128"), "Earnings per Share." SFAS 128 specifies
computation, presentation and disclosure requirements for earnings per share for
entities with publicly held common stock or potential common stock.

<TABLE>
<CAPTION>
                                                                            Year Ended December 31,
                                         -------------------------------------------------------------------------------------------
                                                     1998                            1999                           2000
                                         ------------------------------  ------------------------------  ---------------------------

                                              Net    Common     Per         Net      Common      Per      Net       Common     Per
                                             Loss    Shares    Share      Income     Shares     Share    Income     Shares    Share
                                             ----    ------    -----      ------     ------     -----    ------     ------    -----
<S>                                      <C>         <C>     <C>         <C>         <C>      <C>      <C>         <C>    <C>
Net income (loss)                        $  (4,524)  16,025              $ 14,959    15,972            $ 52,441    17,553
7.125% preferred stock dividends            (2,615)       -                (2,681)        -                (600)        -
8.50% preferred stock dividends             (3,531)       -                (3,727)        -              (2,610)        -
Preferred stock accretion                     (189)       -                  (331)        -                   -         -
                                         ---------  -------                ------    ------            ---------   ------
Basic net income (loss) attributable
   to common stock                         (10,859)  16,025  $ (0.68)       8,220    15,972   $ 0.52     49,231    17,553  $  2.81
                                                             =======                          ======                       =======

Effect of dilutive securities:
7.125% preferred stock                           -        -                     -         -                   -         -
8.50% preferred stock                            -        -                     -         -               2,610     3,242
Stock options                                    -        -                     -       222                   -     1,111
Stock grant                                      -        -                     -       277                   -       131
$12.50 common stock warrants                     -        -                     -         -                   -       670
                                         ---------  -------              --------    ------            --------    ------
Diluted net income (loss) attributable
   to common stock                       $ (10,859)  16,025  $ (0.68)    $  8,220    16,471   $ 0.50   $ 51,841    22,707  $  2.28
                                         =========  =======  =======     ========    ======   ======   ========    ======  =======
</TABLE>

       The potential common stock equivalents of the 7.125% and 8.50% preferred
stock, and $12.50 common stock warrants were anti-dilutive in 1998 and 1999. The
stock options were anti-dilutive in 1998.


(6)    EMPLOYEE BENEFIT PLANS

401(k) Savings

       The Company has a 401(k) profit sharing and savings plan (the "401(k)
Plan"). Eligible employees may make voluntary contributions to the 401(k) Plan.
The amount of employee contributions is limited as specified in 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
to the 401(k) Plan of $338,000, $483,000 and $589,000 for 1998, 1999 and 2000,
respectively. The profit sharing contributions were made in common stock in each
of the last three years. A total of 138,500, 61,300 and 29,600 common shares
were contributed in 1998, 1999 and 2000, 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 ("Closing 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 Plan. In 1998, the Board
of Directors approved 291,300 common shares (exclusive of shares available for
purchase with participants' salaries and bonuses) for possible purchase by
participants at 75% of the Closing Price during the current Plan Year as defined
in the Stock Purchase Plan. As of December 31, 1998, participants had purchased
257,600 shares of common stock, including 76,700 shares purchased

                                     F-14
<PAGE>

with participant's 1997 bonuses, at prices ranging from $3.69 to $7.31 per share
($2.77 to $5.48 net price per share), resulting in cash proceeds to the Company
of $1.3 million. 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 at 75% of the Closing Price
during the current Plan Year as defined in the Stock Purchase Plan. As of
December 31, 1999, participants had purchased 92,900 shares of common stock at
prices ranging from $5.06 to $8.63 per share ($3.80 to $6.47 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 at 75% of the Closing Price during the current Plan Year as defined
in the Stock Purchase Plan. As of December 31, 2000, participants had purchased
138,200 shares of common stock, including 85,800 shares purchased with
participant's 1999 bonuses, at prices ranging from $9.19 to $17.31 per share
($6.89 to $12.98 net price per share), resulting in cash proceeds to the Company
of $665,000. The Company recorded non-cash general and administrative expenses
of $173,000, $53,000 and $89,000 associated with these purchases for 1998, 1999
and 2000, 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 given time. The specific terms of grant and exercise are
determinable by a committee of independent members of the Board of Directors. A
summary by year of stock options granted under the plan for employees is
summarized below:

                                                                      Weighted
                                                       Range           Average
                                                   of Exercise        Exercise
                                      Options       Price Per         Price Per
       Year                           Granted      Common Share     Common Share
       ----                           -------      ------------     ------------
       1996.......................     512,000         $7.75            $7.75
       1997.......................     521,000     $8.75 - $9.88        $9.75
       1998.......................     614,000     $6.56 - $7.19        $7.03
       1999.......................     630,000     $2.94 - $9.13        $3.54
       2000.......................     505,000    $9.19 - $21.94        $9.34

       The options generally vest over a three-year period (30%, 60%, 100%) and
expire five years from the date of grant, except for 250,000 five-year options
which were fully vested at the date of grant in October 1997 at an exercise
price of $9.88.

       The Company also maintains a shareholder approved stock grant and option
plan (the "Directors' Plan") for non-employee Directors. 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 their retainer. A total
of 3,600 shares were issued in 1996, 4,500 shares were issued in 1997, 11,900
shares were issued in 1998, 8,600 were issued in 1999 and 2,800 were issued in
2000. It also provides for 5,000 options to be granted annually to each
non-employee Director. A summary by year of stock options granted under the
Directors' Plan is summarized below:

                                                                     Weighted
                                                      Range           Average
                                                  of Exercise        Exercise
                                     Options        Price Per       Price Per
      Year                           Granted      Common Share     Common Share
      ----                           -------      ------------     ------------
      1996.......................      20,000         $7.75            $7.75
      1997.......................      30,000     $8.63 - $10.31       $9.19
      1998.......................      35,000     $7.19 - $7.75        $7.59
      1999.......................      30,000     $2.94 - $5.13        $4.76
      2000.......................      25,000        $17.44           $17.44

                                      F-15
<PAGE>

       The options generally vest over a three-year period (30%, 60%, 100%) and
expire five years from the date of grant.

       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 plan, which was
amended effective December 31, 1997, provided for the grant of certain
restricted common shares to the Management Investors. These shares vested at 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 vest at 33% per year in March 1999, 2000 and 2001. The non-vested granted
common shares have been 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, utilizing a portion of these proceeds to repay the note in
March 2001. See Note (9). In April 1999, the Chief Executive Officer was granted
100,000 restricted shares of common stock 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
$1.5 million, $1.0 million and $279,000 of non-cash general and administrative
expenses for 1998, 1999 and 2000 with respect to these stock grants.

       At December 31, 2000, the Company had a fixed 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 fixed stock option plans. Had compensation cost for the Company's
fixed stock option compensation plans been determined consistent with Statement
of Financial Accounting Standards No. 123 ("SFAS 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:

                                                    1998       1999       2000
                                                    ----       ----       ----

Net income (loss)               As Reported       $(4,524)    $14,959    $52,441
                                Pro forma          (5,724)     13,954     50,948
Basic net income (loss)
       per common share         As Reported       $(0.68)     $  0.52    $  2.81
                                Pro forma          (0.75)        0.45       2.72
Diluted net income (loss)
       per common share         As Reported       $(0.68)     $  0.50    $  2.28
                                Pro forma          (0.75)        0.44       2.24


       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 1998, 1999 and 2000: dividend yield of 0%, 1% and
1%; expected volatility of 46%, 47% and 49%; risk-free interest rate of 5.5%,
5.2% and 6.6%; and expected life of 4.5 years, 4.5 years and 4.0 years,
respectively.

                                      F-16
<PAGE>

       A summary of the status of the Company's fixed stock option plans as of
December 31, 1998, 1999 and 2000 and changes during the years are presented
below:

<TABLE>
<CAPTION>
                                                           1998                         1999                     2000
                                                ------------------------   -------------------------   -------------------------
                                                              Weighted                     Weighted                   Weighted
                                                               Average                      Average                    Average
                                                              Exercise                     Exercise                   Exercise
                                                 Shares         Price         Shares         Price       Shares         Price
                                                 ------         -----         ------         -----       ------         -----
     <S>                                       <C>            <C>           <C>             <C>          <C>          <C>
     Outstanding at begining of year.........  1,001,000         $8.07      1,526,000        $8.07       1,740,000      $6.59
     Granted   ..............................    649,000          7.06        660,000         3.60         530,000       9.73
     Exercised ..............................          -             -       (226,000)        6.43        (249,000)      7.53
     Forfeited ..............................   (124,000)         7.91       (220,000)        8.05         (10,000)      9.06
                                             -----------                  -----------                  -----------
     Outstanding at end of year..............  1,526,000         $8.07      1,740,000        $6.59       2,011,000      $7.29
                                               =========                  ===========                  ===========

     Options exercisable at year-end.........    582,000                      747,000                      902,000
                                             ===========                  ===========                  ===========

     Weighted-average fair value of options
        granted during the year..............                    $3.17                       $1.48                      $4.24
</TABLE>

       The following table summarizes information about fixed stock options
outstanding at December 31, 2000:

<TABLE>
<CAPTION>
                                               Options Outstanding                          Options Exercisable
                             ------------------------------------------------------- --------------------------------
                                 Number                                                 Number
                             Outstanding at       Weighted-Avg.         Weighted-   Exercisable at        Weighted-
                              December 31,          Remaining            Average     December 31,          Average
Exercise Price                    2000          Contractual Life     Exercise Price      2000          Exercise Price
--------------                    ----          ----------------     --------------      ----          --------------
<S>                          <C>                <C>                  <C>             <C>               <C>
$  2.94  to   7.06.........       914,000           2.8 years           $  4.89          343,000          $  5.48
   7.19  to   9.19.........       706,000           3.1 years              8.73          199,000             7.77
   9.25  to  21.94.........       391,000           1.8 years             10.28          360,000             9.70
                               ----------                                                -------
$  2.94  to  21.94........      2,011,000           2.7 years           $  7.29          902,000          $  7.67
                                =========                                                =======
</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, 1998,
1999 and 2000 follows:

<TABLE>
<CAPTION>
                                                                              1998            1999            2000
                                                                              ----            ----            ----
<S>                                                                          <C>              <C>             <C>
Federal statutory rate....................................................   (35%)             35%              35%
State income tax rate, net of federal benefit.............................     -                -                3%
Increase (decrease) in valuation allowance against deferred tax asset.....    35%             (35%)            (12%)
Revision of prior estimates ..............................................     -                -               (3%)
                                                                            ------            -----          ------
Effective income tax rate.................................................     -                -               23%
                                                                            ======            =====          ======
</TABLE>

                                      F-17
<PAGE>

     For book purposes the components of the net deferred tax asset and
liability at December 31, 1999 and 2000 were:


<TABLE>
<CAPTION>
                                                                                           1999                   2000
                                                                                        ---------              ---------
                                                                                                 (In thousands)
<S>                                                                                    <C>                    <C>
Deferred tax assets
    NOL carryforwards   ..........................................................     $   30,940             $   18,603
    Deferred deductions and other.................................................          4,025                  1,721
                                                                                       ----------             ----------
                                                                                           34,965                 20,324
                                                                                       ----------             ----------
Deferred tax liabilities
    Depreciable and depletable property...........................................        (26,812)               (36,100)
                                                                                       ----------              ---------

Deferred tax asset (liability)......................................................        8,153                (15,776)
                                                                                       ----------             ----------

Valuation allowance.................................................................       (8,153)                     -
                                                                                       ----------             ----------

Net deferred tax asset (liability)..................................................   $       -              $  (15,776)
                                                                                       ==========             ==========
</TABLE>

     For tax purposes, the Company had regular net operating loss carryforwards
of approximately $49.0 million and alternative minimum tax ("AMT") loss
carryforwards of approximately $7.5 million at December 31, 2000. Utilization of
$42.8 million of the regular net operating loss carryforwards will be limited to
approximately $12.5 million per year as a result of the redistribution of SOCO's
majority ownership in the Company in October 1997. In addition, utilization of
$25.9 million regular net operating loss carryforwards will be limited to $4.2
million per year as a result of the Gerrity acquisition in 1996. These
carryforwards expire from 2008 through 2018. At December 31, 2000, the Company
had AMT credit carryforwards of $1.4 million that are available indefinitely. No
cash payments were made by the Company for federal taxes during 1999 and 2000.
The Company paid $239,000 of federal taxes during 1998.

(8)  MAJOR CUSTOMERS

     During 1998, 1999 and 2000, Duke Energy Field Services, Inc. accounted for
38%, 37% and 32%, BP Amoco Production Company accounted for 13%, 24% and 19%,
Enron North America accounted for 10%, 4%, and 3% and Aurora Natural Gas, LLC
accounted for 0%, 10% and 1% 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
remaining notes balance at December 31, 2000 of $106,000 was repaid in January
2001. These notes have been reflected as Other Assets in the accompanying
consolidated balance sheets at December 31, 1999 and in Inventory and other at
December 31, 2000. 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, or 85% of the purchase
price, represented by a recourse promissory note that bears interest at 8.50%
per annum payable each March 31. The note matures in March 2001 and is secured
by all of the shares purchased and granted to him. As approved by the Board of
Directors, the President sold 50,000 common shares to the Company at $23.50 per
share, utilizing a portion of these proceeds to repay the note in March 2001.
The note has been reflected as Other Assets in the accompanying consolidated
balance sheets at December 31, 1999 and in Inventory and other at December 31,
2000. In consideration of the then depressed stock price and overall lower 1998
bonuses, the interest due as of March 31, 1999 under the Management Investors'
and President's notes was forgiven.

                                     F-18
<PAGE>

     Patina provided Elysium a $60.0 million non-recourse revolving credit
facility, on which $49.0 million was outstanding at December 31, 2000. The
facility provides for a borrowing base, which is subject to adjustment semi-
annually. At February 22, 2001 the borrowing base was $60.0 million of which
$13.0 million was available. The loan matures in July 2003. The interest rate is
generally based on the Eurodollar rate plus a margin, which fluctuates from
1.50% to 2.00%, depending upon the utilization of the borrowing base. In 2000,
Elysium paid $371,000 of interest to Patina under the revolving credit facility.

     Patina provides certain administrative services to Elysium under an
operating agreement. During 2000, the Company was paid $36,000 for these
services.

(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
$750,000 per year from 2001 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.


(11)  UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

      Independent petroleum consultants audited the Company's total proved
reserves at December 31, 1998, 1999 and 2000. 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.

                                     F-19
<PAGE>

Quantities of Proved Reserves

<TABLE>
<CAPTION>
                                                                                     Oil                   Natural Gas
                                                                                     ---                   -----------
                                                                                    (MBbl)                  (MMcf)

    <S>                                                                               <C>                     <C>
    Balance, December 31, 1997..........................................              16,976                  255,635
      Revisions ........................................................              (3,033)                 (23,084)
      Extensions, discoveries and additions.............................               1,890                   77,120
      Production........................................................              (1,699)                 (25,522)
      Purchases.........................................................                 108                    2,465
      Sales.............................................................                  (2)                     (19)
                                                                                   ---------               ----------

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

<CAPTION>
Proved Developed Reserves
                                                                                      Oil                 Natural Gas
                                                                                      ---                 -----------
                                                                                    (MBbl)                  (MMcf)

December 31, 1997      .................................................              14,594                  232,058
                                                                                      ======                  =======

December 31, 1998      .................................................              13,655                  244,736
                                                                                      ======                  =======

December 31, 1999      .................................................              16,633                  307,560
                                                                                      ======                  =======

December 31, 2000      .................................................              35,146                  409,103
                                                                                      ======                  =======
</TABLE>

                                     F-20
<PAGE>

<TABLE>
<CAPTION>
Standardized Measure
                                                                                         December 31,
                                                                 ---------------------------------------------------------
                                                                     1998                    1999                  2000
                                                                 ------------           ------------           -----------
                                                                                      (In thousands)

<S>                                                              <C>                    <C>                 <C>
Future cash inflows.........................................     $    692,747           $ 1,273,591         $   5,427,152
Future costs
   Production...............................................         (220,846)             (323,859)             (848,093)
   Development..............................................          (68,125)             (126,978)             (412,672)
                                                                 -------------          ------------        --------------
Future net cash flows.......................................          403,776               822,754             4,166,387
Undiscounted income taxes...................................          (41,977)             (192,956)           (1,478,535)
                                                                 ------------           -----------         -------------
After tax net cash flows....................................          361,799               629,798             2,687,852
10% discount factor.........................................         (156,395)             (267,270)           (1,248,907)
                                                                 ------------           -----------         -------------
Standardized measure........................................     $    205,404           $   362,528         $   1,438,945
                                                                 ============           ===========         =============


<CAPTION>
Changes in Standardized Measure

                                                                                         December 31,
                                                                 ---------------------------------------------------------
                                                                     1998                    1999                  2000
                                                                 ------------           ------------           -----------
                                                                                      (In thousands)

<S>                                                               <C>                   <C>                  <C>
Standardized measure, beginning of year....................       $   276,330           $   205,404          $    362,528
Revisions:
   Prices and costs........................................          (124,977)              188,474             1,026,518
   Quantities..............................................             8,396                 3,642                 1,927
   Development costs.......................................            (3,310)               (3,003)               (6,170)
   Accretion of discount...................................            27,633                20,540                36,253
   Income taxes............................................            23,944               (75,287)             (683,866)
   Production rates and other..............................            (5,449)               (6,299)                2,149
                                                                  -----------           -----------          ------------
   Net revisions...........................................           (73,763)              128,067               376,811
Extensions, discoveries and additions......................            33,910                64,048               659,094
Production.................................................           (54,837)              (72,234)             (124,611)
Future development costs incurred..........................            21,711                21,122                39,996
Purchases (a)..............................................             2,068                17,026               128,376
Sales (b) .................................................               (15)                 (905)               (3,249)
                                                                  -----------           -----------          ------------
Standardized measure, end of year..........................       $   205,404           $   362,528            $1,438,945
                                                                  ===========           ===========          ============
</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-21
<PAGE>

PART IV.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K


(a)  Exhibits -

     2.1       Amended and Restated Agreement and Plan of Merger dated as of
               January 16, 1996 as amended and restated as of March 20, 1996 --
               incorporated by reference to Exhibit 2.1 to Amendment No. 1 to
               the Registration Statement on Form S-4 of Patina Oil & Gas
               Corporation. (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       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)

     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)

     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.*

                                      F-22
<PAGE>

     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)

     10.3.1    Deferred Compensation Plan for Selected Employees adopted by the
               Company effective May 1, 1996. (Incorporated herein by reference
               to Exhibit 10.3.1 of the Company's Form 10-K for the year ended
               December 31, 1996)

     10.3.2    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. (Incorporated herein by
               reference to Exhibit 10.3.2 of the Company's Form 10-K for the
               year ended December 31, 1997)

     10.4.1    Patina Oil & Gas Corporation 1998 Stock Purchase Plan.
               (Incorporated herein by reference to Exhibit 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)

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

     10.6      Stock Purchase Agreement dated as of July 31, 1997 by and among
               the Company and the Investors named therein as amended on
               September 19, 1997. (Incorporated herein by reference to Exhibit
               10.5 of the Company's Form 10-Q for the quarter ended September
               30, 1997)

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

     10.8      Management Stock Purchase Agreement dated as of September 4, 1997
               by and among the Company and certain Management Investors.
               (Incorporated herein by reference to Exhibit 10.8 of the
               Company's Form 10-Q for the quarter ended September 30, 1997)

     10.9      Restricted Stock Agreement dated as of September 4, 1997 by and
               among the Company and certain Management Investors. (Incorporated
               herein by reference to Exhibit 10.9 of the Company's Form 10-Q
               for the quarter ended September 30, 1997)

     10.10     Stock Purchase Agreement dated March 16, 1998 by and between the
               Company and Jay W. Decker. (Incorporated herein by reference to
               Exhibit 10.11 of the Company's Form 10-K for the year ended
               December 31, 1997)

     10.11     Restricted Stock Agreement dated March 16, 1998 by and between
               the Company and Jay W. Decker. (Incorporated herein by reference
               to Exhibit 10.11 of the Company's Form 10-K for the year ended
               December 31, 1997)

     10.12     Standstill Agreement dated April 12, 2000 between Patina Oil &
               Gas Corporation 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)

                                      F-23
<PAGE>

     10.13     First Amended and Restated Operating Agreement of Elysium Energy,
               L.L.C., a New York limited liability company, dated November 27,
               2000. *

     12        Computation of Ratio of Earnings to Fixed Charges and Ratio of
               Earnings to Combined Fixed Charges and Preferred Stock
               Dividends.*

     23        Consent of independent public accountants. *

     27        Financial Data Schedule.*


*Filed herewith

(b)  No reports on Form 8-K were filed by Registrant during the quarter ended
     December 31, 2000.

                                      F-24
<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.

<TABLE>
<S>                                                 <C>                                            <C>
/s/ Thomas J. Edelman                               Chairman of the Board                          March 9, 2001
---------------------------------
Thomas J. Edelman                                   (Principal Executive Officer)


/s/ Jay W. Decker                                   President and Director                         March 9, 2001
---------------------------------
Jay W. Decker


/s/ David J. Kornder                                Executive Vice President and                   March 9, 2001
---------------------------------
David J. Kornder                                    Chief Financial Officer


/s/ Christopher C. Behrens                          Director                                       March 9, 2001
---------------------------------
Christopher C. Behrens


/s/ Robert J. Clark                                 Director                                       March 9, 2001
---------------------------------
Robert J. Clark


/s/ Elizabeth K. Lanier                             Director                                       March 9, 2001
---------------------------------
Elizabeth K. Lanier


/s/ Alexander P. Lynch                              Director                                       March 9, 2001
---------------------------------
Alexander P. Lynch
</TABLE>

                                      F-25