<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, 1997

                                    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
7.125% Convertible Preferred 
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 15,049,115 shares of voting stock held by
non-affiliates of the registrant, based upon the closing sale price of the
common stock on February 20, 1998 of $7.00 per share as reported on the New York
Stock Exchange, was $105,343,000.  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 February 20, 1998, the registrant had 16,221,925 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, 1998

================================================================================
<PAGE>
 
                         PATINA OIL & GAS CORPORATION

                          Annual Report on Form 10-K
                               December 31, 1997

                                    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 in the Wattenberg Field ("Wattenberg" or
"Field") of Colorado's Denver-Julesburg Basin ("D-J Basin"). The Company was
formed in early 1996 to hold the Wattenberg assets of Snyder Oil Corporation
("SOCO") and to facilitate the acquisition of Gerrity Oil & Gas Corporation
("Gerrity" or the "Gerrity Acquisition") in May 1996.  After the Gerrity
Acquisition,  SOCO owned 14,000,000 or approximately 74% of the Company's common
shares.  The amounts and results of operations of the Company for periods prior
to the Gerrity Acquisition include the historical amounts and results of SOCO's
Wattenberg operations.

     In October 1997, the Company effectuated a series of transactions which
eliminated SOCO's ownership in the Company.  The transactions included: (i) the
sale by SOCO of 10.9 million common shares of its Patina stock to the public in
a secondary offering, (ii) the repurchase and retirement by the Company of
SOCO's remaining common shares, (iii) the sale  by the Company of $40.0 million
of 8.50% convertible preferred stock and 160,000 common shares to certain
institutional investors and  (iv) the purchase of $3.0 million of common shares
and the grant of 496,250 restricted common shares, net of forfeitures, to
certain officers and key managers of the Company.  As a result of these
transactions, SOCO no longer has any ownership in the Company.

     From its inception, the Company has focused on consolidating its
properties, developing an efficient organization, reducing costs and improving
operations. During 1997, the Company's revenues were $100.3 million and net cash
provided by operations was $68.6 million. The Company used its operating cash
flow along with proceeds from the preferred stock offering and management stock
purchase in October 1997 to reduce indebtedness by $51.2 million and repurchase
$32.8 million of its equity securities, while investing $17.0 million in the
further development of its properties during the year.

     At December 31, 1997, the Company had $376.9 million of assets and 357.5
Bcfe of proved reserves. The reserves had an estimated pretax present value of
$320.0 million based on unescalated prices and costs in effect on that date.
Approximately 72% of the reserves by volume were natural gas and over 98% of the
pretax present value was attributable to proved developed reserves. The Company
operates almost 90% of the roughly 3,500 producing wells in which it holds an
interest, representing 98% of its producing reserves. At December 31, 1997, the
Company had 239 proved undeveloped drilling locations, 487 recompletion and 50
restimulation ("refrac") opportunities included in total proved reserves. During
1997, production averaged 104.6 MMcfe per day. Based on year-end 1997 reserves,
the Company has a reserve life index of 9.4 years.

                                       2
<PAGE>
 
     Patina is one of the largest producers in Wattenberg and currently accounts
for over 30% of the total production from the Field. Wattenberg, a major onshore
producing basin with total cumulative production in excess of three trillion
cubic feet of natural gas equivalents since its discovery in 1970, 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 that there are up to eight potentially productive formations
throughout the field ranging in depths 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, while other formations, such as the Sussex and
the Shannon are more localized. The existence of several pay sands within the
geological structure allows for multiple completions within a single wellbore,
keeping drilling and operating costs low. In recent years, the Codell and
Niobrara formations have been the primary drilling objective in Wattenberg,
although the Company has successfully recompleted shallower formations such as
the Sussex.

     Since 1986, the Company and its predecessors have grown through a series of
acquisitions in combination with the further exploitation and development of its
properties. The Company and its predecessors have completed more than 65
acquisitions having an aggregate purchase price of over $450 million. In the
past five years, the Company has expended approximately $350 million on
development projects including the drilling of 1,400 wells and the recompletion
or refrac of more than 400 wells. During 1997, the Company successfully drilled
28 wells, was in the process of drilling an additional three wells at year-end,
recompleted 81 wells and refraced 21 wells at a total cost of approximately
$17.0 million. Management believes that 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. The Company seeks to maximize the value its oil and natural
gas properties by increasing production and recoverable reserves through the
implementation of operational improvements, workovers, multi-zone recompletions,
refracs and the drilling of new development wells. Given management's expertise
in acquisitions and the advantages set forth above, the Company believes it is
in an excellent position to pursue further consolidation in Wattenberg and to
acquire reserves in other basins where it has or can develop a competitive
advantage.

BUSINESS STRATEGY

     The Company plans to increase its reserves, production and cash flows in a
cost-efficient manner primarily through: (i) selectively pursuing consolidation
and acquisition opportunities in existing and future core areas;  (ii)
efficiently controlling operating and overhead expenses;  (iii) operating its
properties in order to enhance production through well workovers, development
activity and operational improvements;  (iv) utilizing improved exploitation and
development techniques to maximize the value of its properties; and (v)
developing a strong financial position that affords the Company the financial
flexibility to execute its business strategy.

     The Company intends to pursue further consolidation and exploitation
opportunities in Wattenberg.  In addition, management intends to simultaneously
pursue low-risk acquisitions of producing reserves in other U.S. basins where
the Company's economies of scale, focused operations and operating expertise
give it a competitive advantage in pursuing further consolidation and
acquisition opportunities.

                                       3
<PAGE>
 
PRODUCTION, REVENUE AND PRICE HISTORY

     The following table sets forth information regarding net production of oil
and natural gas, revenues and operating expenses attributable to such
production, average sales prices and other production information for each of
the years in the five year period ended December 31, 1997.  Note: The financial
and operating information reflect the acquisition of Gerrity by the Company in
May 1996.
<TABLE>
<CAPTION>
                                               December 31,
                             ------------------------------------------------
                               1993      1994      1995      1996      1997
                             --------  --------  --------  --------  --------
                                  (Dollars in thousands, except prices and
                                             per Mcfe information)
<S>                          <C>       <C>       <C>       <C>       <C>       
Production
  Oil (MBbl)...............     1,224     1,829     1,342     1,688     1,889
  Gas (MMcf)...............    21,706    23,893    20,981    23,947    26,863  
  MMcfe (a)................    29,050    34,872    29,034    34,074    38,194
 
Revenues
  Oil......................   $19,429   $27,151   $22,049  $ 34,541   $37,197
  Gas (b)..................    45,125    40,598    28,024    47,644    62,342
                              -------   -------   -------  --------  --------
     Subtotal..............    64,554    67,749    50,073    82,185    99,539
  Other....................       311        73        29     1,003       794
                              -------   -------   -------   -------  --------
     Total.................    64,865    67,822    50,102    83,188   100,333
                              -------   -------   -------   -------  --------
 
Direct operating expenses
  Lease operating expenses.     4,956     3,662     5,387     8,866    11,735
  Production taxes.........     3,971     4,448     3,480     5,653     7,055
                              -------   -------   -------   -------  --------
     Total.................     8,927     8,110     8,867    14,519    18,790
                              -------   -------   -------   -------  --------
 
Direct operating margin....   $55,938   $59,712   $41,235   $68,669  $ 81,543
                              =======   =======   =======   =======  ========
 
Average sales price (c)
  Oil (Bbl)................   $ 15.87   $ 14.84   $ 16.43   $ 20.47  $  19.70
  Gas (Mcf) (b)............      2.08      1.70      1.34      1.99      2.32
  Mcfe (a).................      2.22      1.94      1.73      2.41      2.61
 
Average direct operating 
  expense/Mcfe.............      0.31      0.23      0.31      0.43     0.49
Average production 
  margin/Mcfe..............      1.91      1.71      1.42      1.99     2.12
------------------------------
</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.
(c)  The Company's average net wellhead prices in December 1997 approximated
     $2.35 per Mcf of gas and $17.25 per barrel of oil.

                                       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 natural gas
pipeline facilities near its properties, and the ability to truck oil to local
refineries or oil pipelines. 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. The Company does not believe, however, that the
loss of any of its customers would have a long-term material adverse effect on
its operations.

     Natural Gas.  Wattenberg natural gas is high in heating content (BTUs) and
must be processed in order to strip natural gas liquids ("NGLs") before residue
gas is sold to utilities, independent marketers and end users through both
intrastate and interstate pipelines. The Company utilizes two separate
arrangements to gather, process and market its natural gas production.
Approximately 30% of the Company's natural gas 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 the sale of its residue gas and NGLs by Duke
Energy. Substantially all of the Company's remaining natural gas production is
dedicated for gathering to either Duke Energy or KN Front Range Gathering
Company ("KN") and is then processed at plants owned by Duke Energy or Amoco
Production Company ("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 seasonal spot market arrangements along the front range of Colorado or
transports the gas to Midwest markets under transportation agreements. NGLs are
sold by the processor and the Company receives payment net of applicable
processing fees.

     A portion of the natural gas gathered by KN is processed by Amoco at the
Wattenberg Processing Plant under a favorable contract that not only provides
payment for a percentage of the NGLs stripped from the natural gas, but also
redelivers to the tailgate the same amount of MMBTU's as was delivered to the
plant under a "keepwhole" arrangement. This agreement remains in effect until
December 2012.

     Oil.  Oil production is principally sold to refiners, marketers and other
purchasers who truck oil to local refineries or pipelines. The price is
generally based on a local market posting for oil and is adjusted for
transportation costs and quality. 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 from other oil and natural gas companies in all of its
operations, including the acquisition of drilling prospects and producing
properties. Patina competes for the acquisition of oil and natural gas
properties with numerous entities, including major oil companies, other
independent oil and natural gas concerns 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 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 oil and natural gas 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
believed to be suitable for drilling are acquired.  Prior to the commencement of
drilling on a tract, a detailed title examination is conducted and curative work
is performed with respect to known significant title defects.

                                       5
<PAGE>
 
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 oil and natural gas industry increases the Company's
cost of doing business, decreases flexibility in the timing of operations and
may adversely affect the economics of capital projects.

     In the past, the federal government has regulated the prices at which oil
and 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 market forces.

     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 properties are located, amended its
statute concerning oil and natural gas development in 1994 to provide the
Colorado Oil and 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. Several rule makings pursuant to
these statutory changes have been undertaken by the COGCC 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 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 conducting
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 and
recompletion operations.

     Environmental Regulation. Operations of the Company 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 natural gas
and oil 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.

                                       6
<PAGE>
 
     The Company operates its own exploration and production waste management
facilities, which enable it to treat, bioremediate and otherwise dispose of tank
sludges, contaminated soil and produced water generated from the Company's
operations. There can be no assurance, that these facilities, or other
commercial disposal facilities utilized by the Company 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 to Patina. 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 the
Company's operating costs, as well as on the oil and natural gas industry in
general.

OFFICE AND OPERATIONS FACILITIES

     The Company, a Delaware corporation, leases its principal executive offices
at 1625 Broadway, Denver, Colorado 80202. The lease covers approximately 29,000
square feet and has a remaining term of four years, expiring in November 2001.
The monthly rent is approximately $39,000. The Company also own a 6,000 square
foot production facility in Platteville, Colorado and 6,000 square feet of
office space in Brighton, Colorado. These facilities are used to support the
Company's Wattenberg Field operations. The Company also owns a 15,000 square
foot office building in Evans, Colorado which is currently held for sale.

EMPLOYEES

     On December 31, 1997, the Company employed 163 people, including 103 that
work in the Company's various field offices, none of whom are represented by a
labor union.  The Company believes its relationship with its employees is
satisfactory.

                                       7
<PAGE>
 
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....... 47         Chairman of the Board, President
                                             and Chief Executive Officer
         Brian J. Cree........... 34         Executive Vice President and
                                             Chief Operating Officer, Director
         Keith M. Crouch......... 51         Senior Vice President and General
                                             Counsel
         Ronald E. Dashner....... 45         Senior Vice President, Operations
         David J. Kornder........ 37         Vice President and Chief
                                             Financial Officer
         David R. Macosko........ 36         Vice President
         Terry L. Ruby........... 39         Vice President
         David W. Siple.......... 38         Vice President
         Arnold L. Chavkin....... 46         Director
         Robert J. Clark......... 53         Director
         Jay W. Decker........... 45         Director
         Thomas R. Denison....... 37         Director
         Elizabeth K. Lanier..... 46         Director
         Alexander P. Lynch...... 45         Director
</TABLE>
____________________

     THOMAS J. EDELMAN has served as Chairman of the Board, President and Chief
Executive Officer of the Company since its formation. He co-founded SOCO and was
its President from 1981 through February 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
Lomak Petroleum, Inc., and is a Director of Petroleum Heat & Power Co. Inc.,
Star Gas Corporation, Weatherford Enterra, Inc. and Paradise Music &
Entertainment, Inc. Mr. Edelman is also a Trustee of The Hotchkiss School.

     BRIAN J. CREE has served as Executive Vice President, Chief Operating
Officer and Director of the Company since May 1996. Prior to the Gerrity
Acquisition, he served as Chief Operating Officer and Director of Gerrity since
1993. From 1992 to 1993, Mr. Cree served as Senior Vice President - Operations
and Chief Accounting Officer of Gerrity. Prior to that, Mr. Cree served as Vice
President of Gerrity and its predecessor since 1989 and served in various
accounting capacities with that company from 1987 to 1990. Prior to that, Mr.
Cree was employed as an accountant with the public accounting firm of Deloitte,
Haskins & Sells. Mr. Cree received his Bachelor of Arts Degree in Accounting
from the University of Northern Iowa.

     KEITH M. CROUCH has served as Senior Vice President and General Counsel of
the Company since May 1996. Prior to the Gerrity Acquisition, he was a Vice
President of Gerrity commencing in 1993 and was appointed a Director in 1994.
From 1992 to 1993, Mr. Crouch served as Corporate Counsel to Gerrity. Prior to
joining Gerrity, Mr. Crouch was in private practice with the law firms of
Gorsuch, Kirgis, Campbell, Walker and Grover; Kirkland & Ellis and Pendleton,
Friedberg, Wilson and Hennessey. Mr. Crouch received Bachelor of Arts and Juris
Doctor Degrees from the University of Colorado.

                                       8
<PAGE>
 
     RONALD E. DASHNER has served as Senior Vice President, Operations of the
Company since its formation. He joined SOCO in 1994 and served as Operations
Manager of SOCO's D-J Basin/Greater Green River Unit. In late 1995 he was
appointed Vice President - Rocky Mountain Division. From 1991 to 1994, Mr.
Dashner was Onshore Gulf Coast Operations Manager for Enron Oil & Gas Company.
From 1980 through 1990, Mr. Dashner held various positions with TXO Production
Corp., including Drilling & Production Manager - Rocky Mountain District and
Assistant District Manager - East Texas District. From 1978 to 1980, he was
employed by Davis Oil Company in Engineering and Operations. From 1975 to 1978,
he was employed by Chevron in the Drilling, Production and Construction
Department. Mr. Dashner received his Bachelor of Science Degree in Civil
Engineering from Colorado State University.

     DAVID J. KORNDER has served as Vice President and Chief Financial Officer
of the Company since May 1996. Prior to the Gerrity Acquisition, he served as a
Vice President - Finance of Gerrity beginning in early 1993. From 1989 through
1992, Mr. Kornder was an Assistant Vice President for 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.

     DAVID R. MACOSKO has served as a Vice President of the Company since May
1996. Prior to the Gerrity Acquisition, he served as a Vice President of Gerrity
from 1994. From 1989 to 1992, Mr. Macosko held various accounting positions with
Gerrity and served as Operations Coordinator from 1992 to 1994. From 1985 to
1989, Mr. Macosko was employed by PanCanadian Petroleum Company as the
supervisor of revenue and expenditure accounting. Mr. Macosko received his
Bachelor of Science Degree in Accounting from West Virginia University.

     TERRY L. RUBY has served as a Vice President of the Company since May 1996.
Prior to the Gerrity Acquisition, Mr. Ruby served as a senior landman of Gerrity
beginning in 1992 and was appointed Vice President - Land in 1995.  Prior to his
employment with Gerrity, Mr. Ruby worked for Apache Corporation from 1990 to
1992, and for Baker Exploration Company from 1982 to 1989. 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 of the Company since May
1996. He joined SOCO's land department in 1994 and was appointed Land Manager of
SOCO 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.

     ARNOLD L. CHAVKIN has served as a Director of the Company since October
1997. Mr. Chavkin is a General Partner at Chase Capital Partners. Chase Capital
Partners is a General Partner of Chase Venture Capital Associates, L.P. Before
assuming such position, Mr. Chavkin was a member of Chemical Bank's merchant
banking group and, prior to that, a generalist in its corporate finance group
specializing in mergers and acquisitions and private placements for the energy
industry. Prior to that, Mr. Chavkin worked in corporate development for
Freeport McMoRan, and held various positions with Gulf and Western Industries.
Mr. Chavkin is a Certified Public Accountant. He received his Bachelor of Arts
and M.B.A. degrees from Columbia University. Mr. Chavkin is also a director of
American Radio Systems, Inc., Bell Sports, Reading & Bates Corporation and
Wireless One, Inc.

                                       9
<PAGE>
 
     ROBERT J. CLARK has served as a Director of the Company since May 1996. Mr.
Clark is the President of Bear Paw Energy Inc., a wholly owned subsidiary of
TransMontaigne Oil Company. Mr. Clark formed a predecessor company Bear Paw
Energy Inc. in 1995 and joined TransMontaigne in 1996 when TransMontaigne
acquired a majority interest in the predecessor company. 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.

     JAY W. DECKER has served as a Director of the Company since May 1996. Mr.
Decker has 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 based
in Denver, Colorado 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 for 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.

     THOMAS R. DENISON has served as a Director of the Company since January
1998. Mr. Denison is a Managing Director and the General Counsel of First
Reserve Corporation. He joined the firm in January 1998 and opened its Denver.
Prior to joining First Reserve, he was a partner in the international law firm
of Gibson, Dunn & Crutcher LLP, a firm which he joined in 1986 as an associate.
Mr. Denison received his Bachelor of Science degree in Business Administration
from the University of Denver and his Juris Doctor from the University of
Virginia. Mr. Denison also serves on the board of directors of Phoenix Energy
Services.

     ELIZABETH K. LANIER has served as a Director of the Company since January
1998.  Mrs. Lanier has served as Vice President and Chief of Staff of Cinergy
Corp since 1996.  She is a member of the Management Committee, Operating
Committee and Strategy Committee and a Cinergy Foundation Trustee.  Mrs. Lanier
is responsible for Information Technology, Real Estate, Facilities, Corporate
and Office Services, Technology Integration (R&D), Community Affairs,
Shareholder Relations, Corporate Records and Diversity Performance.  Mrs. Lanier
received her Bachelor of Arts Degree with honors from Smith College in 1973 and
her law degree from Columbia Law School in 1977 where she was a Harlan Fiske
Stone Scholar.  Mrs. Lanier was awarded an Honorary Doctorate of Technical
Letters by Cincinnati Technical College in 1991 and an Honorary Doctorate of
Letters in 1995 from the College of Mt. St. Joseph.  From 1982 to 1996 she was a
Partner in the Corporate and Litigation Departments of Frost & Jacobs a law firm
in Cincinnati, Ohio.  From 1977 to 1982 she was with the law firm of Davis Polk
& Wardwell in New York City.  She is Chair of the Ohio Board of Regents.

     ALEXANDER P. LYNCH has served as a Director of the Company since May 1996.
Mr. Lynch is currently a General Partner of The Beacon Group, a private
investment and financial advisory firm. Mr. Lynch had been Co-President and Co-
Chief Executive Officer of The Bridgeford Group, a financial advisory firm,
since 1995. 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 Illinois Central Corporation and Lincoln Snacks Company.

                                       10
<PAGE>
 
ITEM 2. PROPERTIES

GENERAL

     The Company's reserves are concentrated in the Wattenberg Field within 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.
Although referred to as a "formation" or "sand," many such formations actually
are comprised of more than one rock strata. For example, the Niobrara has three
separate and distinct bodies or "benches" with potential hydrocarbon
development. The presence of several prospective zones tends to reduce the risk
of a dry hole. The following chart lists the formations present in Wattenberg:

                             PRODUCING FORMATIONS
<TABLE>
<CAPTION>
                                                        Approximate
                Formation                                  Depth
                ---------                                  -----
                                                           (feet)
                <S>                                     <C>
                Parkman.................................   3,600
                Sussex..................................   4,500
                Shannon.................................   4,800
                Niobrara................................   7,000
                Codell..................................   7,300
                D-Sand..................................   7,500
                J-Sand..................................   7,800
                Dakota..................................   8,000
</TABLE>

     At December 31, 1997, the Company had working interests in 3,305 gross
(2,985 net) producing oil and natural gas wells in the D-J Basin and held
royalty interests in an additional 195 producing wells. As of December 31, 1997,
estimated proved reserves totaled 357.5 Bcfe, including 17.0 million barrels of
oil and 255.6 Bcf of gas.

PROVED RESERVES

     The following table sets forth estimated year-end net proved reserves for
the three years ended December 31, 1997.
<TABLE>
<CAPTION>
                                               December 31,
                                        --------------------------
                                         1995      1996      1997
                                        -------   -------  -------
                <S>                     <C>       <C>      <C>
                Oil (MBbl)
                       Developed.....     6,955    15,799   14,594
                       Undeveloped...       466     6,676    2,382
                                        -------   -------  -------
                             Total...     7,421    22,475   16,976
                                        =======   =======  =======
 
                Natural gas (MMcf)
                       Developed.....   133,088   242,777  232,058
                       Undeveloped...     5,769    53,882   23,577
                                        -------   -------  -------
                             Total...   138,857   296,659  255,635
                                        =======   =======  =======
 
                Total MMcfe..........   183,383   431,509  357,491
                                        =======   =======  =======
</TABLE>

                                       11
<PAGE>
 
     The following table sets forth for the year ended December 31, 1997, pretax
future net revenues from the production of proved reserves and the pretax
present value discounted at 10% of such revenues, net of estimated future
capital costs, including estimated costs of $19.5 million in 1998.
<TABLE>
<CAPTION>
                                            December 31, 1997
                                    ---------------------------------
                                    Developed  Undeveloped    Total
                                    ---------  ------------  --------
                                             (In thousands)
         <S>                        <C>        <C>           <C>
         1998....................... $ 60,832      $(5,418)  $ 55,414
         1999.......................   55,926       (2,346)    53,580
         2000.......................   51,313       (1,953)    49,360
         Remainder..................  354,696       38,327    393,023
                                     --------      -------   --------
            Total................... $522,767      $28,610   $551,377
                                     ========      =======   ========

         Pretax PW 10% Value (a).... $314,920      $ 5,082   $320,002
                                     ========      =======   ========
</TABLE>
------------------
(a) The after tax present value discounted at 10% of the proved reserves
totaled $276.3 million at year-end 1997.

     The quantities and values in the preceding tables are based on prices in
effect at December 31, 1997, which averaged $17.25 per barrel of oil and $2.35
per Mcf of gas.  Price declines decrease reserve values by lowering the future
net revenues attributable to the reserves and reducing the quantities of
reserves that are recoverable on an economic basis. Price increases have the
opposite effect.  A significant decline in the prices of oil or natural gas
could have a material adverse effect on the Company's financial condition and
results of operations.

     Proved developed reserves are proved reserves that are expected to be
recovered from existing wells with existing equipment and operating methods.
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, 1997.
Subsequent to year-end, oil prices have fallen. The value of the Company's
assets is in part dependent on the prices the Company receives for oil and
natural gas, and a significant decline in the price of oil or gas could have a
material adverse effect on the Company's financial condition and results of
operations. The 10% discount factor used to calculate present value, which is
specified by the Securities and Exchange Commission (the "SEC"), is not
necessarily the most appropriate discount rate, and present value, no matter
what discount rate is used, is materially affected by assumptions as to timing
of future production, which may prove to be inaccurate. For properties operated
by the Company, expenses exclude Patina's share of overhead charges. In
addition, the calculation of estimated future net revenues does not take into
account the effect of various cash outlays, including, among other things
general and administrative costs and interest expense.

     There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. The data in the above tables represent estimates only.
Oil and 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.

                                       12
<PAGE>
 
     The proved oil and natural gas reserves and future revenues as of December
31, 1997 were audited by Netherland, Sewell & Associates Inc. ("NSAI").  Since
January 1, 1997, the Company has filed 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- 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 certain information at December 31, 1997 relating
to the producing wells in which the Company owned a working interest. The
Company also held royalty interests in 195 producing wells at such date. The
Company had 147 wells (144 net) shut in at December 31, 1997. The Company's
average working interest in all wells was 90%. 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>
    Oil.......................................  2,698           2,477
    Natural gas...............................    607             508
                                                -----           -----
           Total..............................  3,305           2,985
                                                =====           =====
</TABLE>

DRILLING RESULTS

     The following table sets forth information with respect to wells drilled by
the Company during the past three years. All the wells were development wells.
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>
                                1995            1996            1997
                                ----            ----            ----
<S>                             <C>             <C>             <C>
Productive
    Gross...................... 25.0            12.0            28.0
    Net........................ 24.1            12.0            28.0
Dry
    Gross......................  0.0             0.0             1.0
    Net........................  0.0             0.0             1.0
</TABLE>

     At December 31, 1997, 3.0 gross (3.0 net) development wells were in
progress.

ACREAGE

     The following table sets forth certain information at December 31, 1997
relating to Wattenberg acreage held by the Company. 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>
                              Gross       Net
                              -----       ---
     <S>                     <C>        <C>
     Developed.............. 175,000    136,000
                             =======    =======

     Undeveloped............  99,000     86,000
                             =======    =======
</TABLE>

                                       13
<PAGE>
 
ITEM 3.  LEGAL PROCEEDINGS
 
     In March 1996, a complaint was filed in the Court of Chancery for the State
of Delaware against Gerrity and each of its directors, Brickell Partners v.
Gerrity Oil & Gas Corporation, C.A. No. 14888 (Del. Ch.). The complaint alleges
that the "action is brought (a) to restrain defendants from consummating the
Gerrity Acquisition which will benefit the holders of Gerrity's common stock at
the expense of the holders of Gerrity's preferred stock and (b) to obtain a
declaration that the terms of the proposed Gerrity Acquisition constitute a
breach of the contractual rights of the preferred." The complaint sought, among
other things, certification as a class action on behalf of all holders of
Gerrity's preferred stock, a declaration that the defendants have committed an
abuse of trust and have breached their fiduciary and contractual duties, an
injunction enjoining the Gerrity Acquisition and money damages. In April 1996,
the defendants were granted an indefinite extension of time in which to answer
the complaint and no answer had been filed by February 1997. In February 1997,
the attorney for the plaintiff filed a Status Report with the court stating
"Case has been mooted. Plaintiff is preparing an application for counsel fees."
No fee application was filed. In November 1997, the plaintiff filed an amended
complaint. The amended complaint realleges the substance of the original
complaint and includes an allegation that the defendants coerced the holders of
the Gerrity preferred stock into exchanging their stock for the 7.125% Preferred
Stock of the Company. The amended complaint also alleges the defendants
participated in a scheme to eliminate the outstanding Gerrity preferred by
forcing the exchange of those shares for shares of the Company's preferred in
October 1996. The amended complaint seeks rescission of the transactions
described in the complaint or money damages if rescission is impractical. On
January 5, 1998, defendants filed a motion to dismiss the amended complaint. No
further action has been taken with respect to the case. Defendants believe that
the amended complaint is without merit and intend to vigorously defend against
this action. At this time, the Company is unable to estimate the range of
potential loss, if any, from this uncertainty. However, the Company believes the
resolution of this uncertainty should not have a material adverse effect upon
the Company's financial position, although an unfavorable outcome in any
reporting period could have a material adverse effect on results for that
period.

     The Company is a party to various other 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

     The following matters were submitted for a vote of security holders during
the fourth quarter of 1997:

     On October 17, 1997, a Special Meeting of the Company's common stockholders
was held.  All four proposals, as summarized below, were voted on and approved
by the shareholders.  For a complete description of the proposals and the vote
tabulation, see Item 4 of the Company's Form 10-Q for the quarter ended,
September 30, 1997.

     (i)    The sale by SOCO of 10.9 million common shares of its Patina stock
            to the public in a secondary offering at $9.875 per share.

     (ii)   The repurchase and retirement by the Company of the remaining 3.0
            million common shares from SOCO at $9.332 per share.

     (iii)  The sale by the Company of $40.0 million of 8.50% convertible
            preferred stock and the issuance of 160,000 common shares to certain
            institutional investors.

     (iv)   The purchase of $3.0 million of common shares issued by the Company
            at $9.875 per share and the grant of 500,000 restricted common
            shares to certain officers and key managers of the Company.

                                       14
<PAGE>
 
                                    PART II

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

     The Company's Common Stock, $12.50 Warrants and 7.125% Preferred Stock are
listed on the New York Stock Exchange ("NYSE") under the symbols "POG", "POGWT"
and "POGPr", respectively. Such listings became effective in May 1996. The 8.50%
Preferred Stock was privately placed and does not trade publicly. 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>
1996
----
 Second Quarter (from May 3, 1996)..  $ 8.25   $6.13   $2.38    $1.25    $24.50      $22.25
 Third Quarter......................    7.38    6.75    1.63     1.00     26.00       23.00
 Fourth Quarter.....................    9.50    7.00    2.38     1.00     30.25       25.50

1997
----
 First Quarter......................   10.50    8.63    2.88     1.50     31.75       29.50
 Second Quarter.....................    9.50    8.00    1.88     1.25     29.75       28.00
 Third Quarter......................    9.94    8.00    2.25     1.13     32.38       27.75
 Fourth Quarter.....................   10.31    6.88    2.56     1.25     33.00       27.50
 
</TABLE>

     On February 20, 1998, the closing prices of the Common Stock, Warrants and
the 7.125% Preferred Stock were $7.00, $1.38 and $28.00, respectively. As of
December 31, 1997, there were approximately 160 holders of record of the common
stock and 16.5 million shares outstanding.

     Dividend Policy. The Board of Directors of the Company declared its first
quarterly dividend on its common stock in the fourth quarter of 1997 at a rate
of one cent per share payable to holders of record on December 15, 1997. The
dividend was paid on December 31, 1997. Prior to the fourth quarter of 1997, the
Company had not declared dividends on its common stock. The Company currently
plans to continue to declare and pay future dividends on its common stock. The
amounts thereof will depend upon the Company's earnings, financial condition,
capital requirements and other factors deemed relevant by the Board of
Directors. Under the terms of its current bank Credit Agreement, the Company, as
of December 31, 1997, has $15.9 million available for dividends it can declare
on its common stock.

                                       15
<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, 1997.  Future results may differ substantially from historical results
because of changes in oil and natural gas prices,  production 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.
Note: The financial statements reflect the Gerrity Acquisition by the Company in
May 1996.
<TABLE>
<CAPTION>
                                                   As of or for the Year Ended December 31,
                                             ----------------------------------------------------
                                               1993       1994       1995       1996       1997
                                             --------   --------   --------   --------   --------
                                                    (In thousands except per share data)
<S>                                          <C>        <C>        <C>        <C>        <C>
STATEMENT OF OPERATIONS DATA
Revenues...................................  $ 64,865   $ 67,822   $ 50,102   $ 83,188   $100,333
Expenses
 Direct operating..........................     8,927      8,110      8,867     14,519     18,790
 Exploration...............................       573        784        416        224        131
 General and administrative................     6,982      7,484      5,974      6,151      7,154
 Interest and other........................     2,362      3,869      5,476     14,304     16,038
 Depletion, depreciation and amortization..    25,190     43,036     32,591     44,822     49,076
 Impairment of oil and gas properties......         -          -          -          -     26,047
                                             --------   --------   --------   --------   --------
   Total expenses..........................    44,034     63,283     53,324     80,020    117,236
                                             --------   --------   --------   --------   --------
Income (loss) before taxes.................    20,831      4,539     (3,222)     3,168    (16,903)
Provision  (benefit ) for income taxes.....     7,291      1,589     (1,128)      (394)         -
                                             --------   --------   --------   --------   --------
Net income (loss)..........................  $ 13,540   $  2,950   $ (2,094)  $  3,562   $(16,903)
                                             ========   ========   ========   ========   ========
   Net income (loss) per
       common share........................     $0.97      $0.21     $(0.15)     $0.08     $(1.11)
                                             ========   ========   ========   ========   ========

Weighted average shares outstanding........    14,000     14,000     14,000     17,796     18,324

Cash dividends per common share............     $0.00      $0.00      $0.00      $0.00      $0.01

BALANCE SHEET DATA
 Current assets............................  $ 14,725   $ 11,083   $  9,611   $ 27,587   $ 31,068
 Oil and gas properties, net...............   181,170    234,821    214,594    398,640    342,833
 Total assets..............................   195,895    246,686    224,521    430,233    376,875
 Current liabilities.......................    23,735     23,838      9,611     26,572     30,297
 Debt......................................    60,857     79,333     75,000    197,594    146,435
 Stockholders' equity......................    92,865    115,846    113,663    196,236    188,441

CASH FLOW DATA
 Net cash provided by operations...........  $ 38,882   $ 47,690   $ 18,407   $ 52,996   $ 68,645
 Net cash used by investing................   (97,573)   (96,378)   (21,060)    (9,796)   (18,801)
 Net cash realized (used) by financing.....    58,691     48,688      2,653    (38,047)   (43,388)
</TABLE>

                                       16
<PAGE>
 
     The following table sets forth unaudited summary financial results on a
quarterly basis for the two most recent years.
<TABLE>
<CAPTION>
                                                              1996
                                            --------------------------------------
                                             First     Second    Third     Fourth
                                            --------  --------  --------  --------
<S>                                         <C>       <C>       <C>       <C>
(In thousands, except per share data)

Revenues................................... $10,654   $19,456   $23,097   $ 29,981
Direct operating expenses..................   1,955     3,446     4,161      4,957
Depletion, depreciation and amortization...   6,967    11,756    13,232     12,867
Net income (loss)..........................    (732)   (1,129)     (669)     6,092
Net income (loss) per common share.........   (0.05)    (0.10)    (0.07)      0.28


                                                              1997
                                            --------------------------------------
                                             First     Second    Third     Fourth
                                            --------  --------  --------  --------
(In thousands, except per share data)

Revenues................................... $29,486   $22,854   $21,703   $ 26,290
Direct operating expenses..................   4,975     4,347     4,185      5,283
Depletion, depreciation and amortization...  12,428    12,348    11,487     12,813
Impairment of oil and gas properties.......       -         -         -     26,047
Net income (loss)..........................   6,256       828       799    (24,786)
Net income (loss) per common share.........    0.29      0.01      0.01      (1.55)
</TABLE>

                                       17
<PAGE>
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS

RESULTS OF OPERATIONS

     In May 1996, the Company acquired Gerrity Oil & Gas Corporation
("Gerrity"). The acquisition was accounted for as a purchase. Accordingly, the
results of operations since the Gerrity Acquisition reflect the impact of the
purchase.

     Comparison of 1997 results to 1996. Total revenues for 1997 increased to
$100.3 million from $83.2 million, representing an increase of 21% from the
prior year. The revenue increase was due to the higher production associated
with the Gerrity Acquisition and improved product prices. Exclusive of the
Gerrity Acquisition, revenues would have decreased. The net loss for 1997 was
$16.9 million compared to net income of $3.6 million in 1996. The net loss was
primarily attributed to the $26.0 million impairment of oil and gas properties.
Exclusive of the non-cash impairment, the Company would have recognized $9.1
million of net income in 1997.

     Average daily production for 1997 was 5,174 barrels and 73.6 MMcf (104.6
MMcfe), increases of 12% and 12%, respectively. The production increases
resulted solely from the Gerrity Acquisition. Exclusive of the Gerrity
Acquisition, average daily production would have declined due to the Company's
limited development schedule and expected initial declines on the large number
of wells drilled and completed in 1994 and early 1995. However, successful
production enhancement and development programs have substantially reduced the
expected decline in production.  There were 28 wells and 102 recompletions and
refracs placed on production in 1997 compared to 12 wells and 90 recompletions
in 1996.  In the future, a decrease in production is expected unless development
activity is substantially increased or acquisitions are consummated. The
decision to increase development activity is heavily dependent on the prices
being received for production.

     Average oil prices decreased from $20.47 per barrel in 1996 to $19.70 in
1997. Average natural gas prices increased from $1.99 per Mcf in 1996 to $2.32
in 1997. The average oil price includes hedging gains in 1997 of $297,000 or
$.16 per barrel.  The increase in average natural gas prices was primarily the
result of the 35% increase in the average CIG index in 1997 from 1996 and the
Company's ability to realize Mid-Continent pricing for a significant portion of
its natural gas production during the winter months.  The average natural gas
price for 1997 includes hedging gains of $2.0 million or $.07 per Mcf.   Direct
operating expenses totaled $18.8 million or $0.49 per Mcfe in 1997 compared to
$14.5 million or $0.43 per Mcfe in the prior year. The increase in operating
expenses was primarily attributed to focusing more attention on enhancing
production through increased well workovers and more effective production
methods and the increase in production taxes as a result of higher average
product prices.

     General and administrative expenses, net of  third party  reimbursements,
for 1997 totaled $7.2 million, a 16% increase from 1996.  The increase was
attributed to the expensing of $2.0 million related to a common stock grant
awarded to the officers and key managers of the Company in October 1997.
Exclusive of the non-cash stock grant expense, general and administrative
expenses declined by $1.0 million or 16%, due to continued efficiencies realized
as a result of the Gerrity Acquisition.  Prior to the Gerrity Acquisition, the
Company did not have its own employees. Employees,  office space, furniture,
fixtures and equipment were provided by SOCO. SOCO allocated estimated general
and administrative expenses to the Company.

     Interest and other expenses were $16.0 million in 1997 compared to $14.3
million in 1996. Interest expense increased as a result of the higher average
outstanding debt levels and interest rates as a result of the Gerrity
Acquisition.  The Company's average interest rate for 1997 was 9.6% compared to
9.3% in the prior year. This increase was due primarily to the 11.75% Senior
Subordinated Notes due July 15, 2004 (the "Notes") assumed by the Company in the
Gerrity Acquisition in May 1996.   These Notes were outstanding for all of 1997
compared to only eight months of 1996.

                                       18
<PAGE>
 
     Depletion, depreciation and amortization expense for 1997 totaled $49.1
million, an increase of $4.3 million or 9% from 1996.  Depletion expense totaled
$46.2 million for 1997 compared to $41.3 million for 1996.  The depletion rate
for 1996 and 1997 averaged $1.21 per Mcfe.  The increase in expense resulted
from higher oil and natural gas production as a result of the Gerrity
Acquisition.   Depreciation and amortization expense for 1997 totaled $2.9
million, or $.08 per Mcfe compared to $3.5 million or $.10 per Mcfe in 1996.
Amortization expense consists primarily of the expensing of a noncompete
agreement entered into as part of the Gerrity Acquisition of $2.6 million in
1996 and $2.5 million in 1997.  In the fourth quarter of 1997, management
determined that the noncompete agreement had no remaining value and expensed the
remaining book value.

     Impairment of oil and gas properties expense for 1997 totaled $26.0
million. The impairment was the result of applying Statement of Financial
Accounting Standards No. 121 ("SFAS 121"), "Accounting for the Impairment of
Long Lived Assets." In applying this statement, the Company determined that the
estimated future cash flows (undiscounted and without interest charges) expected
to result from use of these assets, largely proven undeveloped drilling
locations, and their disposition was less than the carrying amount (book value)
of these assets and, accordingly, recorded an impairment. The impairment
primarily resulted from lower oil and natural gas prices at year-end.

     Comparison of 1996 results to 1995.  Total revenues for 1996 were $83.2
million, an increase of $33.1 million from 1995. The amount represents an
increase of 66% as compared to the prior year period. The revenue increase was
due to the effect of the Gerrity Acquisition, improved product prices in 1996
and includes other revenue of $1.0 million primarily attributable to oil
marketing income. Exclusive of the Gerrity Acquisition, revenues would have
decreased by $3.5 million or 7%. Net income for 1996 was $3.6 million compared
to a net loss of $2.1 million in 1995. The increase in net income was primarily
attributed to a significant increase in average oil and natural gas prices
received, offset by an increase in interest expense and depletion, depreciation
and amortization.

     Average daily production in 1996 was 4,612 barrels and 65.4 MMcf (or 93.1
MMcfe), increases of 26% and 14%, respectively. The production increases
resulted solely from the Gerrity Acquisition. Exclusive of the Gerrity
Acquisition, average daily production would have declined by 1,165 barrels and
18.3 MMcf due to the Company's reduced capital expenditures and expected
production declines on the large number of wells drilled and completed in 1994
and early 1995. There were 88 wells placed on production in 1995 compared to 12
wells in 1996.

     Average oil prices increased to $20.47 per barrel compared to $16.43 in
1995. Average natural gas prices increased from $1.34 per Mcf in 1995 to $1.99
in 1996. The average oil price for 1996 included hedging losses of $841,000 or
$.50 per barrel.  The increase in natural gas prices was primarily the result of
prior year production being marketed under term arrangements which were based on
Rocky Mountain region pricing (which was depressed) whereas the 1996 production
benefited from several factors. A portion of these term arrangements expired
during 1996, which allowed the production to be sold at local spot prices which
had increased as a result of higher demand and declining production in the D-J
Basin. In addition, enhanced marketing efforts combined with higher natural gas
liquids prices contributed to the overall price increase. Direct operating
expenses increased to $14.5 million or $0.43 per Mcfe in 1996 compared to $8.9
million or $0.31 in 1995. The increase in operating expenses was primarily
attributed to the Company's focus on enhancing production through performing
well workovers on existing properties and the overall increase in production
taxes as a result of the higher average oil and natural gas prices.

     General and administrative expenses, net of third party reimbursements, for
1996 were $6.2 million, a 3% increase over 1995. The increase was the result of
the Gerrity Acquisition partially offset by reductions in allocated costs from
SOCO during the first four months of 1996. Prior to the Gerrity Acquisition, the
Company did not have its own employees. Employees,  office space, furniture,
fixtures and equipment were provided by SOCO. SOCO allocated estimated general
and administrative expenses to the Company.

     Interest and other expense was $14.3 million in 1996 compared to $5.5
million in 1995. Interest expense increased as a result of higher average
outstanding debt levels as a result of the Gerrity Acquisition. The Company's
average interest rate for 1996 climbed to 9.3% compared to 7.0% in 1995. This
increase was due primarily to the Notes which were assumed by the Company as
part of the Gerrity Acquisition.

                                       19
<PAGE>
 
     Depletion, depreciation and amortization expense for 1996 totaled $44.8
million, an increase of $12.2 million, or 38% over 1995. The increase resulted
from the higher production and an increased depletion, depreciation and
amortization rate of $1.32 per Mcfe compared to $1.12 in 1995. The primary cause
for the increased rate was a downward revision in reserve quantities due to
proved undeveloped reserves being classified as uneconomic at year-end 1995
prices and the inclusion of the amortization of a noncompete agreement entered
into in conjunction with the Gerrity Acquisition. The amortization of a
noncompete agreement of $2.6 million in 1996 resulted in an increase of $0.08 in
the depletion, depreciation and amortization rate per Mcfe.

DEVELOPMENT, ACQUISITION AND EXPLORATION
 
     During 1997, the Company incurred $19.4 million in capital expenditures.
Development expenditures totaled $17.0 million as the Company has gradually
increased its development activity.   During 1997, the Company successfully
drilled 28 wells, was in the process of drilling an additional three wells at
year end, recompleted 81 wells and refraced 21 wells.  The Company anticipates
incurring development expenditures of approximately $21.0 million in 1998.

FINANCIAL CONDITION AND CAPITAL RESOURCES

     At December 31, 1997, the Company had $376.9 million of assets.  Total
capitalization was $334.9 million, of which 56% was represented by stockholders'
equity, 15% by senior debt and 29% by subordinated debt.  During 1997, net cash
provided by operations was $68.6 million, as compared to $53.0  million in 1996.
As of December 31, 1997, there were no significant commitments for capital
expenditures.  The Company anticipates that 1998 expenditures for development
drilling and recompletion activity will approximate $21.0 million, which, based
on current projections, will allow for a reduction of indebtedness, provide
funds to pursue acquisitions or additional security repurchases.  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
using internal cash flow, proceeds from asset sales and borrowings under its
bank Credit Agreement.  In addition, joint ventures or future public and private
offerings of debt or equity securities may be utilized.

     Prior to May 1996, SOCO financed all of the Company's activities. A portion
of such financing was considered to be an investment by SOCO in the Company with
the remaining portion being considered debt payable to SOCO. In May 1996, the
$75.0 million debt payable to SOCO was repaid in full. The Company does not have
any outstanding debt with SOCO and does not expect SOCO to provide any
additional funding.

     The Company entered into an amended Credit Agreement in April 1997. The
Credit Agreement consists of a revolving credit facility in an aggregate amount
up to $140.0 million. The amount available under the revolving credit facility
is adjusted semiannually and equaled $100.0 million at December 31, 1997, with
$49.0 million outstanding at that time.

     The Credit Agreement contains certain financial covenants, including but
not limited to, a maximum total debt to capitalization ratio, a maximum total
debt to EBITDA ratio, a minimum current ratio and various other negative
covenants that could limit the Company's ability to incur other debt, consummate
acquisitions, dispose of assets, pay dividends or repurchase securities.
Borrowings under the Credit Agreement mature in 2000, 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 of $15.9 million as of
December 31, 1997, which allows the Company to repurchase common stock,
preferred stock and warrants and pay dividends on its common stock.

     The Company had $97.4 million of 11.75% Senior Subordinated Notes due July
15, 2004 outstanding as of December 31, 1997.  The Notes have been reflected in
the accompanying financial statements at a book value of 105.875% of their
principal amount ($92.0 million of principal amount outstanding as of December
31, 1997).  The Notes are redeemable at the option of the Company, in whole or
in part, at any time on or after July 15, 1999 at 105.875% of their principal
amount.  The Notes are unsecured general obligations of the Company and are
subordinated to all senior indebtedness of the Company and to any existing and
future indebtedness of the Company's subsidiaries.

                                       20
<PAGE>
 
     In October 1997, the common shareholders approved each of the proposals to
effectuate a series of transactions which eliminated SOCO's majority ownership
in the Company.  The transactions included: (i) the sale by SOCO of 10.9 million
common shares of its Patina stock to the public in a secondary offering at
$9.875 per share, (ii) the repurchase and retirement by the Company of the
remaining 3.0 million common shares from SOCO at $9.332 per share, (iii) the
sale  by the Company of $40.0 million of 8.50% convertible preferred stock and
the issuance of 160,000 common shares to certain institutional investors and
(iv) the purchase of $3.0 million of common shares issued by the Company at
$9.875 per share and the grant of 496,250 restricted common shares, net of
forfeitures, to certain officers and key managers of the Company.  The stock
grant generally vests over a four year period.  As a result of these
transactions, SOCO no longer has any ownership in the Company.

     The Company from time to time enters 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 of such arrangements, the Company recognized additional
natural gas revenues of $2.0 million, $1.5 million and $1.8 million during 1995,
1996 and 1997, respectively.  These arrangements are expected to increase
revenues through 2002.

     The Company's primary cash requirements will be to finance acquisitions,
development expenditures, repayment of 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 available borrowings under the Credit Agreement
and the Company's cash on hand will be sufficient to cover its working capital,
capital expenditures, planned development activities and debt service
requirements for the next 18 months. In connection with consummating any
significant acquisition, the Company will require additional debt or equity
financing, which 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 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.

                                       21
<PAGE>
 
YEAR 2000 ISSUES

     The Company is aware of the issues associated with the programming code in
many existing computer systems as the millennium approaches. The "Year 2000"
problem is pervasive; virtually every computer operation may be affected in some
way by the rollover of the two digit year value to 00. The risk is that computer
systems will not properly recognize sensitive information when the year changes
to 2000. Systems that do not properly recognize such information could generate
erroneous data or cause a system to fail, resulting in business interruption.

     The Company is currently being provided certain computer processing
services by SOCO through September 1998. The Company is in the process of
purchasing and converting to its own upgraded in-house computer system. In
conjunction with this process, the Company is taking steps to identify, correct
or reprogram and test its existing systems for Year 2000 compliance. It is
anticipated that all new systems, upgrades and reprogramming efforts will be
completed by mid 1998, allowing adequate time for testing. As such, management
believes the Year 2000 issues can be mitigated without a significant potential
effect on the Company's financial position. However, given the complexity of the
Year 2000 issue, there can be no assurance that the Company will be able to
address the problem without costs and uncertainties that might affect future
financial results or cause reported financial information not to be necessarily
indicative of future operating results or future financial condition.

INFLATION AND CHANGES IN PRICES

     While certain of its 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 1996 and 1997. Average price computations exclude hedging gains and
losses and other nonrecurring items to provide comparability. Average prices per
Mcfe indicate the composite impact of changes in oil and natural gas prices. Oil
production is converted to natural gas equivalents at the rate of one barrel per
six Mcf.
<TABLE>
<CAPTION>
                                               Average Prices
                                ------------------------------------------
                                                 Natural        Equivalent
                                   Oil             Gas             Mcf
                                ---------       ---------       ----------
                                (Per Bbl)       (Per Mcf)       (Per Mcfe)
                <S>             <C>             <C>             <C>
                Annual
                ------
                1993........... $15.87            $2.08           $2.22
                1994...........  14.84             1.70            1.94
                1995...........  16.43             1.34            1.73
                1996...........  20.47             1.99            2.41
                1997...........  19.54             2.25            2.55

                Quarterly
                ---------
                1996
                ----
                First.......... $18.31            $1.55           $1.96
                Second.........  20.24             1.60            2.13
                Third..........  19.92             1.83            2.29
                Fourth.........  22.35             2.78            3.07

                1997
                ----
                First.......... $21.79            $2.63           $2.93
                Second.........  19.09             1.85            2.26
                Third..........  18.53             1.92            2.26
                Fourth.........  18.80             2.61            2.76
</TABLE>

                                       22
<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, 1996 and 1997..  F-3
 
 Consolidated Statements of Operations for the years ended
  December 31, 1995, 1996 and 1997.............................  F-4
 
 Consolidated Statements of Changes in Stockholders' Equity
  for the years ended December 31, 1995, 1996 and 1997.........  F-5
 
 Consolidated Statements of Cash Flows for the years ended
  December 31, 1995, 1996 and 1997.............................  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, 1996
and 1997, 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, 1997. 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 generally accepted auditing
standards. 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, 1996 and 1997, and results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.



Fort Worth, Texas,                               ARTHUR ANDERSEN LLP
February 17, 1998

                                      F-2
<PAGE>
 
                         PATINA OIL & GAS CORPORATION

                          CONSOLIDATED BALANCE SHEETS
                                (IN THOUSANDS)
<TABLE> 
<CAPTION> 
                                                               DECEMBER 31,
                                                          --------------------- 
                                                            1996         1997
                                                          ---------   ---------
<S>                                                       <C>         <C>
                                    ASSETS
Current assets
   Cash and equivalents                                   $   6,153   $  12,609
   Accounts receivable                                       19,977      15,307
   Inventory and other                                        1,457       3,152
                                                          ---------   ---------
                                                             27,587      31,068
                                                          ---------   ---------
Oil and gas properties, successful efforts method           559,072     575,508
   Accumulated depletion, depreciation and amortization    (160,432)   (232,675)
                                                          ---------   ---------
                                                            398,640     342,833
                                                          ---------   ---------

Gas facilities and other                                      6,421       5,930
   Accumulated depreciation                                  (4,917)     (3,807)
                                                          ---------   ---------
                                                              1,504       2,123
                                                          ---------   ---------

Other assets, net                                             2,502         851
                                                          ---------   ---------
                                                          $ 430,233   $ 376,875
                                                          =========   =========

                       LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities 
   Accounts payable                                       $  15,063   $  20,451
   Accrued liabilities                                       11,509       9,846
                                                          ---------   ---------
                                                             26,572      30,297
                                                          ---------   ---------

Senior debt                                                  94,500      49,000
Subordinated notes                                          103,094      97,435
Other noncurrent liabilities                                  9,831      11,702

Commitments and contingencies

Stockholders' equity
   Preferred Stock, $.01 par, 5,000,000 shares
      authorized, 1,593,608 and 3,094,363 shares                 
      issued and outstanding                                     16          31 
   Common Stock, $.01 par, 40,000,000 shares
      authorized, 18,886,932 and 16,450,425 shares
      issued and outstanding                                    189         165
   Capital in excess of par value                           194,066     208,525
   Deferred compensation                                         -       (1,828)
   Retained earnings (deficit)                                1,965     (18,452)
                                                          ---------   ---------
                                                            196,236     188,441
                                                          ---------   ---------
                                                          $ 430,233   $ 376,875
                                                          =========   =========
</TABLE> 
 
 The accompanying notes are an integral part of these statements.

                                      F-3
<PAGE>
 
                         PATINA OIL & GAS CORPORATION

                     CONSOLIDATED STATEMENTS OF OPERATIONS
                     (IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE> 
<CAPTION> 
                                                   YEAR ENDED DECEMBER 31,
                                             ----------------------------------- 
                                               1995          1996         1997
                                             --------      --------     -------- 
<S>                                          <C>           <C>          <C> 
Revenues                                      
  Oil and gas sales                          $ 50,073      $ 82,185     $ 99,539
  Other                                            29         1,003          794
                                             --------      --------     -------- 
                                               50,102        83,188      100,333 
                                             --------      --------     -------- 
                                                                                 
Expenses                                                                        
  Direct operating                              8,867        14,519       18,790
  Exploration                                     416           224          131
  General and administrative                    5,974         6,151        7,154
  Interest and other                            5,476        14,304       16,038
  Depletion, depreciation and amortization     32,591        44,822       49,076
  Impairment of oil and gas properties              -             -       26,047
                                             --------      --------     --------
Income (loss) before taxes                     (3,222)        3,168      (16,903)
                                             --------      --------     -------- 
                                                                                
Provision (benefit) for income taxes                                            
  Current                                           -             -            -
  Deferred                                     (1,128)         (394)           -
                                             --------      --------     --------
                                               (1,128)         (394)           -
                                             --------      --------     --------
                                                                                
Net income (loss)                            $ (2,094)     $  3,562     $(16,903)
                                             ========      ========     ======== 
                                                                                
Net income (loss) per common share           $  (0.15)     $   0.08     $  (1.11)
                                             ========      ========     ======== 
                                                                                
Weighted average shares outstanding             14,000       17,796       18,324
                                             =========     ========     ======== 
</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>
 
                                                             
                                        Preferred Stock      Common Stock     Capital in                                 Retained  
                                        ---------------    ---------------    Excess of    Investment     Deferred       Earnings  
                                        Shares   Amount    Shares   Amount    Par Value    By Parent    Compensation    (Deficit)  
                                        ------   ------    ------   ------    ----------   ----------   ------------    ---------  
<S>                                     <C>      <C>       <C>      <C>       <C>          <C>          <C>             <C>        
Balance, December 31, 1994                   -   $    -    14,000   $  140    $       -    $ 115,706    $          -    $       -  
                                                                                                                                   
Credit in lieu of taxes                      -        -         -        -            -        1,107               -            -  
                                                                                                                                   
Change in investment by parent               -        -         -        -            -       (1,196)              -            -  
                                                                                                                                   
Net  loss                                    -        -         -        -            -       (2,094)              -            -  
                                        ------   ------    ------   ------    ---------    ---------    ------------    ---------  
                                                                                                                                   
Balance, December 31, 1995                   -        -    14,000      140            -      113,523               -            -  
                                                                                                                                   
Credit in lieu of taxes                      -        -         -        -            -          171               -            -  
                                                                                                                                   
Change in investment by parent               -        -         -        -            -       (7,514)              -            -  
                                                                                                                                   
Net  loss through the Merger date            -        -         -        -            -         (532)              -            -  
                                                                                                                                   
Merger                                   1,205       12     6,000       60      194,291     (105,648)              -            -  
                                                                                                                                   
Issuance of common                           -        -         4        -           27            -               -            -  
                                                                                                                                   
Repurchase of common and warrants            -        -    (1,117)     (11)      (9,722)           -               -            -  
                                                                                                                                   
Issuance of preferred                      389        4         -        -        9,470            -               -            -  
                                                                                                                                   
Preferred dividends                          -        -         -        -            -            -               -       (2,129) 
                                                                                                                                   
Net income subsequent to the Merger          -        -         -        -            -            -               -        4,094  
                                        ------   ------    ------   ------    ---------    ---------    ------------    ---------  
                                                                                                                                   
Balance, December 31, 1996               1,594       16    18,887      189      194,066            -               -        1,965  
                                                                                                                                   
Repurchase of common and preferred        (126)      (1)   (3,101)     (31)     (32,723)           -               -            -  
                                                                                                                                   
Issuance of common                           -        -       664        7        7,958            -          (1,828)           -  
                                                                                                                                   
Issuance of preferred                    1,600       16         -        -       38,516            -               -            -  
                                                                                                                                   
Preferred dividends and accretion           26        -         -        -          708            -               -       (3,346) 
                                                                                                                                   
Common dividends                             -        -         -        -            -            -               -         (168) 
                                                                                                                                   
Net loss                                     -        -         -        -            -            -               -      (16,903) 
                                        ------   ------    ------   ------    ---------    ---------    ------------    ---------  
                                                                                                                                   
Balance, December 31, 1997               3,094   $   31    16,450   $  165    $ 208,525    $       -    $     (1,828)   $ (18,452) 
                                        ======   ======    ======   ======    =========    =========    ============    =========  
</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,
                                                                           -----------------------------------------------
                                                                             1995               1996                1997
                                                                           --------            -------           ---------
<S>                                                                        <C>                 <C>               <C> 
Operating activities
  Net income (loss)                                                        $ (2,094)           $ 3,562           $ (16,903)     
  Adjustments to reconcile net income (loss) to net                                                                         
    cash provided by operations                                                                                     
      Exploration expense                                                       416                224                 131  
      Depletion, depreciation and amortization                               32,591             44,822              49,076  
      Impairment of oil and gas properties                                        -                  -              26,047  
      Deferred compensation expense                                               -                  -               1,987  
      Deferred taxes                                                         (1,128)              (394)                  -  
      Amortization of deferred credits                                       (2,025)              (605)                  -  
      Gain on sale of other assets                                                -                  -                (338) 
      Changes in current and other assets and liabilities                                                                   
        Decrease (increase) in                                                                                              
          Accounts receivable                                                 1,472             (1,057)              4,548  
          Inventory and other                                                     -                338                (213) 
        Increase (decrease) in                                                                                              
          Accounts payable                                                  (10,902)            (4,249)              5,639  
          Accrued liabilities                                                    77              4,844              (1,248) 
          Other liabilities                                                       -              5,511                 (81) 
                                                                           --------            -------           ---------
      Net cash provided by operations                                        18,407             52,996              68,645
                                                                           --------            -------           ---------
                                                                                                                            
Investing activities                                                                                                        
  Acquisition, development and exploration                                  (21,842)            (8,532)            (19,831)   
  Gerrity Acquisition expenditures, net of cash acquired                          -             (2,375)                  -  
  Sale of oil and gas properties                                                782              1,111               1,030  
                                                                           --------            -------           ---------
      Net cash used by investing                                            (21,060)            (9,796)            (18,801) 
                                                                           --------            -------           ---------
                                                                                                                            
Financing activities                                                                                                        
  Increase (decrease) in payable/debt to SOCO                                 1,011            (80,466)                  -
  Increase (decrease) in indebtedness                                             -             72,863             (51,159) 
  Deferred credits                                                            2,838                814               2,005   
  Decrease in investment by SOCO                                             (1,196)            (7,514)                  -  
  Issuance of preferred stock                                                     -                  -              39,432  
  Issuance of common stock                                                        -                  -               2,795  
  Cost of common stock and preferred issuance                                     -            (11,882)               (900) 
  Repurchase of common stock and warrants                                         -             (9,733)            (28,946) 
  Repurchase of preferred stock                                                   -                  -              (3,809) 
  Preferred dividends                                                             -             (2,129)             (2,638) 
  Common dividends                                                                -                  -                (168) 
                                                                           --------            -------           ---------
      Net cash realized (used) by financing                                   2,653            (38,047)            (43,388)  
                                                                           --------            -------           ---------
                                                                                                                  
Increase in cash                                                                  -              5,153               6,456
Cash and equivalents, beginning of period                                     1,000              1,000               6,153    
                                                                           --------            -------           ---------
Cash and equivalents, end of period                                        $  1,000            $ 6,153           $  12,609    
                                                                           ========            =======           =========
</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 incorporated in January 1996 to hold  the assets and operations
of Snyder Oil Corporation ("SOCO") in the Wattenberg Field and to facilitate the
acquisition of  Gerrity Oil & Gas Corporation ("Gerrity").  Previously, SOCO's
Wattenberg operations had been conducted through SOCO or its wholly owned
subsidiary, SOCO Wattenberg Corporation ("SWAT").  On May 2, 1996, SOCO
contributed the balance of its Wattenberg assets to SWAT and transferred all of
the shares of SWAT to the Company in exchange for 14.0 million common shares of
the Company.  Immediately thereafter, Gerrity merged into another wholly owned
subsidiary of the Company ("Gerrity Acquisition").  As a result of these
transactions, SWAT and Gerrity became subsidiaries of the Company.  In the first
quarter of 1997, Gerrity was merged into the Company.  The Company's operations
currently consist of the acquisition, development, exploitation and production
of oil and natural gas properties in the Wattenberg Field of Colorado's D-J
Basin.

     The above transactions were accounted for as a purchase of Gerrity. The
amounts and results of operations of the Company for periods prior to the
Gerrity Acquisition reflected in these financial statements include the
historical amounts and results of SOCO's Wattenberg operations. Certain amounts
in the accompanying financial statements have been allocated in a reasonable and
consistent manner in order to depict the historical financial position, results
of operations and cash flows of the Company on a stand-alone basis prior to the
Gerrity Acquisition.

     In October 1997, the common shareholders approved each of the proposals to
effectuate a series of transactions which eliminated SOCO's majority ownership
in the Company. The transactions included: (i) the sale by SOCO of 10.9 million
common shares of its Patina stock to the public in a secondary offering at
$9.875 per share, (ii) the repurchase and retirement by the Company of the
remaining 3.0 million common shares from SOCO at $9.332 per share, (iii) the
sale by the Company of $40.0 million of 8.50% convertible preferred stock and
the issuance of 160,000 common shares to certain institutional investors and
(iv) the purchase of $3.0 million of common shares issued by the Company at
$9.875 per share and the grant of 496,250 restricted common shares, net of
forfeitures, to certain officers and key managers of the Company. The stock
grant generally vests over a four year period. As a result of these
transactions, SOCO no longer has any ownership in the Company.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Producing Activities

     The Company utilizes the successful efforts method of accounting for its
oil and natural 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 over the entire Wattenberg Field as the wells are located in the same
reservoirs. No accrual has been provided for estimated future abandonment costs
as management estimates that salvage value will approximate such costs.

                                      F-7
<PAGE>
 
     In 1995, the Company adopted 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 1995 and 1996,
the Company did not provide for any impairments. During 1997, the Company
recorded an impairment of $26.0 million to oil and gas properties based on
discounted cash flows. In applying this statement, the Company determined that
the estimated future cash flows (undiscounted and without interest charges)
expected to result from use of these assets, largely proven undeveloped drilling
locations, and their disposition was less than the carrying amount (book value)
of these assets and accordingly, recorded an impairment. The impairment
primarily resulted from lower year-end oil and natural gas prices. Changes in
the underlying assumptions or the amortization units could result in additional
impairments in the future.

Other Assets

     Other assets reflect the value assigned to a noncompete agreement entered
into as part of the Gerrity Acquisition. The value of this noncompete agreement
had been fully amortized at December 31, 1997. Amortization expense for the
years ended December 31, 1996 and 1997 was $2.6 million and $2.5 million,
respectively. In the fourth quarter of 1997, management determined that there
was no remaining value with respect to this noncompete agreement, and
accordingly, amortized the remaining book value. Included in Other assets is
$850,000 of notes receivable from certain officers and key managers of the
Company. See Note (9).

Section 29 Tax Credits

     The Company from time to time enters 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 of such arrangements, the Company recognized additional
gas revenues of $2.0 million, $1.5 million and $1.8 million during 1995, 1996
and 1997, respectively. These arrangements are expected to increase revenues
through 2002.

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,
1996 and 1997 were insignificant.

Financial Instruments

     The book value and estimated fair value of cash and equivalents was $6.2
million and $12.6 million at December 31, 1996 and 1997. The book value
approximates fair value due to the short maturity of these instruments. The book
value and estimated fair value of the Company's senior debt was $94.5 million
and $49.0 million at December 31, 1996 and 1997. The fair value approximates
book value given its floating rate structure. The book value of the Senior
Subordinated Notes ("Subordinated Notes" or "Notes") was $97.4 million and the
estimated fair value was $100.8 million at December 31, 1997. The fair value of
the Notes is estimated based on their price on the New York Stock Exchange.

     From time to time, the Company enters into commodity contracts to hedge the
price risk of a portion of its production. Gains and losses on such contracts
are deferred and recognized in income as an adjustment to oil and gas sales
revenues in the period in which the physical product to which the contracts
relate, is actually sold.

     In the fourth quarter of 1997, the Company entered into various swap sales
contracts with a weighted average oil price (NYMEX based) of $21.85 for contract
volumes of 46,500 barrels of oil for January 1998. The unrecognized gain on
these contracts totaled $195,000 based on December 31, 1997 market values. The
Company realized $238,000 of income related to these swap contracts based on
settlements after year end.

                                      F-8
<PAGE>
 
     In the fourth quarter of 1997, the Company entered into various CIG and
PEPL index based swap sales contracts for the first quarter of 1998. The
weighted average natural gas price for the CIG index based contracts is $2.19
for contract volumes of 332,000 MMBtu's of natural gas and for the PEPL index
based contracts is $2.60 for contract volumes of 1,151,000 MMBtu's of natural
gas. The unrecognized gains on these contracts totaled $701,000 based on
December 31, 1997 market values. The Company estimates realizing $658,000 of
income related to these swap contracts based on settlements after year-end and
market values as of February 17, 1998.

     In the first quarter of 1998, the Company entered into various additional
CIG and PEPL index based swap sales contracts for March 1998 through August
1998. The weighted average natural gas price for the CIG index based contracts
is $1.70 for contract volumes of 1,840,000 MMBtu's of natural gas and for the
PEPL index based contracts is $2.19 for contract volumes of 1,215,000 MMBtu's of
natural gas.

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 $2.0
million of non-cash general and administrative expenses in 1997.

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 are also included in the
calculation of diluted per share data if their effect is dilutive.

Supplemental Cash Flow Information

     The Company incurred the following significant non-cash items in 1997:
<TABLE>
<CAPTION>
                                                                                     (In thousands)
     <S>                                                                             <C>       
     Stock grant awarded to certain officers and key managers........................   $  3,821
     Dividends and accretion - 8.50% preferred stock.................................        708  
     401(k) profit sharing in common stock...........................................        453
</TABLE> 
 
The Company incurred the following significant non-cash items related to the
 Gerrity Acquisition in 1996:
<TABLE>
<CAPTION>
                                                                                     (In thousands)
     <S>                                                                             <C>
     Cash payments made for the acquisition..........................................   $ 14,257
     Senior debt assumed.............................................................     19,000
     Subordinated debt assumed.......................................................    105,805
     Minority interest in Gerrity preferred stock not exchanged at acquisition date..      9,878
     Preferred stock issued..........................................................     30,122
     Common stock and warrants issued................................................     46,750
     Other liabilities assumed.......................................................     12,423
                                                                                        --------
     Fair value of assets acquired...................................................   $238,235
                                                                                        ========
</TABLE>

     The above cash payments made include approximately $4.9 million of costs
capitalized and allocated to oil and gas properties. The above cash payments are
reduced in the accompanying consolidated statements of cash flows by $2.1
million for cash acquired in the Gerrity Acquisition.

Gas facilities and other

     Depreciation of gas gathering and transportation facilities is provided
using the straight-line method over the estimated useful life of 10 years.
Equipment is depreciated using the straight-line method with estimated useful
lives ranging from three to five years.

                                      F-9
<PAGE>
 
Risks and Uncertainties

     Historically, the market for oil and natural gas has experienced
significant price fluctuations. Prices for natural gas in the Rocky Mountain
region have traditionally been volatile, particularly since 1994. In large part,
the price fluctuations can result from variations in weather, levels of
production in the region and availability of transportation capacity to other
regions of the country. Increases or decreases in prices received could have a
significant impact on the Company's future results of operations.

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 current
classification.

     All cash payments for income taxes were made by SOCO during 1995 and
through May 2, 1996, at which point the Company began paying its own taxes. The
Company was charged interest by SOCO on its debt of $5.4 million and $1.6
million during 1995 and through May 2, 1996, which was reflected as an increase
in debt to SOCO.

     The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiaries. 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.

(3)  OIL AND GAS PROPERTIES

     The cost of oil and gas properties at December 31, 1995, 1996 and 1997,
includes no significant unevaluated leasehold. Acreage is generally held for
exploration, development or resale and its value, if any, is excluded from
amortization. The following table sets forth costs incurred related to oil and
gas properties:
<TABLE>
<CAPTION>
                                    1995       1996       1997
                                  --------   --------   -------
                                         (IN THOUSANDS)
         <S>                       <C>       <C>        <C>
 
         Acquisition............   $   650   $218,380   $ 2,225
         Development............    12,141      8,301    17,013
         Exploration and other..       429        224       131
                                   -------   --------   -------
                                   $13,220   $226,905   $19,369
                                   =======   ========   =======
</TABLE>

     In May 1996, the Gerrity Acquisition discussed in Note 1 was consummated.
The following table summarizes the unaudited pro forma effects on the Company's
financial statements assuming that the Gerrity Acquisition and the Original
Exchange Offer had been consummated on January 1, 1995 and 1996. Future results
may differ substantially from pro forma results due to changes in these
assumptions, changes in oil and natural gas prices, production declines and
other factors. Therefore, pro forma statements cannot be considered indicative
of future operations (in thousands, except per share data).
<TABLE>
<CAPTION>
                                                         YEAR ENDED DECEMBER 31,
                                                         -----------------------
                                                           1995           1996
                                                         --------       --------
         <S>                                             <C>            <C>
         Total revenues................................  $103,962       $100,138
         Gross operating margin........................    85,654         82,420
         Depletion, depreciation and amortization......    63,383         51,662
         Net income (loss).............................    (7,338)         3,476
         Net income (loss) per common share............  $  (0.51)      $   0.03
         Weighted average shares outstanding...........    20,000         19,796

</TABLE>

                                      F-10
<PAGE>
 
(4)  INDEBTEDNESS

     The following indebtedness was outstanding on the respective dates:
<TABLE>
<CAPTION>
                                              DECEMBER 31,
                                        -----------------------
                                          1996            1997
                                        --------        -------
                                           (IN THOUSANDS)
         <S>                            <C>             <C>
         Bank facilities............... $ 94,500        $49,000
         Less current portion..........        -              -
                                        --------        -------

         Senior debt, net.............. $ 94,500        $49,000
                                        ========        =======

         Subordinated notes............ $103,094        $97,435
                                        ========        =======
</TABLE>

     In April 1997, the Company entered into an amended bank Credit Agreement
(the "Credit Agreement"). The Credit Agreement is a revolving credit facility in
an aggregate amount up to $140.0 million. The amount available under the
facility is adjusted semiannually and equaled $100.0 million at December 31,
1997, with $49.0 million outstanding at that time.

     The Company may elect that all or a portion of the credit facility bear
interest at a rate equal to: (i) the higher of (a) prime rate plus a margin
equal to 0.25% (the "Applicable Margin") or (b) the Federal Funds Effective Rate
plus .5% plus the Applicable Margin, 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
0.625% to 1.125%, determined by a debt to EBITDA ratio. During 1997, the average
interest rate under the facility approximated 6.8%.

     The Credit Agreement contains certain financial covenants, including but
not limited to, a maximum total debt to capitalization ratio, 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 2000, 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 of $15.9 million as of December 31, 1997, which
allows the Company to repurchase common stock, preferred stock and warrants and
pay dividends on its common stock.

     In conjunction with the Gerrity Acquisition, the Company assumed $100
million of 11.75% Senior Subordinated Notes due July 15, 2004 issued by Gerrity
in 1994. Under purchase accounting, the Notes have been reflected in the
accompanying financial statements at a book value of 105.875% of their principal
amount. Interest is payable each January 15 and July 15. The Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after July 15, 1999, initially at 105.875% of their principal amount, declining
to 102.938% on or after July 15, 2000, and declining to 100% on or after July
15, 2001. Upon a change of control, as defined in the Notes, the Company is
obligated to make an offer to purchase all outstanding Notes at a price of 101%
of the principal amount thereof. In addition, the Company would be obligated,
subject to certain conditions, to make offers to purchase the Notes with the net
cash proceeds of certain asset sales or other dispositions of assets at a price
of 101% of the principal amount thereof. Subsequent to the Gerrity Acquisition,
the Company repurchased and retired $8.0 million of the Notes, resulting in
$92.0 million of principal amount of Notes outstanding, or a book value of $97.4
million in the accompanying financial statements. The Notes are unsecured
general obligations of the Company and are subordinated to all senior
indebtedness of the Company and to any existing and future indebtedness of the
Company's subsidiaries.

                                      F-11
<PAGE>
 
     The Notes contain covenants that, among other things, limit the ability of
the Company to incur additional indebtedness, pay dividends, engage in
transactions with shareholders and affiliates, create liens, sell assets, engage
in mergers and consolidations and make investments in unrestricted subsidiaries.
Specifically, the Notes restrict the Company from incurring indebtedness
(exclusive of the Notes) in excess of approximately $51.0 million, if after
giving effect to the incurrence of such additional indebtedness and the receipt
and application of the proceeds therefrom, the Company's interest coverage ratio
is less than 2.5:1 or adjusted consolidated net tangible assets is less than
150% of the aggregate indebtedness of the Company. The Company currently meets
these ratios and accordingly, is not limited in its ability to incur additional
debt.

     Prior to the Gerrity Acquisition, SOCO financed all of the Company's
activities. A portion of such financing was considered to be an investment by
SOCO in the Company with the remaining portion being considered debt payable to
SOCO. The portion considered to be debt to SOCO versus an investment by SOCO
was a discretionary percentage determined by SOCO after consideration of the
Company's internally generated cash flows and level of capital expenditures.
Subsequent to the Gerrity Acquisition, the $75.0 million debt to SOCO was repaid
in full and the Company does not expect SOCO to provide any additional funding.

     On the portion of such financing which was considered to be debt to parent,
SOCO charged interest at a rate which approximated the average interest rate
being paid by SOCO under its revolving credit facility ( 7.0% and 6.9% for 1995
and the four month period ended May 2, 1996, respectively).

     Scheduled maturities of indebtedness for the next five years are zero for
1998 and 1999 and $49.0 million in 2000, and zero in 2001 and  2002. The long-
term portions of the credit facilities are scheduled to expire in 2000.  It is
management's intent to review both the short-term and long-term facilities and
extend the maturities on a regular basis; however, there can be no assurance
that the Company will be able to do so.

     There were no cash payments for interest expense in 1995 or in the first
four months of 1996. Cash payments for interest totaled $10.5 million in the
eight months ended December 31, 1996, and $16.5 million in 1997.


(5)  STOCKHOLDERS' EQUITY

     A total of 40.0 million common shares, $.01 par value, are authorized of
which 16.5 million were issued and outstanding at December 31, 1997.  The
Company issued 6.0 million common shares and 3.0 million five year common stock
warrants exercisable at $12.50 (which expire in May 2001), in exchange for all
of the outstanding stock of Gerrity upon consummation of the Gerrity
Acquisition.  Subsequent to the acquisition date, the Company has repurchased
4,217,200 shares of common stock (including the 3.0 million common shares
repurchased from SOCO in conjunction with the redistribution of SOCO's majority
ownership in October 1997), 125,682 shares of 7.125% preferred stock,  500,000
warrants issued to Gerrity's former chief executive officer, and 80,549 five
year common stock warrants for total consideration of $42.5 million.  Prior to
the fourth quarter of 1997, no dividends had been paid on common stock.  A cash
dividend of one cent per common share was declared and paid in December 1997.

     A total of 5.0 million preferred shares, $.01 par value, are authorized. At
December 31, 1997, the Company had two separate issues of preferred stock
outstanding consisting of 1,467,926 shares of 7.125% preferred and 1,626,437
shares of 8.50% preferred.

                                      F-12
<PAGE>
 
     In May 1996, 1.2 million shares of the Company's 7.125% preferred stock
were issued to certain Gerrity preferred shareholders electing to exchange their
preferred shares (the "Original Exchange Offer"). Thus there were no proceeds
received related to this issuance. In October 1996, Gerrity's certificate of
incorporation was amended to provide that all shares of Gerrity's preferred
stock not exchanged in the Original Exchange Offer be exchanged for the
Company's 7.125% preferred shares on the same terms as the Original Exchange
Offer. This exchange resulted in the issuance of an additional 389,000 preferred
shares. The stock is convertible into common stock at any time at $8.61 per
share, or 2.9036 common shares. The 7.125% preferred stock pays quarterly cash
dividends, when declared by the Board of Directors, based on an annual rate of
$1.78 per share. The 7.125% preferred stock is redeemable at the option of the
Company at any time after May 2, 1998 if the average closing price of the Patina
common stock for 20 of the 30 days prior to not less than five days preceding
the redemption date is greater than $12.92 per share or at any time after May 2,
1999. The liquidation preference is $25 per share, plus accrued and unpaid
dividends. As of December 31, 1997, there were 1,467,926 preferred shares
outstanding with a liquidation preference of $36.7 million. The 7.125% preferred
stock is listed on the New York Stock Exchange. Holders of the 7.125% preferred
stock are not generally entitled to vote, except with respect to certain limited
matters. The Company paid $2.1 million and $2.6 million ($1.78 per 7.125%
convertible preferred share per annum) in preferred dividends during the years
ended December 31, 1996 and 1997, and had accrued an additional $354,000 and
$327,000 at December 31, 1996 and 1997, respectively, for dividends.

     In October 1997, 1.6 million shares of 8.50% preferred stock and 160,000
common shares were issued to a private group of investors for $40.0 million.
Each member of the private group of investors has agreed not to sell, transfer
or dispose of any shares of the 8.50% preferred prior to  October 22, 1999.  The
stock is convertible into common stock at any time at $9.50 per share or 2.6316
common shares.  The 8.50 % preferred stock pays quarterly dividends, when
declared by the Board of Directors, and are payable in-kind ("PIK Dividend")
until the fourth quarter of 1999, and payable in cash thereafter.  The 8.50%
preferred stock is redeemable at the option of the Company at any time after
October 22, 2000 at 106% of its stated value declining by 2% per annum
thereafter.  The liquidation preference is $25 per share, plus accrued and
unpaid dividends.  As of December 31, 1997, there were 1,626,437 preferred
shares outstanding with a liquidation preference of $40.7 million.  The 8.50%
preferred is privately held and not listed on a public stock exchange.  Holders
of the 8.50% preferred are entitled to vote their shares of preferred stock with
the common stock, based upon the number of shares of common stock into which the
shares of preferred stock are convertible. The Company paid $661,000 in PIK
Dividends (issued 26,400 8.50% preferred shares) during the quarter  ended
December 31, 1997.

     The Company adopted Statement of Financial Accounting Standards No. 128
("SFAS 128"), "Earnings per Share" during 1997.  SFAS 128 specifies computation,
presentation and disclosure requirements for earnings per share for entities
with publicly held common stock or potential common stock.  All prior period
earnings per share amounts have been restated in accordance with SFAS 128.

     In accordance with SFAS 128, the Company computed the net income (loss) per
share by dividing the net income (loss), less dividends and accretion on
preferred stock, by the weighted average common shares outstanding during the
period. Net income (loss) applicable to common for 1995, 1996, and 1997, was
($2,094,000), $1,433,000 and ($20,249,000), respectively.

     Diluted net income (loss) per share was computed by dividing the net income
(loss), less dividends and accretion on preferred stock, by weighted average
common shares outstanding during the period and all dilutive potential shares
outstanding (zero for 1995, 1996, and 1997, respectively).  The 7.125% and 8.50%
preferred stock potential common stock equivalents and $12.50 common stock
warrants and stock options were anti-dilutive for all periods presented.  Net
income (loss) per common share and diluted net income (loss) per common share
were the same for all periods presented.

                                      F-13
<PAGE>
 
(6)  EMPLOYEE BENEFIT PLANS

401(k) Savings

     The Company has a 401(k) profit sharing and savings plan (the "401(k)
Plan"). The initial 401(k) Plan was established in May 1996 and in conjunction
with the sale of SOCO's majority ownership of the Company in October 1997, a new
plan was adopted effective January 1, 1997. 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 has historically made profit sharing contributions to the 401(k) Plan,
which totaled $281,000 and $453,000 for 1996 and 1997, respectively. The 1997
profit sharing contribution was made in shares of the Company's common stock
(59,901 shares).

Stock Purchase Plan

     In January 1998, the Company adopted a stock purchase plan ("Stock Purchase
Plan").  Pursuant to the Stock Purchase Plan, certain officers, directors and
key managers of the Company are eligible to purchase shares of the Company's
common stock at prices ranging from 50% to 85% of the closing price of the stock
on the trading day prior to the date the stock is purchased ("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.  The Stock Purchase Plan has reserved 500,000 shares of common stock for
possible purchase under the plan.  The Board of Directors has approved 137,500
common shares available to participants for purchase at 75% of the Closing Price
during the current Plan Year as defined in the Stock Purchase Plan.

Stock Option and Award Plans

     In 1996, the shareholders adopted a stock option plan for employees
providing for the issuance of options at prices not less than fair market value.
Options to acquire up to three million shares of common stock 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 total of 512,000
options were issued in May 1996, with an exercise price of $7.75 per common
share, and 271,000 options were issued in February 1997, with an exercise price
of $9.25 per common share. The options vest over a three-year period (30%, 60%,
100%) and expire five years from date of grant. In addition, 250,000 fully
vested five year options were granted in October 1997 at an exercise price of
$9.875.

     In 1996, the shareholders adopted a stock grant and option plan (the
"Directors' Plan") for nonemployee Directors of the Company.  The Directors'
Plan provides for each nonemployee Director to receive common shares having a
market value equal to $2,250 quarterly in payment of one-half their retainer.  A
total of 3,632 shares were issued  in 1996, and 4,512 shares were issued in
1997.  It also provides for 5,000 options to be granted annually to each
nonemployee Director.  A total of 20,000 options were issued in May 1996, with
an exercise price of $7.75 per common share and 20,000 options were issued in
May 1997, with an exercise price of $8.625.  In addition, 10,000 options were
issued in October 1997 with an exercise price of $10.313.  The options vest over
a three-year period (30%, 60%, 100%) and expire five years from date of grant.

     In October 1997, the shareholders approved a stock grant and purchase plan
for certain officers and key managers ("Management Investors") of the Company.
The plan, which was amended effective December 31, 1997, provided for the grant
of 496,250 restricted common shares, net of forfeitures, to the Management
Investors.  These shares will vest at 25% per year on January 1, 1998, 1999,
2000 and 2001.  The Company recognized $2.0 million of non-cash general and
administrative expenses in 1997 with respect to the stock grant.  The non-vested
granted common shares have been recorded as Deferred compensation in the equity
section of the accompanying consolidated balance sheets.  The Management
Investors also purchased $3.0 million of common shares from the Company at
$9.875 per share (303,797 shares).  A portion of this purchase ($850,000) was
financed by the Company.  See Note (9).

                                      F-14
<PAGE>
 
     At December 31, 1997, 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:
<TABLE>
<CAPTION>
 
                                         1996             1997
                                        ------          --------
<S>                     <C>             <C>             <C>
 
Net income (loss)       As Reported     $3,562          $(16,903)
                        Pro forma        3,281           (18,611)
 
Net income (loss)
    per common share    As Reported     $ 0.08          $  (1.11)
                        Pro forma         0.06             (1.20)
</TABLE>

     The fair value of each option grant is estimated on the date of grant using
the Black-Sholes option-pricing model with the following weighted-average
assumptions used for grants in 1996 and 1997: dividend yield of 0% and 0%;
expected volatility of 30% and 35%; risk-free interest rate of 6.4% and 6.0%;
and expected life of 4.5 years and 4.5 years, respectively.

     A summary of the status of the Company's fixed stock option plan as of
December 31, 1996 and 1997 and changes during the years are presented below:
<TABLE>
<CAPTION>
                                                             1996                           1997
                                                --------------------------------  ------------------------
                                                                Weighted-Average  Weighted-Average
                                                                    Exercise          Exercise
                                                Shares               Price             Shares       Price
                                                -------         ----------------  ----------------  -----
        <S>                                     <C>             <C>               <C>               <C>
        Outstanding at beginning of year......        -         $        -             503,000      $7.75
        Granted...............................  532,000               7.75             551,000       9.53
        Exercised.............................        -                  -             (12,000)      7.75
        Forfeited.............................  (29,000)              7.75             (41,000)      8.38
                                                -------                              ---------
        Outstanding at end of year............  503,000         $     7.75           1,001,000      $8.70
                                                =======                              =========

        Options exercisable at year-end.......        -                                389,000
                                                                                     =========

        Weighted-average fair value of
         options granted during the year......                  $     2.81                          $3.84
</TABLE>
 
     The following table summarizes information about fixed stock options
outstanding at December 31, 1997:
<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                     1997       Contractual Life Exercise Price       1997      Exercise Price
--------------                 -------------- ---------------- -------------- --------------  --------------
<S>                            <C>            <C>              <C>            <C>            <C> 
$ 7.75 to 9.25                     741,000      3.6 years        $ 8.29          139,000         $ 7.75
  9.88 to 10.31                    260,000      4.8 years          9.89          250,000           9.88
                                ----------                                      --------
$ 7.75 to 10.31                  1,001,000      3.9 years        $ 8.70          389,000         $ 9.11
                                ==========                                      ========
</TABLE>

                                      F-15
<PAGE>
 
(7)  FEDERAL INCOME TAXES

     Prior to the Gerrity Acquisition, the Company had been included in the
consolidated tax return of SOCO. Current and deferred income tax provisions
allocated by SOCO were determined as though the Company filed as an independent
company, making the same tax return elections used in SOCO's consolidated
return.  Subsequent to the Gerrity Acquisition, the Company is no longer
included in the tax return of SOCO.
 
     A reconciliation of the statutory rate to the Company's effective rate as
they apply to the provision (benefit) for the years ended December 31, 1995,
1996 and 1997 follows:
<TABLE>
<CAPTION>
 
                                                            1995    1996    1997
                                                           -----   -----   -----
<S>                                                        <C>     <C>     <C>
 
Federal statutory rate...................................  (35%)    35%    (35%)
Utilization of net deferred tax asset....................     -    (35%)      -
Increase in valuation allowance..........................     -       -     35%
Tax benefit recognized prior to the Gerrity Acquisition..     -    (12%)      -
                                                           ----    ----    ----
Effective income tax rate................................  (35%)   (12%)      -
                                                           ====    ====    ====
</TABLE>
     For book purposes the components of the net deferred asset and liability at
December 31, 1996 and 1997, respectively, were:
<TABLE>
<CAPTION>
                                                  1996            1997
                                                -------         --------
                                                     (IN THOUSANDS)
<S>                                             <C>             <C>
Deferred tax assets
  NOL carryforwards............................ $24,586         $ 30,497
  Production payment receivables and other.....  27,382           25,939
                                                -------         --------
                                                 51,968           56,436
                                                -------         --------
Deferred tax liabilities
  Depreciable and depletable property..........  48,145           44,782
  Investments and other........................       -                -
                                                -------         --------
                                                 48,145           44,782
                                                -------         --------

Deferred tax assets............................   3,823           11,654
                                                -------         --------

Valuation allowance............................  (3,823)         (11,654)
                                                -------         --------

Net deferred tax asset......................... $     -         $      -
                                                =======         ========
</TABLE>

     For tax purposes, the Company had regular net operating loss carryforwards
of $87.1 million and alternative minimum tax ("AMT") loss carryforwards of $51.2
million at December 31, 1997. Utilization of the regular and AMT net operating
loss carryfowards 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 $31.9 million regular net operating
loss carryforwards and $31.6 million AMT loss carryforwards will be limited to
$5.2 million per year as a result of the Gerrity Acquisition in May 1996. These
carryforwards expire from 2006 through 2011. At December 31, 1997, the Company
had alternative minimum tax credit carryforwards of $447,000 which are available
indefinitely. No cash payments were made by the Company for federal taxes during
1996 and 1997.

                                      F-16
<PAGE>
 
(8)  MAJOR CUSTOMERS

     During 1996 and 1997, Duke Energy Field Services, Inc. accounted for 38%
and 41% of revenues. During 1995, 1996 and 1997, Amoco Production Company
accounted for 22%, 19% and 16%, subsidiaries of SOCO accounted for 46%, 0% and
0%, and Total Petroleum accounted for 20%, 10% and 8%, 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

     Prior to the Gerrity Acquisition, the Company did not have its own
employees. Employees, certain office space and furniture, fixtures and equipment
were provided by SOCO. SOCO allocated general and administrative expenses to the
Company based on its estimate of expenditures incurred on behalf of the Company.
Subsequent to the Gerrity Acquisition, certain field, administrative and
executive employees of SOCO and Gerrity became employees of the Company. SOCO
will continue to provide certain services to Patina under a corporate services
agreement through September 1998. During 1996 and 1997, the Company paid
approximately $650,000 and $1.5 million to SOCO under the corporate services
agreement.

     In conjunction with the transactions entered into with SOCO in October 1997
which redistributed their majority ownership of the Company, certain officers
and key managers purchased $3.0 million of common shares at $9.875 per share
(303,797 shares) from the Company.  A portion of this purchase ($850,000) was
financed by the Company through the issuance of  8.50% recourse notes.  These
notes are secured by the common stock purchased (101,265 shares) and additional
common shares granted  (146,250 shares) to the respective officers and key
managers.  Interest is due annually and the notes are scheduled to mature on
January 2, 2001. These notes have been reflected as Other assets in the
accompanying consolidated balance sheets.

                                      F-17
<PAGE>
 
(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
$500,000 per year from 1998 through 2002.
 
     In March 1996, a complaint was filed in the Court of Chancery for the State
of Delaware against Gerrity and each of its directors, Brickell Partners v.
Gerrity Oil & Gas Corporation, C.A. No. 14888 (Del. Ch.).  The complaint alleges
that the "action is brought (a) to restrain defendants from consummating the
Gerrity Acquisition which will benefit the holders of Gerrity's common stock at
the expense of the holders of Gerrity's preferred stock and (b) to obtain a
declaration that the terms of the proposed Gerrity Acquisition constitute a
breach of the contractual rights of the preferred."  The complaint sought, among
other things, certification as a class action on behalf of all holders of
Gerrity's preferred stock, a declaration that the defendants have committed an
abuse of trust and have breached their fiduciary and contractual duties, an
injunction enjoining the Gerrity Acquisition and money damages.  In April 1996,
the defendants were granted an indefinite extension of time in which to answer
the complaint and no answer had been filed by February 1997.  In February 1997,
the attorney for the plaintiff filed a Status Report with the court stating
"Case has been mooted.  Plaintiff is preparing an application for counsel fees."
No fee application was filed.  In November 1997, the plaintiff filed an amended
complaint.  The amended complaint realleges the substance of the original
complaint and includes an allegation that the defendants coerced the holders of
the Gerrity preferred stock into exchanging their stock for the 7.125% Preferred
Stock of the Company.  The amended complaint also alleges the defendants
participated in a scheme to eliminate the outstanding Gerrity preferred by
forcing the exchange of those shares for shares of the Company's preferred in
October 1996.  The amended complaint seeks rescission of the transactions
described in the complaint or money damages if rescission is impractical.  On
January 5, 1998, defendants filed a motion to dismiss the amended complaint.  No
further action has been taken with respect to the case.  Defendants believe that
the amended complaint is without merit and intend to vigorously defend against
this action.  At this time, the Company is unable to estimate the range of
potential loss, if any, from this uncertainty.  However, the Company believes
the resolution of this uncertainty should not have a material adverse effect
upon the Company's financial position, although an unfavorable outcome in any
reporting period could have a material adverse effect on results for that
period.
 
     The Company is a party to various other lawsuits incidental to its
business, none of which are anticipated to have a material adverse impact on its
financial position or results of operations.

                                      F-18
<PAGE>
 
(11) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

     Independent petroleum consultants directly evaluated total proved reserves
at December 31, 1995 and 1996 and audited total proved reserves at December 31,
1997. 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 above. 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, 1994.........................  12,218          178,703
      Revisions.......................................  (3,609)         (19,618)
      Extensions, discoveries and additions...........     154              785
      Production......................................  (1,342)         (20,981)
      Purchases.......................................       -                -
      Sales...........................................       -              (32)
                                                        ------          -------

   Balance, December 31, 1995.........................   7,421          138,857
      Revisions.......................................     720           (1,314)
      Extensions, discoveries and additions...........     194            1,342
      Production......................................  (1,688)         (23,947)
      Purchases.......................................  15,834          183,729
      Sales...........................................      (6)          (2,008)
                                                        ------          -------

   Balance, December 31, 1996.........................  22,475          296,659
      Revisions (a)...................................  (4,418)         (27,671)
      Extensions, discoveries and additions...........     784           11,162
      Production......................................  (1,889)         (26,863)
      Purchases.......................................     101            3,193
      Sales...........................................     (77)            (845)
                                                        ------          -------

   Balance, December 31, 1997.........................  16,976          255,635
                                                        ======          =======
</TABLE>
 
PROVED DEVELOPED RESERVES
<TABLE> 
<CAPTION> 
                                                          OIL         NATURAL GAS
                                                          ---         -----------
                                                        (MBBL)          (MMCF)
<S>                                                    <C>            <C>  
December 31, 1994.....................................   8,832          147,869
                                                       =======        =========
December 31, 1995.....................................   6,955          133,088
                                                       =======        =========
December 31, 1996.....................................  15,799          242,777
                                                       =======        =========
December 31, 1997.....................................  14,594          232,058
                                                       =======        =========
</TABLE> 
(a) Revisions consist primarily of 4,060 MBbl's and 31,232 MMcf's attributable
to proved undeveloped drilling locations and proved developed non-producing
zones (behind-pipe recompletions) determined to be uneconomic using the lower
oil and natural gas prices in effect at December 31, 1997.

                                      F-20
<PAGE>
 
STANDARDIZED MEASURE
<TABLE>  
<CAPTION>                                                             
                                                            DECEMBER 31,
                                           ---------------------------------------------
                                             1995              1996              1997
                                           --------         ----------          -------- 
                                                           (IN THOUSANDS)
<S>                                        <C>              <C>                 <C>
Future cash inflows                        $356,224         $1,668,475          $894,390
Future costs                                    
 Production..............................  (100,505)          (338,752)         (255,599)
 Development.............................   (13,428)          (160,856)          (87,414)
                                           --------         ----------          --------                  
Future net cash flows....................   242,291          1,168,867           551,377    
Undiscounted income taxes.............      (29,873)          (294,407)          (89,094)  
                                           --------         ----------          --------                  
After tax net cash flows..............      212,418            874,460           462,283   
10% discount factor......................   (84,902)          (374,524)         (185,953)    
                                           --------         ----------          -------- 
Standardized measure.....................  $127,516         $  499,936          $276,330
</TABLE> 
 
CHANGES IN STANDARDIZED MEASURE
<TABLE> 
<CAPTION> 
                                                         YEAR ENDED DECEMBER 31,
                                                -----------------------------------------
                                                  1995            1996             1997
                                                --------        --------         -------- 
                                                             (IN THOUSANDS)
<S>                                             <C>             <C>             <C>  
Standardized measure, beginning of year..       $161,481        $127,516        $ 499,936
Revisions:                                          
  Prices and costs.......................          2,240         351,724         (312,526)  
  Quantities.............................        (14,230)            501            6,134
  Development costs......................         (1,182)        (11,024)         (14,783)                        
  Accretion of discount..................         16,148          27,619           49,994 
  Income taxes...........................         10,963        (129,612)         105,189 
  Production rates and other.............        (21,265)         (3,706)          (8,433)       
                                                --------        --------         -------- 
  Net revisions..........................         (7,326)        235,502         (174,425)
Extensions, discoveries and additions....          2,064           3,791           11,756
Production...............................        (40,877)        (67,666)         (81,149)
Future development costs incurred........         12,192           7,906           17,013
Purchases (a)............................              -         193,998            3,900
Sales (b)................................            (18)         (1,111)            (701)
                                                --------        --------         -------- 
Standardized measure, end of year........       $127,516        $449,936         $276,330 
                                                ========        ========         ========
</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 -
<TABLE> 
<CAPTION> 
     <C>     <S> 
     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)

     4.1     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)

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

     4.3     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  Amended and Restated Credit Agreement dated April 1, 1997 by and among the Company, as Borrower, and Texas Commerce
             Bank National Association, as Administrative Agent, and certain commercial lending institutions. (Incorporated herein
             by reference to Exhibit 10.1.5 of the Company's Form 10-Q for the quarter ended March 31, 1997.)

     10.1.2  First Amendment to the Amended and Restated Credit Agreement effective May 1, 1997 by and among the Company, as
             Borrower, and Texas Commerce Bank National Association, as Administrative Agent, and certain commercial lending
             institutions. (Incorporated herein by reference to Exhibit 10.1.6 of the Company's Form 10-Q for the quarter ended
             March 31, 1997.)

     10.1.3  Second Amendment to Amended and Restated Credit Agreement dated as of September 15, 1997 by and among the Company and
             Texas Commerce Bank National Association, as Administrative Agent, NationsBank of Texas, N.A. as Documentary Agent,
             Wells Fargo Bank, N.A., CIBC, Inc. and Credit Lyonnais New York Branch, as Co-Agents and the financial institutions a
             party to the Credit Agreement. (Incorporated herein by reference to Exhibit 10.1.8 of the Company's Form 10-Q for the
             quarter ended September 30, 1997.)

     10.2.1  Supplemental Indenture dated as of March 31, 1997 among Gerrity Oil & Gas Corporation, the Company and The Chase
             Manhattan Bank (formerly known as Chemical Bank) as Trustee. (Incorporated herein by reference to Exhibit 10.1.7 of the
             Company's Form 10-Q for the quarter ended March 31, 1997.)

     10.3    Patina Oil & Gas Corporation Profit Sharing and Savings Plan and Trust, effective January 1, 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.*

     10.3.3  Patina Oil & Gas Corporation 1998 Stock Purchase Plan.*
</TABLE> 
                                      F-22
<PAGE>
<TABLE> 
<CAPTION> 
     <C>     <S> 
     10.4    Sublease Agreement dated as of May 1, 1996 by and between Snyder Oil Corporation, as Sublandlord, and the Company, as
             Subtenant. (Incorporated herein by reference to Exhibit 10.4 of the Company's Form 10-Q for the quarter ended June 30,
             1996.)

     10.4.1  Sublease Agreement dated as of October 7, 1996 by and between Gerrity Oil & Gas Corporation, as Sublandlord, and
             Shadownet Technologies, L.L.C. (Incorporated herein by reference to Exhibit 10.4 of the Company's Form 10-Q for the
             quarter ended September 30, 1996.)

     10.5    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.)

     10.6    Share Repurchase Agreement dated as of July 31, 1997 by and between the Company and Snyder Oil Corporation as amended
             and restated on September 19, 1997 and as amended as of October 15, 1997 and amended by letter agreement dated October
             21, 1997. (Incorporated herein by reference to Exhibit 10.6 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   Transition Agreement dated as of October 21, 1997 by and between the Company and Snyder Oil Corporation. (Incorporated
             herein by reference to Exhibit 10.10 of the Company's Form 10-Q for the quarter ended September 30, 1997.)

     11.1    Computation of Per Share Earnings.*

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

     27      Financial Data Schedule.*
</TABLE> 
 
*Filed herewith

(b)  No reports on Form 8-K were filed by Registrant during the quarter ended
     December 31, 1997.

                                      F-23
<PAGE>
 
                                  SIGNATURES


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


/s/ Thomas J. Edelman    Chairman of the Board and President   February 26, 1998
---------------------    (Principal Executive Officer)
Thomas J. Edelman                                        


/s/ Brian J. Cree        Director, Executive Vice President    February 26, 1998
---------------------    and Chief Operating Officer 
Brian J. Cree                                            


/s/ David J. Kornder     Vice President and                    February 26, 1998
---------------------    Chief Financial Officer
David J. Kornder                                         


/s/ Arnold L. Chavkin    Director                              February 26, 1998
---------------------                                      
Arnold Chavkin


/s/ Robert J. Clark      Director                              February 26, 1998
---------------------                                      
Robert J. Clark


/s/ Jay W. Decker        Director                              February 26, 1998
---------------------                                       
Jay W. Decker


/s/ Thomas R. Denison    Director                              February 26, 1998
---------------------                                              
Thomas R. Denison


/s/ Elizabeth K. Lanier  Director                              February 26, 1998
-----------------------                                         
Elizabeth K. Lanier


/s/ Alexander P. Lynch   Director                              February 26, 1998
----------------------                                            
Alexander P. Lynch

                                      F-24