<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, 1996

                                      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, Suite 2000                      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
  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 4,816,000 shares of voting stock held by
non-affiliates of the registrant, based upon the closing sale price of the
Common Stock on February 27, 1997 of $9.125 per share as reported on the New
York Stock Exchange, was $43,946,000.  Shares of Common Stock held by each
officer and director and by each person who owns 5% or more of the outstanding
Common Stock have been excluded in that such persons may be deemed affiliates.
This determination of affiliate status is not necessarily a conclusive
determination for other purposes.

     As of March 4, 1997, the registrant had 18,816,432 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, 1997

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

                          Annual Report on Form 10-K
                               December 31, 1996

                                    PART I

ITEM 1.  BUSINESS

GENERAL

     Patina Oil & Gas Corporation ("Patina" or the "Company") is an independent
oil company engaged in the production, development and acquisition of oil and
gas properties.  All of the Company's properties are currently located  in the
Wattenberg Field ("Wattenberg" or the "Field") of Colorado's Denver-Julesburg
Basin ("D-J Basin").  Patina was incorporated in early 1996 to hold the
Wattenberg assets and operations of Snyder Oil Corporation ("SOCO") and to
facilitate the acquisition of Gerrity Oil & Gas Corporation ("GOG"). 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.  Immediately thereafter, GOG merged into
another wholly owned subsidiary of the Company (the "Merger").  As a result of
these transactions, SWAT and GOG became subsidiaries of the Company.  As of
December 31, 1996, SOCO owned 14,000,000 or approximately  74% of the Company's
common shares.

     During 1996, the Company's revenues were $83.2 million and cash flow (net
income applicable to common stock plus exploration expense, depletion,
depreciation and amortization and deferred taxes) approximated $46.1 million.
At December 31, 1996, Patina held interests in over 3,600 wells in Wattenberg
with net proved reserves of 71.9 million barrels of oil equivalent ("MMBOE"),
approximately 70% of which were attributable to natural gas.  Based on
unescalated year-end oil and gas prices, these reserves had a pre-tax present
value of $649 million.

     Wattenberg, discovered in 1970, is located approximately 35 miles northeast
of Denver and stretches over Adams, Boulder and Weld Counties in Colorado.  One
of the most attractive features of Wattenberg is that there are at least eight
potentially productive formations throughout the Field.  Three of the
formations, the Codell, Niobrara and J-sand, are "blanket" zones in the area of
the Company's holdings, while others, such as the Sussex and Shannon are more
localized.  In recent years, the Codell and Niobrara formations have been the
primary drilling objective in the Field, although the Company has also
successfully recompleted shallower formations such as the Sussex.  Drilling in
Wattenberg is low risk from the perspective of encountering hydrocarbons with
better than 95% of the wells drilled being completed as producers.
Consequently, the Field's economic attractiveness is primarily dependent on
energy prices, the reservoir characteristics of the specific area of the Field
being drilled and the operator's ability to minimize capital and operating
costs.

     Over the past five years, the Company, including its predecessors, has
drilled over 1,500 wells in Wattenberg.  During 1996, the Company successfully
drilled 12 development wells,  was in the process of drilling an additional nine
wells at year end and recompleted a further 61 wells at a total cost of
approximately $8.5 million.  Given the Company's experience in drilling and
completing wells of this type, combined with  operating over 3,200 wells, Patina
believes it can drill and operate its oil and gas properties in the Field at a
lower cost than its competitors.  The Company exploits its oil and gas
properties through the implementation of operational 

                                       2
<PAGE>
 
improvements, workovers, multi-zone recompletions, refracs and the drilling of
new development wells. Furthermore, because virtually all of the wells in which
it holds an interest lie within a 40 mile radius, Patina believes it is one of
the most efficient oil and gas producers in the United States.

     The Company's oil and 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.  Gas production from Wattenberg is processed in order to
recover natural gas liquids which are comprised of ethane, propane and
butane/gasoline mix.  The liquids are then sold separately from the residue gas
but included in the Company's gas revenues to determine its average price per
Mcf.  The Company utilizes two separate methodologies to gather, process and
market its natural gas production.  Approximately 30% of the Company's gas
production is sold to PanEnergy Field Services, Inc. ("PanEnergy") under several
separate wellhead agreements.  Pursuant to these agreements, the Company
receives a fixed percentage of the proceeds of PanEnergy's sale of residue gas
and natural gas liquids.  Substantially all of the Company's remaining gas
production is dedicated for gathering to either PanEnergy or KN Front Range
Gathering Company ("KN") and is then processed at plants owned by PanEnergy,
Amoco Production Company ("Amoco") or Vessels Gas Processing, Inc. ("Vessels").
Under this methodology, 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 under
transportation contracts to midwest markets.  Natural gas liquids are sold by
the processor and the Company receives payment net of applicable processing
fees.

     As of December 31, 1996, the Company had net proved reserves of 22.5
million barrels of oil and 296.7 Bcf of gas attributable to interests in  3,602
wells, 728 proved undeveloped locations and 605 proved behind pipe
recompletions.  This inventory of undeveloped locations and recompletions
provides the ability to expand development activities should drilling and
completion technologies improve or the recent recovery in Rocky Mountain natural
gas prices continue.  A significant portion of the Company's 728 proved
undeveloped locations are projected to provide rates of return below the level
judged attractive by management based on projected commodity prices and reserve
recoveries.  While the sharp increase in oil and gas prices during the fall of
1996 through early 1997 provided substantial encouragement, the Company will
continue to evaluate its drilling results and assess trends in energy prices in
the coming months.  The Company, at least for the present, expects to limit its
capital expenditures on existing properties to approximately $14 million.  The
capital program is expected to entail the drilling of 35 wells and 75
recompletions, as well as the expansion of recently initiated refrac, workover
and tubing installation efforts to enhance production.  As a result, management
believes that funds generated from operations will permit a continued paydown of
debt, additional security repurchases or the aggressive pursuit of further
consolidation or acquisition opportunities.  Given Patina's low cost structure
and extensive experience in drilling and efficiently operating large numbers of
wells, management believes the Company is well positioned to pursue further
consolidation in Wattenberg and to take advantage of similar opportunities in
other basins.

                                       3
<PAGE>
 
PRODUCTION, REVENUE AND PRICE HISTORY

     The following table sets forth information regarding net production of
crude oil  and natural gas, revenues and expenses attributable to such
production and certain price and cost information for each of the years in the
five year period ended December 31, 1996.  Note: The financial and operating
information reflect the merger of GOG into a subsidiary of the Company in May
1996.

<TABLE>
<CAPTION>
                                                 December 31,
                                 -------------------------------------------
                                    1992     1993     1994     1995     1996
                                    ----     ----     ----     ----     ---- 
                                  (Dollars in thousands, except prices and  
                                     per barrel equivalent information)
<S>                              <C>      <C>      <C>      <C>      <C>
 
Production
  Oil (Mbbl)                         795    1,224    1,829    1,342    1,688        
  Gas (Mmcf)                      12,867   21,706   23,893   20,981   23,947                                                        

  MBOE (a)                         2,940    4,842    5,812    4,839    5,679                                                        

                                                                                                                                    

Revenues                                                                                                                            

  Oil                            $15,154  $19,429  $27,151  $22,049  $34,541                                                        

  Gas (b)                         23,419   45,125   40,598   28,024   47,644                                                        

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

     Subtotal                     38,573   64,554   67,749   50,073   82,185                                                        

  Other                              125      311       73       29    1,003                                                        

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

     Total                        38,698   64,865   67,822   50,102   83,188                                                        

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

                                                                                                                                    

Operating expenses                                                                                                                  

  Production (C)                   8,272    8,927    8,110    8,867   14,519                                                        

  Exploration                         17      573      784      416      224                                                        

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

                                   8,289    9,500    8,894    9,283   14,743                                                        

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

                                                                                                                                    

Direct operating margin          $30,409  $55,365  $58,928  $40,819  $68,445                                                        

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

                                                                                                                                    

Average sales price (d)                                                                                                             

  Oil (Bbl)                      $ 19.06  $ 15.87  $ 14.84  $ 16.43  $ 20.47                                                        

  Gas (Mcf) (b)                     1.82     2.08     1.70     1.34     1.99                                                        

  BOE (a)                          13.12    13.33    11.66    10.35    14.47                                                        

Average production expense/BOE      2.81     1.84     1.40     1.83     2.56                                                        

Average production margin/BOE      10.31    11.49    10.26     8.52    11.92         
</TABLE> 

___________________________
(a)  Gas production is converted to oil equivalents at the rate of six Mcf per
     barrel.
(b)  Sales of natural gas liquids are included in gas revenues.
(c)  Production expense is comprised of lease operating expenses and production
     taxes.
(d) The Company estimates that its composite net wellhead prices at December 31,
    1996 were approximately $3.70 per Mcf of gas and $25.20 per barrel of oil.

                                       4
<PAGE>
 
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>
                                          1994   1995  1996
                                          ----   ----  ----
<S>                                       <C>    <C>   <C>
Productive
  Gross............................       350.0  25.0  12.0
  Net..............................       305.6  24.1  12.0
Dry
  Gross............................         8.0   0.0   0.0
  Net..............................         7.9   0.0   0.0
</TABLE>

  At December 31, 1996, nine gross (eight net) development wells were in
progress.

CUSTOMERS AND MARKETING

     The Company's oil and 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 gas can be affected by a number of
factors that are beyond the Company's control and whose future effect 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 (Btu's) and
must be processed in order to strip natural gas liquids from the residue gas
which is sold to utilities, independent marketers and end users through both
intrastate and interstate pipelines.  The Company utilizes two separate
methodologies to gather, process and market its natural gas production.
Approximately 30% of the Company's gas production is sold to PanEnergy 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 natural gas liquids by PanEnergy.  Substantially all of
the Company's remaining gas production is dedicated for gathering to either
PanEnergy or KN and is then processed at plants owned by PanEnergy, Amoco or
Vessels.  Under this methodology, 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.  Natural gas liquids are
sold by the processor and the Company receives payment net of applicable
processing fees.

     A portion of 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 natural gas liquids stripped from the 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.
As a part of an agreement entered into with Vessels, the Company will deliver an
average of 4,000 MMBtu per day to the Vessels' Ft. Lupton gas processing
facility through November 30, 1997 at competitive processing terms.

     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 crude oil and is adjusted for
transportation costs and quality.  Amoco has the right to purchase oil produced
from certain properties owned by the Company.

                                       5
<PAGE>
 
COMPETITION

     The oil and gas industry is highly competitive in all its phases.
Competition is particularly intense with respect to the acquisition of producing
properties.  There is also competition for the acquisition of oil and gas
leases, in the hiring of experienced personnel and from other industries in
supplying alternative sources of energy.

     Competitors in acquisitions, exploration, development and production
include the major oil companies in addition to numerous independent oil
companies, individual proprietors, drilling and acquisition programs and others.
Many of these competitors possess financial and personnel resources
substantially in excess of those available to the Company.  Such competitors may
be able to pay more for desirable leases and to evaluate, bid for and purchase a
greater number of properties than the financial or personnel resources of  the
Company permit. 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 exploration and development.

TITLE TO PROPERTIES

     Title to the Company's oil and gas properties is subject to royalty,
overriding royalty, carried and other similar interests and contractual
arrangements customary in the oil and 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 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.

REGULATION

     Regulation of Drilling and Production.  The Company's operations are
affected by political developments, and by federal, state and local laws and
regulations.  Oil and gas industry legislation and administrative regulations
are periodically changed for a variety of political, economic and other reasons.
Numerous federal, state and local departments and agencies issue rules and
regulations binding on the oil and gas industry, some of which carry substantial
penalties for failure to comply.  The regulatory burden on the oil and 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.  On the other hand, these laws and regulations also establish the
framework in which the government sanctions and approves the conduct of the
Company's business activities, and can operate to the Company's benefit.

     In the past, the federal government has regulated the prices at which oil
and gas could be sold.  Prices of oil and gas sold by the Company are not
currently regulated.  In recent years, the Federal Energy Regulatory Commission
("FERC") has taken significant steps to increase competition in the sale,
purchase, storage and transportation of natural gas.  FERC's regulatory programs
allow more accurate and timely price signals from the consumer to the producer
and, on the whole, have helped 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 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.

                                       6
<PAGE>
 
     State statutes govern exploration and production operations, conservation
of oil and gas resources, protection of the correlative rights of oil and gas
owners and environmental standards.  State Commissions implement their authority
by establishing rules and regulations requiring permits for drilling,
reclamation of production sites, plugging bonds, reports and other matters.
Colorado, where most of the Company's properties are located, amended its
statute concerning oil and gas development in 1994 to provide the state's Oil
and Gas Conservation Commission with enhanced authority to regulate oil and gas
activities to protect public health, safety and welfare, including the
environment.  Several rulemakings pursuant to these statutory changes have been
undertaken by the Commission 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 oil and gas operations of
the Company, as the Commission 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 oil and gas operations in the future.

     In Colorado, a number of city and county governments have enacted oil and
gas regulations.  These ordinances increase the involvement of local governments
in the permitting of oil and gas operations, and require additional restrictions
or conditions on the conduct of operations so as to reduce their impact on the
surrounding community.  Accordingly, these local ordinances have the potential
to delay, and increase the cost of, drilling 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 crude 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.

     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, however, 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 gas industry in general.

                                       7
<PAGE>
 
DIRECTORS AND EXECUTIVE OFFICERS

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

<TABLE>
<CAPTION>

          Name                         Age                Position
          ----                         ---                --------
<S>                                    <C>  <C>

Thomas J. Edelman..................     46  Chairman of the Board, President and
                                            Chief Executive Officer
Brian J. Cree......................     33  Executive Vice President and
                                            Chief Operating Officer, Director
Keith M. Crouch....................     50  Senior Vice President and General
                                            Counsel
Ronald E. Dashner..................     44  Senior Vice President, Operations
David J. Kornder...................     36  Vice President and Chief Financial
                                            Officer
David R. Macosko...................     35  Vice President
Terry L. Ruby......................     38  Vice President
David W. Siple.....................     37  Vice President
Rodney L. Waller...................     47  Vice President
Kenneth A. Wonstolen...............     45  Vice President
Robert J. Clark....................     52  Director
Jay W. Decker......................     44  Director
William J. Johnson.................     61  Director
Alexander P. Lynch.................     44  Director
John C. Snyder.....................     54  Director
</TABLE>

     THOMAS J. EDELMAN has served as Chairman of the Board, President and Chief
Executive Officer of Patina since its formation.  He co-founded SOCO and was the
President and a director of SOCO from 1981 through February 1997.  Prior to
1981, he was a Vice President of The First Boston Corporation.  From 1975
through 1980, Mr. Edelman was 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 a director of  Petroleum Heat & Power
Co., a Connecticut based fuel oil distributor, and its affiliate Star Gas
Corporation, and of Paradise Music & Entertainment, Inc.  Mr. Edelman also
serves as Chairman of Lomak Petroleum, Inc.

     BRIAN J. CREE has served as Executive Vice President, Chief Operating
Officer and Director of Patina since May 1996.  Prior to the Merger, he served
as Chief Operating Officer and Director of GOG since 1993. From 1992 to 1993,
Mr. Cree served as Senior Vice President-Operations and Chief Accounting Officer
of GOG. Prior to that, Mr. Cree served as Vice President and Treasurer of GOG
since its inception in 1990.  Mr. Cree served as Vice President and Treasurer of
The Robert Gerrity Company from 1989 to 1990 and served in various accounting
capacities with that company from 1987 to 1990.  Prior to that, Mr. Cree was
employed as an accountant at the public accounting firm of Deloitte, Haskins &
Sells.

                                       8
<PAGE>
 
     KEITH M. CROUCH has served as Senior Vice President and General Counsel of
Patina since May 1996. Prior to the Merger, he was a Vice President of GOG
commencing in 1993 and was appointed a Director in 1994.  From 1992 to 1993, Mr.
Crouch served as Corporate Counsel to GOG.  Mr. Crouch was responsible for the
legal aspects of GOG's oil and gas operations.  Prior to joining GOG, Mr. Crouch
was in private practice with Pendleton & Sabian, P.C. since 1983.

     RONALD E. DASHNER has served as Senior Vice President, Operations of Patina
since its formation.  Prior to the Merger, he served as Vice President--Rockies
Group--Rocky Mountain Division of SOCO in late 1995. Prior to that he was
Operations Manager of SOCO's D-J Basin/Greater Green River Unit.  He joined SOCO
in 1994.  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 in 1974.

     DAVID J. KORNDER has served as Vice President and Chief Financial Officer
of Patina since May 1996. Prior to the Merger, he served as a Vice President-
Finance of GOG from 1993.   Mr. Kornder is responsible for Patina's financial
reporting,  planning, cash management, budgeting, and acquisition evaluation.
Prior to joining GOG, Mr. Kornder was an Assistant Vice President for Gillett
Group Management, Inc. where he was responsible for that firm's financial
planning and budgeting from 1989 to 1993.  Prior to that, Mr. Kornder was an
accountant with the independent accounting firm of Deloitte & Touche for five
years.

     DAVID R. MACOSKO has served as a Vice President of Patina since May 1996.
Prior to the Merger, he served as a Vice President of GOG from 1994.  From 1992
to 1994, Mr. Macosko served as Operations Coordinator and Manager of Accounts
Payable with GOG.  Mr. Macosko is responsible for Patina's daily business
operations in the D-J Basin.  Mr. Macosko received a bachelor of science degree
in accounting from West Virginia University.  Mr. Macosko has been with Patina
and its predecessor entity for seven years serving in various operational,
accounting and analyst positions.  Mr. Macosko has eleven years of experience in
the oil and gas industry.

     TERRY L. RUBY has served as a Vice President of Patina since May 1996.
Prior to the Merger, he served as a Vice President of GOG from 1995, and was in
charge of land matters for GOG.  His current  responsibilities include
management of land assets, acquisition and divestiture.  Mr. Ruby has been with
Patina and its predecessors's  land department from 1992.  Previously, Mr. Ruby
worked with Apache Corporation from 1990 to 1992, and with Baker Exploration
Company from 1982 to 1989.  Mr. Ruby holds a B.S. in Minerals Land Management
and an M.B.A.

     DAVID W. SIPLE has served as a Vice President of Patina since its
formation.  Prior to the Merger, he served as a Land Manager with SOCO from
1995.  He  served in various capacities in the Land Department since joining
SOCO in 1994.  From 1990 through 1994, Mr. Siple was the Land Manager of GOG.
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
Mineral Land Management from the University of Colorado.

     RODNEY L. WALLER has served as a Vice President of Patina since its
formation.  He also serves as Vice President--Special Projects of SOCO.  He
joined SOCO in 1977.  Previously, Mr. Waller was employed by Arthur Andersen &
Co.  Mr. Waller received his Bachelor of Arts Degree from Harding University.

                                       9
<PAGE>
 
     KENNETH A. WONSTOLEN has served as a Vice President of Patina since May
1996.  Prior to the Merger, he served as a Vice President of GOG from 1995, and
was in charge of environmental and public affairs.  His responsibilities at
Patina include environmental, health and safety matters, as well as government,
community, media and investor relations.  Mr. Wonstolen joined GOG in 1992 as
Corporate Counsel after having been in the private practice of law since 1990.
Mr. Wonstolen was Executive Director and General Counsel of the Independent
Petroleum Association of Mountain States from 1985 to 1990.  Mr. Wonstolen holds
B.A. and J.D. degrees, as well as a Master of Environmental Policy and
Management degree.

     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
Snyder Oil Corporation.  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 affiliates NICOR Exploration, Norther Illinois Gas and
Reliance Pipeline Company.  Mr. Clark received his Bachelor of Science Degree
from Bradley University and his Masters Degree in Business Administration 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 and a Director of the Children's Museum of Denver.

     WILLIAM J. JOHNSON has served as a Director of the Company since May 1996.
Mr. Johnson, a Director of SOCO since 1994, is a private consultant to the oil
and gas industry and is President and a Director of JonLoc Inc., an oil and gas
company of which he and his family are the sole shareholders.  From 1991 to
1994, Mr. Johnson was President, Chief Operating Officer and a director of
Apache Corporation.  Previously, he was a Director, President and Chief
Executive Officer of Tex/Con Oil and Gas, where he served from 1989 to 1991.
Prior thereto, Mr. Johnson served in various capacities with major oil
companies, including director and President USA of BP Exploration Company,
President of Standard Oil Production Company and Senior Vice President of The
Standard Oil Company.  Mr. Johnson received a Bachelor of Science degree in
Petroleum Geology from Mississippi State University and completed the Advanced
Management Course at the University of Houston. Mr. Johnson serves as a Director
of Tesoro Petroleum, a refining and marketing company with interests in oil and
gas production and marine services and Camco International, an oilfield
manufacturing company.  Mr. Johnson also serves on the advisory board of Texas
Commerce Bank, Houston.

                                       10
<PAGE>
 
     ALEXANDER P. LYNCH has served as a Director of the Company since May 1996.
Mr. Lynch has 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 also serves as a Director of Lincoln Snacks Company and Illinois
Central Corporation.  Mr. Lynch received his Bachelor of Arts Degree from the
University of Pennsylvania and an M.B.A. from the Wharton School of Business at
the University of Pennsylvania.

     JOHN C. SNYDER has served as a Director of the Company since its formation.
Mr. Snyder, the Chairman, President and Chief Executive Officer of SOCO, founded
one of SOCO's predecessors in 1978.  From 1973 to 1977, Mr. Snyder was an
independent oil operator in Texas and Oklahoma.  Previously, he was a director
and the Executive Vice President of May Petroleum Inc. where he served from 1971
to 1973.  Mr. Snyder was the first president of Canadian-American Resources
Fund, Inc., which he founded in 1969.  From 1964 to 1966, Mr. Snyder was
employed by Humble Oil and Refining Company (currently Exxon Co., USA) as a
petroleum engineer.  Mr. Snyder received his Bachelor of Science Degree in
Petroleum Engineering from the University of Oklahoma and his Masters Degree in
Business Administration from the Harvard University Graduate School of Business
Administration.  Mr. Snyder is a director of the Community Enrichment Center,
Inc., Forth Worth, Texas.

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 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 at least 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
                                                              Depth
            Formation                                         (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>

                                       11
<PAGE>
 
     At December 31, 1996, the Company had working interests in 3,407 gross
(3,084 net) producing oil and gas wells in the D-J Basin and held royalty
interests in 195 producing wells.  As of December 31, 1996, estimated proved
reserves totaled 71.9 million BOE, including 22.5 million barrels of oil and
296.7 Bcf of gas.

PROVED RESERVES

     The following table sets forth estimated year end net proved reserves  for
the three years ended December 31, 1996.

<TABLE>
<CAPTION>
                                                        December 31,
                                                  -------------------------
                                                   1994     1995     1996
                                                  -------  -------  -------
<S>                                               <C>      <C>      <C>
     Crude oil and liquids (Mbbl)
          Developed.........................        8,832    6,955   15,799
          Undeveloped.......................        3,386      466    6,676
                                                  -------  -------  -------
               Total........................       12,218    7,421   22,475
                                                  =======  =======  =======

     Natural gas (Mmcf)
          Developed.........................      147,869  133,088  242,777
          Undeveloped.......................       30,834    5,769   53,882
                                                  -------  -------  -------
               Total........................      178,703  138,857  296,659
                                                  =======  =======  =======

     Total MBOE.............................       42,002   30,564   71,918
                                                  =======  =======  =======
</TABLE>

     The following table sets forth pretax future net revenues from the
production of proved reserves and the Pretax PW 10% Value of such revenues, net
of estimated future capital costs, including estimated costs of $14.0 million in
1997.

<TABLE>
<CAPTION>
                                                           December 31, 1996
                                                  -----------------------------------
                                                  Developed  Undeveloped     Total
                                                  ---------  ------------  ----------
                                                            (In thousands)
<S>                                               <C>        <C>           <C>
     1997....................................      $117,410     $ (2,154)  $  115,256
     1998....................................       101,637       (2,455)      99,182
     1999....................................        92,397        4,235       96,632
     Remainder...............................       668,820      188,977      857,797
                                                   --------     --------   ----------
        Total................................      $980,264     $188,603   $1,168,867
                                                   ========     ========   ==========

     Pretax PW 10% Value (a).................      $582,408     $ 66,389   $  648,797
                                                   ========     ========   ==========
</TABLE>

__________________
(a) The after tax PW 10% value of the proved reserves totaled $499.9 million at
year end 1996.

                                       12
<PAGE>
 
     The quantities and values in the preceding tables are based on prices in
effect at December 31, 1996 which averaged $25.20 per barrel of oil and $3.70
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 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 oil and gas prices in effect on December 31, 1996.  Those prices
were significantly higher than the prices that prevailed throughout most of 1996
and since year end, prices have fallen from year end levels.  The value of the
Company's assets is in part dependent on the prices the Company receives for oil
and gas and a significant decline in the price of oil or gas could have a
material adverse effect on the Company's financial condition and results of
operations.   The 10% discount factor used to calculate present value, which is
specified by the Securities and Exchange Commission (the "SEC"), is not
necessarily the most appropriate discount rate, and present value, no matter
what discount rate is used, is materially affected by assumptions as to timing
of future production, which may prove to be inaccurate.  For properties operated
by the Company, expenses exclude Patina's share of overhead charges.  In
addition, the calculation of estimated future net revenues does not take into
account the effect of various cash outlays, including, among other things
general and administrative costs and interest expense.

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

     All of the proved reserves at year-end were estimated by Netherland, Sewell
& Associates Inc. ("NSAI"). No estimates of the Company's reserves comparable to
those included herein have been included in reports to any federal agency other
than the SEC.

                                       13
<PAGE>
 
PRODUCING WELLS

     The following table sets forth certain information at December 31, 1996
relating to the producing wells in which the Company owned a working interest.
The Company also held royalty interests in 195 producing wells.  Wells are
classified as oil or gas wells according to their predominant production stream.

<TABLE>
<CAPTION>
                                                                    Average
                      Principal                      Gross   Net    Working
                  Production Stream                  Wells  Wells  Interest
                  -----------------                  -----  -----  --------
               <S>                                   <C>    <C>    <C>
               Crude oil and liquids.............    2,794  2,571       92%
               Natural gas.......................      613    513       84%
                                                     -----  -----
                  Total..........................    3,407  3,084       91%
                                                     =====  =====
</TABLE>

ACREAGE

     The following table sets forth certain information at December 31, 1996
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.  The Company also has approximately 60,000 gross undeveloped
acres in the Uinta Basin of Utah.  The Company currently plans to divest of this
acreage.

                                                 Gross       Net
                                                 -----       ---

     Developed...........................       177,548    137,500
                                                =======    =======
     Undeveloped.........................       160,621    141,713
                                                =======    =======

                                       14
<PAGE>
 
ITEM 3.  LEGAL PROCEEDINGS

     In August 1995, SOCO was sued in the United States District Court of
Colorado by plaintiffs purporting to represent all persons who, at any time
since January 1, 1960, have had agreements providing for royalties from gas
production in Colorado to be paid by SOCO under various lease provisions.  In
January 1997, the judge denied the plaintiffs' motion for class certification.
Substantially all liability under this suit was assumed by the Company  upon its
formation.  In January 1996, GOG was also sued in a similar but separate action
filed in the Colorado State Court.  The plaintiffs, in both suits, allege that
unspecified "post-production" costs incurred prior to calculating royalty
payments were deducted in breach of the relevant lease provisions and that this
fact was fraudulently concealed.  The plaintiffs seek unspecified compensatory
and punitive damages and a declaratory judgment prohibiting the deduction of
post-production costs prior to calculating royalties paid to the plaintiffs. The
Company believes that costs deducted in calculating royalties are and have been
proper under the relevant lease provisions, and they intend to defend these and
any similar suits vigorously.  At this time, the Company is unable to estimate
the range of potential loss, if any.  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 impact on results for that period.

     In March 1996, a complaint was filed in the Court of Chancery for the State
of Delaware against GOG 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 the defendants from consummating a merger
which will benefit the holders of GOG's common stock at the expense of the
holders of the Preferred and (b) to obtain a declaration that the terms of the
proposed merger constitute a breach of the contractual rights of the Preferred."
The complaint seeks, among other things, certification as a class action on
behalf of all holders of GOG'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 Merger and money damages.
Defendants believe that the complaint is without merit and intend to vigorously
defend against the 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 impact 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

     No matters were submitted for a vote of security holders during the fourth
quarter of 1996.

                                       15
<PAGE>
 
                                    PART II

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

     The Patina Common Stock, the Patina Warrants and the Patina Preferred Stock
are listed on the New York Stock Exchange ("NYSE") under the symbols "POG",
"POGWT" and "POGPr", respectively.  Such listings became effective on May 3,
1996.  The following table sets forth, for the period since such listing became
effective, the range of high and low closing prices as reported on the NYSE
Composite Tape.

<TABLE>
<CAPTION>
                                                                    1996
                                          --------------------------------------------------------
                                          Common Stock          Warrants          Preferred Stock
                                          ------------          --------          ----------------
                                          High     Low        High     Low        High         Low
                                          ----     ---        ----     ---        ----         ---
     <S>                                  <C>     <C>         <C>      <C>       <C>         <C>

     Second Quarter (from May 3, 1996)    $8 1/4  $6 1/8       $2 3/8  $1 1/4    $24 1/2     $22 1/4
     Third Quarter                         7 3/8   6 3/4        1 5/8   1         26          23
     Fourth Quarter                        9 1/2   7            2 3/8   1         30 1/4      25 1/2
</TABLE>

     On February 27, 1997, the closing prices of the Common Stock, Warrants and
the  Preferred Stock were $9.125, $2.00 and $30.00, respectively.  As of
December 31, 1996, there were approximately 110 holders of record of the common
stock and 18.9 million shares outstanding.

     Dividend Policy.   The Board of Directors of the Company have not declared
cash dividends on its Common Stock and does not currently  plan to do so.  Under
the terms of its current Bank Credit Agreement, the Company is restricted in its
ability to declare dividends on its Common Stock.

                                       16
<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, 1996.  Future results may differ substantially from historical results
because of changes in oil and  gas prices, normal 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 merger of GOG into a subsidiary of
the Company in May 1996.

<TABLE>
<CAPTION>
                                                                            As of or for the Year Ended December 31,
                                                                      -----------------------------------------------------
                                                                        1992       1993       1994       1995       1996
                                                                        ----       ----       ----       ----       ----
                                                                              (In thousands except per share data)
<S>                                                                   <C>        <C>        <C>        <C>        <C>

STATEMENT OF OPERATIONS DATA
Revenues........................................................      $ 38,698   $ 64,865   $ 67,822   $ 50,102   $ 83,188
Expenses
  Direct operating..............................................         8,272      8,927      8,110      8,867     14,519
  Exploration...................................................            17        573        784        416        224
  General and administrative....................................         6,115      6,982      7,484      5,974      6,151
  Interest and other............................................         1,771      2,362      3,869      5,476     14,304
  Depletion, depreciation and amortization......................        11,949     25,190     43,036     32,591     44,822
                                                                      --------   --------   --------   --------   --------
   Total expenses...............................................        28,124     44,034     63,283     53,324     80,020
                                                                      --------   --------   --------   --------   --------
Income (loss) before taxes......................................        10,574     20,831      4,539     (3,222)     3,168
Provision (benefit) for income taxes............................         3,701      7,291      1,589     (1,128)      (394)
                                                                      --------   --------   --------   --------   --------
Net income (loss)...............................................      $  6,873   $ 13,540   $  2,950   $ (2,094)  $  3,562
                                                                      ========   ========   ========   ========   ========

   Per common share.............................................          $.49       $.97       $.21      $(.15)      $.08
                                                                      ========   ========   ========   ========   ========

Weighted Average Shares Outstanding.............................        14,000     14,000     14,000     14,000     17,796

BALANCE SHEET DATA
   Current assets...............................................      $  5,343   $ 14,725   $ 11,083   $  9,611   $ 27,587
   Oil and gas properties, net..................................       106,251    181,170    234,821    214,594    398,640
   Total assets.................................................       113,064    195,895    246,686    224,521    430,233
   Current liabilities..........................................        16,740     23,735     23,838      9,611     26,572
   Debt.........................................................        35,537     60,857     79,333     75,000    197,594
   Stockholders' equity.........................................        51,278     92,865    115,846    113,663    196,236

CASH FLOW DATA
   Net cash provided by operations..............................      $ 27,710   $ 38,882   $ 47,690   $ 18,407   $ 52,996
   Net cash used by investing...................................       (47,189)   (97,573)   (96,378)   (21,060)    (9,796)
   Net cash realized (used) by financing........................        19,479     58,691     48,688      2,653    (38,047)

RATIO OF EARNINGS TO COMBINED FIXED
   CHARGES AND PREFERRED DIVIDENDS..............................          6.97       9.82       2.17       0.40       1.08
</TABLE>

                                       17
<PAGE>
 
The following table sets forth unaudited summary financial results on a
quarterly basis for the two most recent years.

<TABLE>
<CAPTION>
                                                                                            1995
                                                                        --------------------------------------------
                                                                            First     Second    Third     Fourth
                                                                            -----     ------    -----     ------
<S>                                                                     <C>          <C>       <C>       <C>
(In thousands, except per share data)

Revenues.....................................................              $14,287   $12,890   $11,423   $11,502
Direct operating expenses....................................                2,263     2,503     2,201     1,900
Depletion, depreciation and amortization.....................                8,620     8,331     7,372     8,268
Net income (loss)............................................                 (215)     (428)     (497)     (954)
  Per common share...........................................                 (.01)     (.03)     (.04)     (.07)


                                                                                             1996
                                                                        --------------------------------------------
                                                                             First    Second     Third    Fourth
                                                                             -----    ------     -----    ------
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
  Per common share...........................................                 (.05)     (.10)     (.07)      .28
</TABLE>

                                       18
<PAGE>
 
ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS

RESULTS OF OPERATIONS

     On May 2, 1996, GOG was merged into a wholly owned subsidiary of the
Company (the "Merger"). This transaction was accounted for as a purchase of GOG.
Accordingly, the results of operations since the Merger reflect the impact of
the purchase.

     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 is
due to the effect of the Merger and improved product prices in 1996.  Net income
for 1996 was $3.6 million compared to a net loss of $2.1 million in 1995.  The
increase in net income is primarily attributed to a significant increase in
average oil and gas prices received, offset by an increase in interest expense
and depletion, depreciation and amortization.

     Oil and gas sales less direct operating expenses for 1996 were $67.7
million, a 64% increase from the prior year period.  Average daily production in
1996 was 4,612 barrels and 65.4 Mmcf, or  (15,515 barrels of oil equivalent
("BOE"), increases of 26% and 14%, respectively.  The production increases
resulted solely from the Merger.  Exclusive of the Merger, production continued
to decline 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.  In the future, while production is not expected to continue to
decline at the current rate, a decrease is expected unless development drilling
activity is substantially increased or additional acquisitions are consummated.
The decision to increase development drilling is heavily dependent on the
commodity prices being received for production.

     Average oil prices increased to $20.47 per barrel compared to $16.43
received in 1995.  Average natural gas prices increased from $1.34 per Mcf in
1995 to $1.99 in 1996.  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 benefitted 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 $2.56 per BOE compared to
$1.83 in 1995.  The increase is 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 gas prices.

                                       19
<PAGE>
 
     General and administrative expenses, net of third party reimbursements, for
1996 were $6.2 million, a 3% increase over 1995.  The increase is the result of
the Merger partially offset by reductions in allocated costs from SOCO during
the first four months of 1996.  Prior to the Merger, the Company did not have
its own employees.  Employees and certain office space and furniture, fixtures
and equipment were provided by SOCO. SOCO allocated general and administrative
expenses based on estimates of expenditures incurred on behalf of the Company.

     Interest and other expense was $14.3 million compared to $5.5 million in
1995.  Interest expense increased as a result of higher average outstanding debt
levels as a result of  the Merger.  The Company's average interest rate climbed
to 9.3% compared to 7.0% in 1995.  This increase is due primarily to the
Subordinated Notes.

     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 $7.89 per BOE compared to $6.74 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 Merger.  The amortization of the noncompete
agreement of $2.6 million in 1996 resulted in an increase of $.46 in the
depletion, depreciation and amortization rate per BOE.

     Comparison of 1995 results to 1994.  Total revenues in 1995 were $50.1
million as compared to $67.8 million in 1994.  The 26% decrease was due to both
a drop in production (17%) and in average prices received (11%).  The net loss
for 1995 was $2.1 million compared to net income of $3.0 million in 1994.  The
decrease was primarily due to the drop in production and average prices
received, higher direct operating expenses and increased interest expense due to
increased average debt payable to parent offset somewhat by a lower depletion
rate.

     Average daily production during 1995 was 3,677 barrels and 57.5 Mmcf
(13,257 BOE), a decrease of 27% for oil and 12% for gas, as compared to 1994.
The production declines resulted primarily from the Company's decision to reduce
drilling in 1995 due to the continued decline in gas prices subsequent to year
end 1994.  During 1995, the Company placed an additional 88 wells on production
compared to 360 wells during 1994.  The direct operating margin (revenues less
direct operating costs) for 1995 was $41.2 million, a 31% decrease from 1994.
Average oil prices increased 11% to $16.43 per barrel.  However, that modest
increase was more than offset by the continued sharp decline in gas prices.  The
average gas price for 1995 was only $1.34 per Mcf, a 21% decrease from 1994.
Direct operating expenses per equivalent barrel also increased to $1.83 from
$1.40 in 1994 due to decreasing total production with a higher number of wells
and higher well servicing costs in 1995.

     General and administrative expenses, net of reimbursements, were $6.0
million in 1995 as compared to $7.5 million in 1994.  The Company did not have
its own employees.  Employees and certain office space and furniture, fixtures
and equipment have been provided by SOCO.  SOCO has allocated general and
administrative expenses based on estimates of actual expenditures incurred on
behalf of Patina.  The general and administrative expenses in 1995 were $1.5
million lower than 1994, reflecting the lower overhead associated with the
reduced drilling activity.

                                       20
<PAGE>
 
     Interest paid to parent and other expense was $5.5 million in 1995 as
compared to $3.9 million in 1994. Interest expense represents interest on debt
payable to SOCO.  Prior to the Merger, SOCO financed all of the Company's
activities.  A portion of such financing was considered to be an investment by
SOCO in the Company and, accordingly, no interest was charged by SOCO to Patina
for this capital.  The remaining portion of such financing was considered to be
debt payable to SOCO with interest charged to the Company at a rate which
approximated the average interest rate being paid by SOCO under its revolving
credit facility.  The increase in interest expense was primarily due to an
increase in interest rates from 5.5% to 7%.

     Depletion, depreciation and amortization expense for 1995 decreased 24%
from 1994.  The decrease was primarily attributable to the decreases in
production and a $2.1 million greater impairment in 1994.

DEVELOPMENT, ACQUISITION AND EXPLORATION

     During 1996, the Company incurred $226.9 million in capital expenditures.
Of this amount, $218.4 million related to the acquisition of GOG by the issuance
of stock and assumption of debt by the Company. Capital expenditures, exclusive
of acquisitions, totaled only $8.5 million as the Company has continued to limit
its development activity based on Rocky Mountain natural gas prices.  The
Company anticipates incurring development capital expenditures of approximately
$14 million during 1997.

FINANCIAL CONDITION AND CAPITAL RESOURCES

     At December 31, 1996, the Company had total assets of $430.2 million.
Total capitalization was $393.8 million, of which 50% was represented by
stockholders' equity, 24% by senior debt and 26% by subordinated debt.  During
1996, net cash provided by operations was $53.0 million, as compared to $18.4
million in 1995. As of December 31, 1996, there were no significant commitments
for capital expenditures.  The Company anticipates that 1997 expenditures for
development drilling and recompletion activity will approximate $14 million,
which 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 its bank credit facilities.  In
addition, joint ventures or future public and private offerings of debt or
equity securities may be utilized.  Due to restrictions outlined in GOG's
various credit agreements, cash generated by GOG may need to be retained by GOG
and might therefore not be available to fund the Company's other operations.

     Prior to the Merger, SOCO financed all of the Company's activities.  A
portion of such financing was considered to be an investment by parent in the
Company with the remaining portion being considered debt payable to SOCO.  In
conjunction with the Merger, the $75 million debt payable to SOCO was paid in
full and the Company does not expect SOCO to provide any additional funding.

     Simultaneously with the Merger, the Company entered into a bank credit
agreement.  The agreement consists of (i) a facility provided to the Company and
SOCO Wattenberg (the "Company Facility") and (ii) a facility provided to GOG
(the "GOG Facility").

                                       21
<PAGE>
 
     The Company Facility is a revolving credit facility in an aggregate amount
up to $102 million.  The amount available for borrowing under the Company
Facility is limited to a semiannually adjusted borrowing base that equalled $85
million at December 31, 1996.  At December 31, 1996, $67.5 million was
outstanding under the Company Facility.  Prior to September 30, 1996, the
Company had a term loan facility in an amount up to $87 million.  This term loan
facility was available to fund GOG's repurchases of the Subordinated Notes.  At
September 30, 1996, the Company had not utilized the term loan facility and it
was canceled.

     The GOG Facility is a revolving credit facility in an aggregate amount up
to $51 million.  The amount available for borrowing under the GOG Facility is
limited to a semiannually adjusted borrowing base that equalled $35 million at
December 31, 1996.  At December 31, 1996, $27.0 million was outstanding under
the GOG Facility.  The GOG Facility was used primarily to refinance GOG's
previous bank credit facility and pay costs associated with the Merger.

     As of February 25, 1997, the Company had approximately $185.1 million of
debt outstanding, consisting of $82.0 million of senior debt and $103.1 million
of subordinated notes.

     The bank 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 bank 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 clauses; issuance of securities; and commodity
hedging.

     The Company from time to time enters into arrangements to monetize its
Section 29 tax credits.  These arrangements result in revenue increases of
approximately $.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 and $1.5 million during 1995 and 1996,
respectively.  These arrangements are expected to increase revenues through
2002.

     The Company believes that its capital resources are adequate to meet the
requirements of its business. However, future cash flows are subject to a number
of variables including the level of production and oil and gas prices, and there
can be no assurance that operations and other capital resources will provide
cash in sufficient amounts to maintain planned levels of capital expenditures or
that increased capital expenditures will not be undertaken.

                                       22
<PAGE>
 
INFLATION AND CHANGES IN PRICES

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

     The following table indicates the average oil and gas prices received over
the last five years and highlights the price fluctuations by quarter for 1995
and 1996.  Average price computations exclude contract settlements and other
nonrecurring items to provide comparability.   Average prices per equivalent
barrel indicate the composite impact of changes in oil and gas prices.  Natural
gas production is converted to oil equivalents at the rate of six Mcf per
barrel.

<TABLE>
<CAPTION>
                                 Average Prices
                       ----------------------------------
                                    Natural   Equivalent
                       Crude Oil      Gas       Barrels
                       ---------    -------   ----------
                       (Per Bbl)   (Per Mcf)   (Per BOE)
          <S>          <C>         <C>        <C>
 
          Annual
          ------
          1992            $19.06      $1.82       $13.12
          1993             15.87       2.08        13.33
          1994             14.84       1.70        11.66
          1995             16.43       1.34        10.35
          1996             20.47       1.99        14.47
 
          Quarterly
          ---------
 
          1995
          ----
          First           $16.37      $1.37       $10.51
          Second           17.24       1.19         9.84
          Third            15.90       1.27         9.91
          Fourth           16.12       1.55        11.27
 
          1996
          ----
          First           $18.31      $1.55       $11.73
          Second           20.24       1.60        12.75
          Third            19.92       1.83        13.72
          Fourth           22.35       2.78        18.40
</TABLE>

In December 1996, the Company received an average of $23.15 per barrel and $3.69
per Mcf for its production.

                                       23
<PAGE>
 
                  INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


                                                                   PAGE
                                                                   ----
PATINA OIL & GAS CORPORATION

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

    Consolidated Balance Sheets as of December 31, 1995 and 1996....F-3

    Consolidated Statements of Operations for the years ended
           December 31, 1994, 1995 and 1996.........................F-4

    Consolidated Statements of Changes in Stockholders' Equity
           for the years ended December 31, 1994, 1995 and 1996.....F-5

    Consolidated Statements of Cash Flows for the years ended
           December 31, 1994, 1995 and 1996.........................F-6

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

                                      F-1
<PAGE>
 
                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS



To the Stockholders,
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, 1995
and 1996, 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, 1996.  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, 1995 and 1996, and results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.



Fort Worth, Texas,                                   ARTHUR ANDERSEN LLP
February 17, 1997

                                      F-2
<PAGE>
 
                         PATINA OIL & GAS CORPORATION

                          CONSOLIDATED BALANCE SHEETS
                                (IN THOUSANDS)

                                                              DECEMBER 31,
                                                         ----------------------
                                                            1995        1996
                                                         ----------  ----------
 
                                    ASSETS
Current assets
  Cash and equivalents                                   $   1,000   $   6,153
  Accounts receivable                                        6,611      19,977
  Inventory and other                                        2,000       1,457
                                                         ---------   ---------
                                                             9,611      27,587
                                                         ---------   ---------
 
Oil and gas properties, successful efforts method          333,513     559,072
  Accumulated depletion, depreciation and amortization    (118,919)   (160,432)
                                                         ---------   ---------
                                                           214,594     398,640
                                                         ---------   ---------
 
Gas facilities and other                                     4,775       6,421
  Accumulated depreciation                                  (4,459)     (4,917)
                                                         ---------   ---------
                                                               316       1,504
                                                         ---------   ---------
 
Other assets, net                                                -       2,502
                                                         ---------   ---------
                                                         $ 224,521   $ 430,233
                                                         =========   =========

                      LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
  Accounts payable                                       $   3,852   $  15,063
  Accrued liabilities                                          415      11,509
  Payable to parent                                          5,344           -
                                                         ---------   ---------
                                                             9,611      26,572
                                                         ---------   ---------
 
Senior debt                                                      -      94,500
Subordinated notes                                               -     103,094
Debt to parent                                              75,000           -
Other noncurrent liabilities                                26,247       9,831
 
Commitments and contingencies
 
Stockholders' equity
  Preferred stock, $.01 par, 5,000,000 shares
     authorized, -0- and 1,593,608 shares issued
     and outstanding                                             -          16
  Common stock, $.01 par, 40,000,000 shares
     authorized, 14,000,000 and 18,886,932 shares
      issued and outstanding                                   140         189
  Capital in excess of par value                                 -     194,066
  Investment by parent                                     113,523           -
  Retained earnings                                              -       1,965
                                                         ---------   ---------
                                                           113,663     196,236
                                                         ---------   ---------
                                                         $ 224,521   $ 430,233
                                                         =========   =========

       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)


                                                    YEAR ENDED DECEMBER 31,
                                                 ----------------------------
                                                   1994      1995       1996
                                                 -------   -------    -------
 
Revenues
 Oil and gas sales                               $67,749   $50,073    $82,185
 Other                                                73        29      1,003
                                                 -------   -------    -------
                                                 
                                                  67,822    50,102     83,188
                                                 -------   -------    -------
                                                 
Expenses                                         
 Direct operating                                  8,110     8,867     14,519
 Exploration                                         784       416        224
 General and administrative                        7,484     5,974      6,151
 Interest and other                                3,869     5,476     14,304
 Depletion, depreciation and amortization         43,036    32,591     44,822
                                                 -------   -------    -------
                                                 
Income (loss) before taxes                         4,539    (3,222)     3,168
                                                 -------   -------    -------
                                                 
Provision (benefit) for income taxes             
 Current                                               -         -          -
 Deferred                                          1,589    (1,128)      (394)
                                                 -------   -------    -------
                                                   1,589    (1,128)     ( 394)
                                                 -------   -------    -------
                                                 
Net income (loss)                                $ 2,950   $(2,094)   $ 3,562
                                                 =======   =======    =======
                                                 
Net income (loss) per common share                  $.21     $(.15)      $.08
                                                 =======   =======    =======
                                                 
Weighted average shares outstanding               14,000    14,000     17,796
                                                 =======   =======    =======

        The accompanying notes are an integral part of these statements

                                      F-4
<PAGE>
 
                         PATINA OIL & GAS CORPORATION

                     CONSOLIDATED STATEMENTS OF CHANGES IN
                             STOCKHOLDERS' EQUITY
                                (IN THOUSANDS)
 
<TABLE> 
<CAPTION> 
                                                                                          Capital in               Retained
                                           Preferred Stock              Common Stock      Excess of   Investment   Earnings
                                       -----------------------     --------------------
                                        Shares         Amount       Shares      Amount    Par Value   By Parent    (Deficit)
                                       -------        --------     -------     --------   ---------   -----------  ---------
<S>                                    <C>            <C>          <C>         <C>        <C>         <C>          <C> 
Balance, December 31, 1993                  -            $ -        14,000        $140    $      -    $  92,725    $     -
                                                                                 
Credit in lieu of taxes                     -              -             -           -           -       (8,190)         -
                                                                                 
Change in investment by parent              -              -             -           -           -       28,221          -
                                                                                 
Net income                                  -              -             -           -           -        2,950          -
                                       ------         ------        ------     -------   ---------    ---------   --------
                                                                                 
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
                                       ======         ======        ======     =======   =========    =========   ========
</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,
                                                                -------------------------------
                                                                1994        1995         1996
                                                                ----        ----         ----   
<S>                                                           <C>         <C>          <C> 
Operating activities                                                               
  Net income (loss)                                           $  2,950    $ (2,094)    $  3,562
  Adjustments to reconcile net income (loss) to net                                
     cash provided by operations                                                   
       Exploration expense                                         784         416          224
       Depletion, depreciation and amortization                 43,036      32,591       44,822
       Deferred taxes                                            1,589      (1,128)        (394)
       Amortization of deferred credits                         (2,539)     (2,025)        (605)
       Changes in current and other assets and liabilities                         
          Decrease (increase) in                                                   
            Accounts receivable                                  3,642       1,472       (1,057)
            Inventory and other                                      -           -          338
          Increase (decrease) in                                                   
            Accounts payable                                    (1,552)    (10,902)      (4,249)
            Accrued liabilities                                   (220)         77        4,844
            Other liabilities                                        -           -        5,511
                                                              --------    --------     --------
                                                                                   
       Net cash provided by operations                          47,690      18,407       52,996
                                                              --------    --------     --------
                                                                                   
Investing activities                                                               
  Acquisition, development and exploration                     (95,596)    (21,842)      (8,532)
  Merger expenditures, net of cash acquired                          -           -       (2,375)
  Sale of  oil and gas properties                                ( 782)        782        1,111
                                                              --------    --------     --------
                                                                                   
       Net cash used by investing                              (96,378)    (21,060)      (9,796)
                                                              --------    --------     --------
                                                                                   
Financing activities                                                               
  Increase (decrease) in payable/debt to parent                 18,476       1,011      (80,466)
  Increase in indebtedness                                           -           -       72,863
  Deferred credits                                               1,991       2,838          814
  Increase (decrease) in investment by parent                   28,221      (1,196)      (7,514)
  Cost of common stock issuance                                      -           -      (11,882)
  Repurchase of common stock and warrants                            -           -       (9,733)
  Preferred dividends                                                -           -       (2,129)
                                                              --------    --------     --------
                                                                                   
       Net cash realized (used) by financing                    48,688       2,653      (38,047)
                                                              --------    --------     --------
                                                                                   
Increase in cash                                                     -           -        5,153
Cash and equivalents, beginning of period                        1,000       1,000        1,000
                                                              --------    --------     --------
Cash and equivalents, end of period                           $  1,000    $  1,000     $  6,153
                                                              ========    ========     ========
</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"), 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 ("GOG").  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.  Immediately thereafter, GOG merged into another wholly owned
subsidiary of the Company (the "Merger").  As a result of these transactions,
SWAT and GOG became subsidiaries of the Company.  The Company's operations
currently consist of the acquisition, development, and production of oil and gas
properties in the Wattenberg Field.

     SOCO currently owns approximately 74% of the common stock of the Company.
In conjunction with the Merger, the Company offered to exchange the Company's
preferred stock for GOG's preferred stock (the "Original Exchange Offer"). A
total of 1,204,847 shares were issued in exchange for approximately 75% of GOG's
preferred stock. In October 1996, GOG's certificate of incorporation was amended
to provide that all shares of GOG's preferred stock not exchanged in the
Original Exchange Offer be exchanged for the Company's preferred stock on the
same terms as the Original Exchange Offer. Upon consummation of this exchange,
the Company had approximately 1.6 million preferred shares outstanding.

     The above transactions were accounted for as a purchase of GOG. The amounts
and results of operations of the Company for periods prior to the Merger
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 Merger.


(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Producing Activities

     The Company utilizes the successful efforts method of accounting for its
oil and gas properties. Consequently, leasehold costs are capitalized when
incurred. Unproved properties are assessed periodically within specific
geographic areas and impairments in value are charged to expense. Exploratory
expenses, including geological and geophysical expenses and delay rentals, are
charged to expense as incurred. Exploratory drilling costs are initially
capitalized, but charged to expense if and when the well is determined to be
unsuccessful. Costs of productive wells, unsuccessful developmental wells and
productive leases are capitalized and amortized on a unit-of-production basis
over the life of the remaining proved or proved developed reserves, as
applicable. Gas is converted to equivalent barrels at the rate of six Mcf to one
barrel. Amortization of capitalized costs has generally been provided over the
entire D-J Basin as the wells are located in the same reservoir. 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. Changes in the underlying
assumptions or the amortization units could, however, result in impairments in
the future.

Other Assets

     Other assets reflect the value assigned to a noncompete agreement entered
into as part of the Merger.  The value is being amortized over five years at a
rate intended to approximate the decline in the value of the agreement.
Amortization expense for the year ended December 31, 1996 was $2,632,000.
Scheduled amortization for the next five years is $1,500,000 in 1997, $500,000
in 1998, and $250,000 in each of 1999 and 2000.

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 $.40 per Mcf on production volumes from qualified Section 29
properties.  As a result of such arrangements, the Company recognized additional
gas revenues of $2.5 million,  $2.0 million and $1.5 million during 1994, 1995
and 1996, 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,
1995 and 1996 were insignificant.

Financial Instruments

     The book value and estimated fair value of cash and equivalents was $1.0
million and $6.2 million at December 31, 1995 and 1996.  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 debt to parent and senior
debt was $75.0 million and $94.5 million at December 31, 1995 and 1996.  The
fair value is presented at face value given its floating rate structure.  The
book value of the Senior Subordinated Notes ("Subordinated Notes" or "Notes")
was $103.1 million and the estimated fair value was $105.6 million at December
31, 1996.  The fair value 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 to which the contracts relate.

     In the fourth quarter of 1996, the Company entered into various swap sales
contracts with a weighted average oil price (NYMEX based) of $22.19 for contract
volumes of 95,000 barrels of oil for January 1997 through February 1997.  The
unrecognized loss on these contracts totaled $350,000 based on December 31, 1996
market values. The Company estimates incurring approximately $200,000 of
losses related to these swap contracts based on settlements after year end and
market values as of February 25, 1997.

                                      F-8
<PAGE>
 
     In the fourth quarter of 1996 and early 1997, the Company entered into
various swap sales contracts with a weighted average natural gas price (CIG-
Inside FERC based) of $3.02 for contract volumes of 2,250,000 MMBtu's of natural
gas for January 1997 through March 1997. The unrecognized loss on these
contracts totaled $10,000 based on December 31, 1996 market values. The Company
estimates realizing $1.4 million of income related to these swap contracts based
on settlements after year end and market values as of February 25, 1997.

Supplemental Cash Flow Information

     The Merger involved cash and non-cash consideration as presented below:
 
     (In thousands)

     Cash payments made for merger                                      $ 14,257
     Senior debt assumed                                                  19,000
     Subordinated debt assumed                                           105,805
     Minority interest in GOG preferred stock not exchanged at 
       merger 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
                                                                        ========

     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 of cash acquired in the merger.

Risks and Uncertainties

     Historically, the market for oil and gas has experienced significant price
fluctuations.  Prices for natural gas in the Rocky Mountain region have
traditionally been particularly volatile and have been depressed since 1994.  In
large part, the decreased prices are the result of mild weather, increased
production in the region and limited transportation capacity to other regions of
the country.  In the fourth quarter of 1996, both oil and natural gas prices
increased considerably, however, there can be no assurance that these increases
will be sustained.  Increases or decreases in prices received could have a
significant impact on the Company's future results of operations.  Subsequent to
year end, both oil and gas prices have declined to levels similar to the
Company's realized average prices in 1996.

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 1994, 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 to SOCO of $3.9 million, $5.4
million and $1.6 million during 1994, 1995 and through May 2, 1996, which was
reflected as an increase in debt to SOCO.

                                      F-9
<PAGE>
 
     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, 1994, 1995 and 1996
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.

                                 1994         1995        1996
                              --------     --------    ---------
                                         (IN THOUSANDS)  
                                                    
     Acquisition               $ 7,556      $   650     $218,380
     Development                88,213       12,141        8,301
     Exploration and other       1,693          429          224
                               -------      -------     --------
                               $97,462      $13,220     $226,905
                               =======      =======     ========
 
     In May 1996, the Merger discussed in Note 1 was consummated. The following
table summarizes the unaudited pro forma effects on the Company's financial
statements assuming that the Merger 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
gas prices, production declines and other factors. Therefore, pro forma
statements cannot be considered indicative of future operations.

<TABLE> 
<CAPTION> 
                                                              YEAR ENDED DECEMBER 31,
                                                     ---------------------------------------
                                                             1995              1996
                                                           -------            ------
                                                       (IN THOUSANDS, EXCEPT PER SHARE DATA)
     <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                       $(.51)          $    .03
     Weighted average shares outstanding                     20,000             19,796
</TABLE>

                                      F-10
<PAGE>
 
(4)  INDEBTEDNESS

     The following indebtedness was outstanding on the respective dates:
 
                                                             DECEMBER 31,
                                                      ------------------------
                                                        1995           1996
                                                      --------       ---------
                                                           (IN THOUSANDS) 
                                                               
      Bank facilities                                  $     -        $ 94,500
      Less current portion                                   -               -
                                                      --------        --------
         Senior debt, net                              $     -        $ 94,500
                                                      ========        ========
                                                               
      Subordinated notes                               $     -        $103,094
                                                      ========        ========
                                                               
      Debt to parent                                   $75,000        $      -
                                                      ========        ========

     As of February 25, 1997, the Company had approximately $185.1 million of
debt outstanding, consisting of $82.0 million of senior debt and $103.1 million
of Subordinated Notes.

     Simultaneously with the Merger, the Company entered into a bank credit
agreement.  The agreement consists of (a) a facility provided to the Company and
SOCO Wattenberg (the "Company Facility") and (b) a facility provided to GOG (the
"GOG Facility").

     The Company Facility is a revolving credit facility in an aggregate amount
up to $102 million. The amount available for borrowing under the Company
Facility is limited to a semiannually adjusted borrowing base that equalled $85
million at December 31, 1996. At December 31, 1996, $67.5 million was
outstanding under the Company Facility. Prior to September 30, 1996, the Company
had a term loan facility in an amount up to $87 million. This term loan facility
was available to fund GOG's repurchases of the Subordinated Notes. At September
30, 1996, the Company had not utilized the term loan facility and it was
canceled.

     The GOG Facility is a revolving credit facility in an aggregate amount up
to $51 million. The amount available for borrowing under the GOG Facility is
limited to a semiannually adjusted borrowing base that equalled $35 million at
December 31, 1996. At December 31, 1996, $27.0 million was outstanding under the
GOG Facility. The GOG Facility was used primarily to refinance GOG's previous
bank credit facility and pay costs associated with the Merger.

     The borrowers may elect that all or a portion of the credit facilities bear
interest at a rate per annum equal to: (i) the higher of (a) prime rate plus a
margin equal to .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
applicable borrower) are offered in the interbank eurodollar market in the
approximated amount of the requested borrowing (the "Eurodollar Rate") plus
1.25% (the "Eurodollar Margin"). During the period subsequent to the Merger
through December 31, 1996, the average interest rate under the facilities
approximated 6.9%.

     The bank 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 bank 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 

                                      F-11
<PAGE>
 
transactions; sale of receivables; prepayment of other indebtedness; amendments
to principal documents; negative pledge clauses; issuance of securities; and
commodity hedging.

     Simultaneously with the Merger, the Company recorded $100 million of 11.75%
Senior Subordinated Notes due July 15, 2004 issued by GOG on July 1, 1994.  In
connection with the Merger, the Company repurchased $1.2 million of the Notes.
The Company has also repurchased an additional $1.4 million of the Notes.  As
part of the purchase accounting, the remaining Notes have been reflected in the
accompanying financial statements at  $103.1 million or 105.875% of their
principal amount.  Interest is payable each January 15 and July 15.  The Notes
are redeemable at the option of GOG, in whole or in part, at any time on or
after July 15, 1999, initially at 105.875% of their principal amount, declining
to 100% on or after July 15, 2001.  Upon the occurrence of a change of control,
as defined in the Notes, GOG would be obligated to make an offer to purchase all
outstanding Notes at a price of 101% of the principal amount thereof.  In
addition, GOG would be obligated, subject to certain conditions, to make offers
to purchase 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.  The
Notes are unsecured general obligations of GOG and are subordinated to all
senior indebtedness of GOG and to any existing and future indebtedness of GOG's
subsidiaries.

     The Notes contain covenants that, among other things, limit the ability of
GOG 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 GOG from incurring indebtedness (exclusive of the Notes) in
excess of approximately $51 million, if after giving effect to the incurrence of
such additional indebtedness and the receipt and application of the proceeds
therefrom, GOG'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 GOG.  GOG currently does not meet the interest coverage ratio necessary to
incur indebtedness in excess of approximately $51 million.

     Prior to the Merger, SOCO financed all of the Company's activities.  A
portion of such financing was considered to be an investment by parent in the
Company with the remaining portion being considered Debt to parent.  The portion
considered to be Debt to parent versus an investment by parent 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 Merger, the $75 million debt to parent was paid 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 (5.5%, 7.0% and 6.9% for
1994, 1995 and the four month period ended May 2, 1996, respectively).

     Scheduled maturities of indebtedness for the next five years are zero for
1997 and 1998, $94.5 million in 1999,  zero in 2000 and 2001.  The long-term
portions of the credit facilities are scheduled to expire in 1999; however, it
is management's intent to review both the short-term and long-term facilities
and extend the maturities on a regular basis.

     There were no cash payments for interest expense in 1994, 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.

                                      F-12
<PAGE>
 
(5)  STOCKHOLDERS' EQUITY

     A total of 40 million common shares, $.01 par value, are authorized of
which 18.9 million were issued and outstanding at December 31, 1996. The Company
issued 6.0 million common shares and 3.0 million warrants exercisable at $12.50
in exchange for all of the outstanding stock of GOG upon consummation of the
Merger. Of the 18.9 million shares outstanding, 2 million are designated as
Series A Common Stock. The Series A Common Stock is identical to the common
shares except that the Series A Common Stock is entitled to three votes per
share rather than one vote per share. The Series A Common Stock is owned by SOCO
and reverts to regular common shares upon certain conditions. Subsequent to the
merger date, the Company repurchased 1,116,700 shares of common stock, 500,000
warrants issued to GOG's former chief executive officer, and 80,549 warrants for
total consideration of $9.7 million. No dividends have been paid on common stock
as of December 31, 1996.

     A total of 5 million preferred shares, $.01 par value, are authorized of
which 1.6 million were issued and outstanding at December 31, 1996. In May 1996,
1.2 million shares of 7.125% preferred stock were issued to certain GOG
preferred shareholders electing to exchange their preferred shares in the
Original Exchange Offer. Thus there were no proceeds received related to this
issuance. In October 1996, GOG's certificate of incorporation was amended to
provide that all shares of GOG's preferred stock not exchanged in the Original
Exchange Offer be exchanged for the Company's 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. 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. The Company paid $2.1 million ($1.78 per 7.125%
convertible share per annum) in preferred dividends during the year ended
December 31, 1996 and had accrued an additional $354,000 at December 31, 1996
for dividends.

     Earnings per share are computed by dividing net income, less dividends on
preferred stock, by weighted average common shares outstanding.  Net income
(loss) applicable to common for 1994, 1995 and 1996, was $2,950,000,
($2,094,000) and $1,433,000, respectively.  Differences between primary and
fully diluted earnings per share were insignificant for all periods presented.

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

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

                                      F-13
<PAGE>
 
     At December 31, 1996, 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:
 
                                                         1996
                                                         ----
 
Net income (loss)                     As Reported       $3,562
                                      Pro forma         $3,281
 
Income (loss) per common share        As Reported       $ 0.08
                                      Pro forma         $ 0.06

     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: dividend yield of 0%; expected volatility
of 30%; risk-free interest rate of 6.4%; and expected life of 4.5 years.

     A summary of the status of the Company's fixed stock option plan as of
December 31, 1996 and changes during the year is presented below (shares are in
thousands):
 
                                                                     1996
                                                                     ----
                                                                Weighted-Average
                                                                     Exercise
                                                       Shares         Price
                                                       ------         -----
 
     Outstanding at beginning of year                      -           $   -
     Granted`                                            532            7.75
     Exercised                                             -               -
     Forfeited                                           (29)           7.75
                                                         ----     
     
     Outstanding at end of year                          503            7.75
                                                         ----     
                                                                  
     Options exercisable at year end                       -               -
 
     Weighted-average fair value of options granted during the year    $2.81
 
     The following table summarizes information about fixed stock options
outstanding at December 31, 1996:

<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       1996        Contractual Life    Exercise Price        1996        Exercise Price
--------------       ----        ----------------    --------------        ----        --------------
<S>             <C>              <C>                 <C>             <C>               <C>  
$   7.75           503,000           4.3 years            $7.75              -               -
</TABLE>

                                      F-14
<PAGE>
 
(6)  FEDERAL INCOME TAXES

     Prior to the Merger, the Company had been included in the 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
Merger, the Company will not be 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, 1994,
1995 and 1996 follows:
 
                                                1994     1995      1996
                                               ------   ------    ------
                                                               
Federal statutory rate                           35%     (35%)      35%
Utilization of net deferred tax asset             -        -       (35%)
Tax benefit recognized prior to Merger            -        -       (12%)
                                               -----     -----     -----
Effective income tax rate                        35%     (35%)     (12%)
                                               =====     =====     =====

For book purposes the components of the net deferred asset and liability at
December 31, 1995 and 1996, respectively, were:
 
                                                      1995     1996
                                                    -------   ------
                                                      (IN THOUSANDS)
Deferred tax assets
  NOL carryforwards                                $ 15,716   $24,586
  Production payment receivables and other              128    27,382
                                                   --------   -------
                                                     15,844    51,968
                                                   --------   -------
Deferred tax liabilities
  Depreciable and depletable property                41,169    48,145
  Investments and other                                   -         -
                                                   --------   -------
                                                     41,169    48,145
                                                   --------   -------
 
Deferred tax assets (liability)                     (25,325)    3,823
                                                   --------   -------
 
Valuation allowance                                       -    (3,823)
                                                   --------   -------
 
Net deferred tax asset (liability)                 $(25,325)  $     -
                                                   ========   =======

     For tax purposes, the Company had regular net operating loss carryforwards
of $70.2 million and alternative minimum tax ("AMT") loss carryforwards of $35.1
million at December 31, 1996.  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 merger of GOG and SOCO
Wattenberg Corporation on May 2, 1996. These carryforwards expire from 2006
through 2011.  At December 31, 1996, the Company had alternative minimum tax
credit carryforwards of $478,000 which are available indefinitely.  No cash
payments were made by the Company for federal taxes during 1995 and 1996.  As
discussed in Note 1, the accompanying financial statements include certain
Wattenberg operations previously owned directly by SOCO.  Accordingly, certain
operating losses generated by these properties were retained by SOCO.  In
addition, certain taxable income generated by SOCO did not offset the Company's
net operating loss carryforwards.  Prior to the Merger, the effect of such items
has been reflected as a charge or credit in lieu of taxes in the Company's
consolidated statement of changes in stockholders' equity.

 

                                      F-15
<PAGE>
 
(7)  MAJOR CUSTOMERS

     During 1996, PanEnergy, Inc. accounted for 38% of revenues.  During 1994,
1995 and 1996, Amoco Production Company accounted for 25%, 22% and 19%,
subsidiaries of SOCO accounted for 59%, 46% and 0%, and Total Petroleum
accounted for 15%, 20% and 10%,  of revenues, respectively.  Management believes
that the loss of any individual purchaser would not have a long-term material
adverse impact on the financial position or results of operations of the
Company.


(8)  RELATED PARTY

     Prior to the Merger, 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 Merger, certain field, administrative and executive employees
of SOCO and GOG became employees of the Company.  SOCO will continue to provide
certain services to Patina under a corporate services agreement. During 1996,
the Company paid approximately $650,000 to SOCO under the corporate services
agreement.


(9)  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 1997 through 2001.

     In August 1995, SOCO was sued in the United States District Court of
Colorado by plaintiffs purporting to represent all persons who, at any time
since January 1, 1960, have had agreements providing for royalties from gas
production in Colorado to be paid by SOCO under various lease provisions.  In
January 1997, the judge denied the plaintiffs' motion for class certification.
Substantially all liability under this suit was assumed by the Company  upon its
formation.  In January 1996, GOG was also sued in a similar but separate action
filed in the Colorado State Court.  The plaintiffs, in both suits, allege that
unspecified "post-production" costs incurred prior to calculating royalty
payments were deducted in breach of the relevant lease provisions and that this
fact was fraudulently concealed.  The plaintiffs seek unspecified compensatory
and punitive damages and a declaratory judgment prohibiting the deduction of
post-production costs prior to calculating royalties paid to the plaintiffs. The
Company believes that costs deducted in calculating royalties are and have been
proper under the relevant lease provisions, and they intend to defend these and
any similar suits vigorously.  At this time, the Company is unable to estimate
the range of potential loss, if any.  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 impact on results for that period.

     In March 1996, a complaint was filed in the Court of Chancery for the State
of Delaware against GOG 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 the defendants from consummating a merger
which will benefit the holders of GOG's common stock at the expense of the
holders of the Preferred and (b) to obtain a declaration that the terms of the
proposed merger constitute a breach of the contractual rights of the Preferred."
The complaint seeks, among other things, certification as a class action on
behalf of all holders of GOG'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 Merger and money damages.
Defendants believe that the complaint is without merit and intend to vigorously
defend against the 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 

                                     F-16
<PAGE>
 
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 impact 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.


(10) UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

     Independent petroleum consultants directly evaluated 89%, 100% and 100% of
proved reserves at December 31, 1994, 1995 and 1996, respectively. All reserve
estimates are based on economic and operating conditions at that time. Future
net cash flows as of each year and 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 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-17
<PAGE>
 
<TABLE>
<CAPTION>
QUANTITIES OF PROVED RESERVES ---
                                                 CRUDE OIL   NATURAL GAS
                                                 ----------  ------------
                                                   (MBBL)       (MMCF)
<S>                                              <C>         <C>
     Balance, December 31, 1993                     16,928       229,862
        Revisions                                   (4,450)      (50,021)
        Extensions, discoveries and additions        1,372        20,900
        Production                                  (1,829)      (23,893)
        Purchases                                      197         1,855
        Sales                                            -             -
                                                    ------       -------
 
     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
                                                    ======       =======
 
PROVED DEVELOPED RESERVES ---
 
                                                 CRUDE OIL   NATURAL GAS    
                                                 ----------  ------------   
                                                   (MBBL)       (MMCF)      
                                                                            
December 31, 1993                                    7,365       136,765    
                                                    ======       =======    
December 31, 1994                                    8,832       147,869    
                                                    ======       =======    
December 31, 1995                                    6,955       133,088    
                                                    ======       =======    
December 31, 1996                                   15,799       242,777    
                                                    ======       =======     
</TABLE>

                                     F-18
<PAGE>
 
<TABLE>
<CAPTION>
STANDARDIZED MEASURE ---
                                                       DECEMBER 31,
                                           -----------------------------------
                                                  1995               1996
                                           ---------------    ----------------
                                                     (IN THOUSANDS)
<S>                                        <C>         <C>          <C>
Future cash inflows                        $ 356,224                $1,668,475
Future costs:
 Production                                 (100,505)                 (338,752)
 Development                                 (13,428)                 (160,856)
                                           ---------                ----------
Future net cash flows                        242,291                 1,168,867
Undiscounted income taxes                    (29,873)                 (294,407)
                                           ---------                ----------
After tax net cash flows                     212,418                   874,460
10% discount factor                          (84,902)                 (374,524)
                                           ---------                ---------- 
Standardized measure                       $ 127,516                $  499,936 
                                           =========                ==========  
</TABLE> 
 
 
CHANGES IN STANDARDIZED MEASURE ---

<TABLE> 
<CAPTION> 
                                                  YEAR ENDED DECEMBER 31,
                                           ----------------------------------
                                             1994         1995        1996
                                           ---------   ----------   ---------
                                                    (IN THOUSANDS)
<S>                                        <C>         <C>          <C>     
Standardized measure, beginning of year    $ 191,011   $  161,481   $  127,516
Revisions:                                                                    
 Prices and costs                            (56,928)       2,240      351,724
 Quantities                                  (29,498)     (14,230)         501
 Development costs                            (8,044)      (1,182)     (11,024)
 Accretion of discount                        19,101       16,148       27,619
 Income taxes                                 23,121       10,963     (129,612)
 Production rates and other                   (8,422)     (21,265)      (3,706)
                                           ---------   ----------   ----------
 Net revisions                               (60,670)      (7,326)     235,502
Extensions, discoveries and additions         19,583        2,064        3,791
Production                                   (58,099)     (40,877)     (67,666)
Future development costs incurred             67,484       12,192        7,906
Purchases (a)                                  2,172            -      193,998
Sales (b)                                          -          (18)      (1,111)
                                           ---------   ----------   ----------
Standardized measure, end of year          $ 161,481   $  127,516   $  499,936
                                           =========   ==========   ========== 
</TABLE>

(a)   "Purchases" includes the present value at the end of the period acquired
during the year plus the 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-19
<PAGE>
 
PART IV.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 10-K


(a)  Exhibits -

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

     2.2       Business Opportunity Agreement -- incorporated herein by
               reference to Exhibit 2.2 to the Company's Form 8-K dated May 2,
               1996 (Commission file number 1-14344)

     2.3       Corporate Services Agreement -- incorporated by reference to
               Exhibit 2.3 to the Registration Statement on Form S-4 of Patina
               Oil & Gas Corporation (Registration No. 333-572)

     2.4       Registration Rights Agreement -- incorporated herein by reference
               to Exhibit 2.4 to the Company's Form 8-K dated May 2, 1996
               (Commission file number 1-4344)

     2.5       Cross Indemnification Agreement -- incorporated herein by
               reference to Exhibit 2.5 to the Company's Form 8-K dated May 2,
               1996 (Commission file number 1-14344)

     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)

     10.1.1    Credit Agreement dated as of May 2, 1996 among the Company,
               Gerrity Oil & Gas Corporation and SOCO Wattenberg Corporation, as
               Borrowers, certain financial institutions, and Texas Commerce
               Bank National Association, as Administrative Agent, and certain
               commercial lending institutions -- incorporated herein by
               reference to Exhibit 10.1 to the Company's Form 8-K dated May 2,
               1996 (Commission file number 1-4344)

     10.1.2    First Amendment to Credit Agreement dated June 28, 1996 by and
               among the Company, Gerrity Oil & Gas Corporation and SOCO
               Wattenberg Corporation, as Borrowers, and Texas Commerce Bank
               National Association, as Administrative Agent, and certain
               commercial lending institutions --incorporated herein by
               reference to Exhibit 10.1.1 to the Company's Form 10-Q for the
               quarter ending June 30, 1996 (Commission file number 1-14344)

     10.1.3    Second Amendment to Credit Agreement effective October 8, 1996 by
               and among the Company, Gerrity Oil & Gas Corporation and SOCO
               Wattenberg Corporation, as Borrowers, and Texas Commerce Bank
               National Association, as Administrative Agent, and certain
               commercial lending institutions --incorporated herein by
               reference to Exhibit 10.74 of the Company's Form 10-Q for the
               quarter ending September 30, 1996 (Commission file number 1-4344)

                                     F-20
<PAGE>
 
     10.1.4    Third Amendment to Credit Agreement effective November 1, 1996 by
               and among the Company, Gerrity Oil & Gas Corporation and SOCO
               Wattenberg Corporation, as Borrowers, and Texas Commerce Bank
               National Association, as Administrative Agent, and certain
               commercial lending institutions --incorporated herein by
               reference to Exhibit 10.75 of the Company's Form 10-Q for the
               quarter ending September 30, 1996 (Commission file number 1-
               14344)

     10.3      Agreement dated July 16, 1996 by and between F. H. Smith,
               employee, and the Company --incorporated herein by reference to
               Exhibit 10.3 of the Company's Form 10-Q for the quarter ending
               June 30, 1996 (Commission file number 1-14344)

     10.3.1    Deferred Compensation Plan for Selected Employees adopted by the
               Company effective May 1, 1996.*

     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 ending June 30, 1996 (Commission file
               number 1-14344)

     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 10.76 of the Company's Form 10-Q for the quarter ending
               September 30, 1996 (Commission file number 1-14344)

     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.*

     99        Reserve letter from Netherland, Sewell & Associates, Inc. Dated
               February 5, 1997 to the Patina Oil & Gas Corporation interest as
               of December 31, 1996.*

*Filed herewith


(b)  Reports on Form 8-K -

     On May 17, 1996, the Company filed with the Securities and Exchange
     Commission a Current Report on Form 8-K.  The Report disclosed under Item 1
     information regarding the approval of the Amended Agreement and Plan of
     Merger among Snyder Oil Corporation, the Company, Patina Merger Corporation
     and Gerrity Oil & Gas Corporation.

                                     F-21
<PAGE>
 
                                   SIGNATURES


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

<TABLE> 
<CAPTION> 
<S>                            <C>                                      <C> 
/s/ Thomas J. Edelman          Chairman of the Board and President      March 4, 1997
----------------------------
Thomas J. Edelman              (Principal Executive Officer)


/s/ Brian J. Cree              Director, Executive Vice President       March 4, 1997
----------------------------   
Brian J. Cree                  and Chief Operating Officer


/s/ Robert J. Clark            Director                                 March 4, 1997
----------------------------
Robert J. Clark


/s/Jay W. Decker               Director                                 March 4, 1997
----------------------------
Jay W. Decker


/s/ William J. Johnson         Director                                 March 4, 1997
----------------------------
William J. Johnson


/s/ Alexander P. Lynch         Director                                 March 4, 1997
----------------------------
Alexander P. Lynch


/s/ John C. Snyder             Director                                 March 4, 1997
----------------------------
John C. Snyder


/s/ David J. Kornder           Vice President and Chief Financial 
----------------------------
David J. Kornder               Officer                                  March 4, 1997
</TABLE> 

                                     F-22