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


                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                             -----------------------
                                    Form 10-K


(Mark one)
[X]                ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 1997

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

                         Commission file number 1-10509


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

                             Snyder Oil Corporation
             (Exact name of registrant as specified in its charter)

             Delaware                                     75-2306158
   (State or other jurisdiction of                      (IRS Employer
    incorporation or organization)                    Identification No.)

          777 Main Street                                    76102
         Fort Worth, Texas                                 (Zip Code)
(Address of principal executive offices)
 
        Registrant's telephone number, including area code (817) 338-4043

               Securities registered pursuant to Section 12(b) of the Act:
            
                                                   Name of each exchange
             Title of each class                    on which registered
       -------------------------------        ------------------------------- 
                Common Stock                      New York Stock Exchange
       Preferred Stock Purchase Rights            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.
                                Yes X      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. [ ]

Aggregate market value of the common stock held by non-affiliates of the
 registrant as of February 27, 1998.................................$571,824,508
Number of shares of common stock outstanding as of February 27, 1998..33,392,696


                       DOCUMENTS INCORPORATED BY REFERENCE
         Part  III  of  this  Report  is   incorporated   by  reference  to  the
Registrant's  definitive  Proxy  Statement  relating  to its  Annual  Meeting of
Stockholders,  which will be filed with the  Commission  no later than April 30,
1998.


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



<PAGE>


                             SNYDER OIL CORPORATION

                           Annual Report on Form 10-K
                                December 31, 1997

                                     PART I

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

General

         Snyder Oil Corporation (the "Company") is an independent energy company
engaged in the production, development,  acquisition and exploration of domestic
oil and gas properties, primarily in the Gulf of Mexico, the Rocky Mountains and
northern Louisiana.  During 1997, the Company's revenues were $255.7 million and
cash flow provided by operations was $122.0  million.  At December 31, 1997, the
Company's  proved  reserves  totaled  77.3  million  barrels  of oil  equivalent
("BOE"),  having a pretax  present  value,  discounted  at 10% based on constant
prices and costs ("Pretax PW 10% Value") of $375.3 million. Approximately 78% of
these reserves are natural gas.

         During 1997,  the Company  undertook  efforts to simplify its corporate
structure.  The  simplification  and  repositioning  resulted in the bulk of the
Company's  asset value being  concentrated  in  properties  the Company owns and
operates  directly.  Three primary  initiatives  were  completed in 1997 towards
reaching this goal.

                  Patina Oil & Gas  Corporation.  In October  1997,  the Company
         sold its entire 74% stake, or 14 million shares of the common stock, of
         Patina Oil & Gas Corporation ("Patina").  The Company sold 10.9 million
         shares of Patina  stock in a  secondary  offering,  with the  remainder
         repurchased by Patina. This transaction  generated $127 million in cash
         while  removing  approximately  $170  million  of Patina  debt from the
         Company's consolidated balance sheet.

                  SOCO International, Inc. In May 1997, SOCO International, Inc.
         ("SOCO   International")   transferred   its  90%   interest   in  SOCO
         International Operations, Inc. ("Operations"), which held the Company's
         investments in Mongolia, Russia and Thailand, to SOCO International plc
         ("SOCI plc"), a recently formed United Kingdom company, in exchange for
         shares of SOCI plc stock.  SOCI plc also  acquired  the  interests of a
         number of minority  investors  in  Operations'  ventures  and assets in
         Yemen, Tunisia and onshore England from Cairn Energy plc ("Cairn").  At
         the time of the  acquisitions,  SOCI plc, which is listed on the London
         Stock  Exchange,  completed a public offering of its common shares that
         raised  approximately  $75  million of new  equity  capital to fund its
         continuing  exploration and development  expenditures.  The 7.8 million
         shares of SOCI plc  acquired  by the  Company  represent  approximately
         15.9% of SOCI plc and had a market  value of $45.1  million at February
         27, 1998.  Under London Stock Exchange  rules,  the Company will not be
         permitted to sell these shares  prior to May 1999.  Edward T. Story,  a
         director and former Vice President - International  of the Company,  is
         the chief executive officer of SOCI plc.

                  Capital   Structure.   The  Company   completed  a  series  of
         transactions  in 1997 to simplify its capital  structure  and eliminate
         the potential dilution to common shareholders.  At January 1, 1997, the
         Company had 42.0 million  common  shares on a fully diluted  basis.  By
         December  31,  1997,   the  Company  had  33.3  million  common  shares
         outstanding   with  no  convertible   securities   outstanding.   These
         transactions consisted of the following:

                   *  In first  quarter  1997,  the  Company  sold  4.5  million
                      shares, or 28% of its holdings in Cairn. Net proceeds from
                      the sales were $39.2 million  resulting in a $13.0 million
                      gain. The Company continues to hold 11.7 million shares of
                      Cairn with a market value of $80.1 million at February 27,
                      1998. The Company may maintain its investment, sell all or
                      part of it, either in one  transaction  or  gradually,  or
                      pursue other courses of action.  Any decision,  when made,
                      will be made in light of  strategic,  financial  and other
                      factors deemed appropriate by management.



<PAGE>



                   *  The   Company   redeployed   the  cash   from  the   Cairn
                      transactions  into  its  securities   repurchase  program,
                      underscoring management's belief that the Company's common
                      stock has been undervalued in the market. During the year,
                      the  Company  repurchased  2.6 million  common  shares for
                      $45.6 million or an average of $17.24 per share.

                   *  In June 1997,  the Company  issued $175  million  of 8.75%
                      senior   subordinated   notes  due  2007.   Following  the
                      issuance,    the   Company    redeemed   its   convertible
                      subordinated notes due 2001. The notes were redeemed for a
                      price of 103.51% of principal plus accrued interest. These
                      transactions  extended the maturity of the indebtedness by
                      six years and  eliminated  the  potential  issuance of 3.6
                      million  shares of common stock on  conversion  of the old
                      notes.

                   *  In October 1997, the Company issued 300,000 shares of  its
                      common  stock  in  exchange  for  warrants  held by  Union
                      Pacific Resources to purchase 2.1 million of the Company's
                      common shares.

                   *  In the fourth quarter 1997, the Company called all of  the
                      depositary shares representing  interests in the Company's
                      $6.00 Convertible  Exchangeable Preferred Stock. The calls
                      resulted  in  the  Company  converting  a  portion  of the
                      preferred shares into  approximately 3.6 million shares of
                      common stock. The Company redeemed the remaining preferred
                      shares  for  $30.1  million  in  cash.  The  calls  of the
                      preferred  shares  eliminated 1.4 million common shares of
                      potential  dilution and over $6 million a year in dividend
                      payments.

          As a result of the capital restructuring,  all of the Company's growth
potential  will benefit its common  shareholders.  Redeployment  of the cash and
marketable  securities  held by the  Company  into an  acquisition  or series of
acquisitions is a strategic objective of the Company.


Operations

         The Company's operations are focused on three core areas, each with the
potential to contribute significantly to future growth:

  *  Offshore.  The  Company  had proved  reserves in the Gulf of Mexico of 19.3
     million BOE with a Pretax PW 10% Value of $170.5  million  at  December 31,
     1997. These reserves are concentrated in the Pabst, Busch and Ingrid Fields
     of the Main Pass area offshore Louisiana and Alabama.  Through  the  end of
     1997,  production  from   the  Pabst  and   Busch  Fields  had  often  been
     restricted  to 100 MMcf (42 MMcf net) of gas per day but  increased to more
     than 150 MMcf (63 MMcf net) per day  following  the  expansion  of pipeline
     capacity  serving  these  fields in January  1998.  The Company  intends to
     complete  installation  of a platform and production  facilities with total
     initial  capacity of 150 MMcf per day on its 50%-owned  Ingrid Field,  with
     production  commencing  by April  1998.  The  Company  plans to expand  its
     activities in the Gulf of Mexico  significantly  and has budgeted up to $50
     million for development and exploration in this area in 1998.

  *  North  Louisiana.  The Company  owns over 330,000  net  mineral acres, with
     leases  and  lease  options  covering  more  than  150,000  additional  net
     acres,  in   North  Louisiana.  The  Company  has  identified  a  number of
     exploration  prospects  as a result  of two 3-D  seismic  surveys  covering
     approximately  166 square miles.  Two partners earned a one-third  interest
     each in these  prospects  by  paying  all of the  costs  of  these  seismic
     surveys.  Based on these  surveys,  the Company  expects to begin  drilling
     activities  in North  Louisiana  in the  first  half of 1998.  The  Company
     expects its  expenditures  in North  Louisiana to total  approximately  $15
     million in 1998.

  *  Rocky  Mountains.  The  Company  had proved  reserves  in Wyoming,  western
     Colorado  and Utah of 56.5 million BOE with a Pretax PW 10% Value of $193.3
     million at December  31,  1997.  These  reserves  are  concentrated  in gas
     development programs in the Washakie,  Green River and Piceance Basins, and
     in two large,  mature  non-operated  oil fields in  northern  Wyoming.  The
     Company  has also  initiated  gas  projects  in the Wind River and Big Horn
     Basins in Wyoming  and an oil  project in Utah.  The  Company  formed a gas
     marketing  joint venture with Coastal  Corporation,  one of the largest gas
     marketers  in North  America,  effective  January 1, 1997.  The Company has
     budgeted up to $70 million for continued development and exploration in the
     western Rocky Mountains during 1998.

                                       2

<PAGE>


Summary information at December 31, 1997 regarding the Company's projects is set
forth in the following table.
<TABLE>
<CAPTION>

                                                            Proved Reserve Quantities
                             Gross         Net        ---------------------------------------          Pretax PW 10% Value
                           Producing   Undeveloped    Crude Oil     Natural           Oil           -------------------------   
                            Wells        Acres        & Liquids       Gas          Equivalent         Amount        Percent
                           ---------   -----------    ----------    -------        ----------       ----------    -----------
                                                        (MBbl)       (MMcf)          (MBOE)            (000)

<S>                         <C>        <C>              <C>         <C>              <C>             <C>             <C>
Offshore
   Main Pass Area              18        9,167           1,094       96,433          17,167          $ 161,783        43%
   Other                       23         -                285       10,994           2,117              8,734         2
                           -------    ---------        --------    ---------        --------         ----------     ------
   Total Offshore              41        9,167           1,379      107,427          19,284            170,517        45

North Louisiana                14(a)   346,773(b)           57        2,041             397              3,313         1
Other                          86        1,533             104        6,099           1,120              8,177         2
                          --------    ---------        --------    ---------        --------         ----------     ------
   Southern Region            141      357,473           1,540      115,567          20,801            182,007        48
                          --------    ---------        --------    ---------        --------         ----------     ------



Washakie (WY)                 174       75,174           1,341      139,307          24,559             95,766        26
Piceance (CO)                  87       42,641             150       33,669           5,761             21,597         6
Deep Green River (WY)          30       41,555             373       48,661           8,483             32,619         9
Wind River (WY)                26       38,626             447       20,999           3,947             13,726         4
Big Horn (WY)                 -         77,955            -            -               -                  -            -
Northern Wyoming              902         -             12,313          566          12,407             24,655         6
Uinta (UT)                    126       71,244             596        4,399           1,330              4,904         1
                          --------    ---------        --------    ---------        --------         ----------     ------
   Rocky Mountain Region    1,345      347,195          15,220      247,601          56,487            193,267        52
                          --------    ---------        --------    ---------        --------         ----------     ------
   Total Company            1,486      704,668          16,760      363,168          77,288          $ 375,274       100%
                          ========    =========        ========    =========        ========         ==========     ======

<FN>
(a)   Excludes royalty interests in 101 wells.
(b)   Excludes 130,000 net acres under option as of February 27, 1998.
</FN>
</TABLE>

                            Offshore - Gulf of Mexico

          The   Company   believes   many  areas  in  the  Gulf  of  Mexico  are
under-exploited  and,  while having greater  risks,  the potential  benefits and
exposure to additional markets complement the Company's onshore activities.  The
Company  began  developing an asset base in the offshore Gulf of Mexico in 1994,
and currently  operates 10 platforms  accounting  for  substantially  all of the
production from this core area.  During 1997, the Company spudded 9 wells, a 28%
increase  over the 7 wells  drilled in 1996.  Since  inception,  the Company has
recorded a 60% success ratio in its exploratory program (3 out of 5 wells) and a
success ratio of 94% in its development program (17 out of 18 wells).

         At year end, total offshore  proved reserves were 19.3 million BOE (1.4
million  barrels  of oil and 107.4 Bcf of gas),  up from 17.4  million  BOE (2.4
million  barrels of oil and 90.0 Bcf of gas) at year end 1996.  This  represents
approximately  25% of year end  reserve  quantities,  but 45% of  Pretax  PW 10%
Value.  The Company has interests in 41 (17.5 net) wells, 38 (17.2 net) of which
are operated,  and 83,000 gross  (47,000 net) acres.  Production in 1997 was 3.9
million BOE compared to 1.6 million BOE in 1996.  Fourth quarter 1997 production
totaled 960 thousand BOE.

         In the fourth  quarter of 1997,  the Company  made a major  purchase of
seismic data covering  approximately 250 offshore blocks, or 2,250 square miles,
in  the  Main  Pass/Viosca   Knoll  area.  The  offshore  staff  of  exploration
professionals  has doubled in the last six months to facilitate new  exploration
and exploitation of existing fields.

         The Gulf of  Mexico  will  continue  to be a major  focus  area for the
Company.  Estimated 1998 capital expenditures are expected to total $50 million,
including $12 million to install or upgrade platforms and related facilities and
to complete  three  development  wells.  The  remainder  is for the  purchase of
additional seismic data and to drill up to twelve exploratory wells. The Company
will continue its acquisition efforts in the area and the evaluation of existing
properties for additional exploratory or development potential.

                                       3

<PAGE>

         Pabst/Busch Fields. The Pabst (Main Pass 259) and Busch (Main Pass 255)
Fields are located in the Main  Pass/Viosca  Knoll area  offshore  Louisiana and
Alabama.  The Company  continued  development  and exploration on and around the
Pabst and Busch fields during 1997. Three  development wells were drilled at the
Busch  field to the 7,900  foot  Miocene  sand  bringing  the total to six wells
producing  from this field.  Two  development  wells were drilled from the Pabst
platform and one  recompletion  and one workover were also conducted  during the
year.  The 12 wells at the Pabst field  produce  from a series of Miocene  zones
ranging from 7,700 to 11,500 feet.  The Company  drilled a dry hole in Main Pass
248 during 1997 which is northwest of the Pabst platform.

         The Company had firm  transportation  on Viosca Knoll Gathering  System
for 100 MMcf per day gross (41 MMcf per day net) covering both platforms  during
1997. The Pabst platform  facilities are capable of production rates of 110 MMcf
per day and the Busch platform facilities were capable of 60 MMcf per day before
the  upgrade  in 1998.  As of year end,  the 12 wells  producing  from the Pabst
platform had a combined  gross well  deliverability  of 175 MMcf per day and the
six  wells  producing  from  the  Busch  platform  had  a  combined  gross  well
deliverability  of 120 MMcf per day. During 1997, the Company's  production from
the two  platforms  was  limited  by both the take away  capacity  and  platform
facilities constraints.

         During 1997, the Company generally  produced the wells at Main Pass 259
in favor of the wells at Main Pass 255 due to the  greater  condensate  yield at
Main Pass 259, except when additional  interruptible  space was available on the
Viosca Knoll system.  Net production from the two fields averaged 56.2 MMcfe per
day in 1997  compared  to  19.7  MMcfe  per day in  1996.  The  increase  in net
production  was primarily  the result of including  prior year  acquisitions  of
additional interests for the full year.

         The  pipeline  take  away   constraints   were  improved  for  existing
deliverability  when  Viosca  Knoll  system  looped its 20 inch line in December
1997.  Effective January 1998, the Company's take away capacity increased to 175
MMcf per day gross (72 MMcf per day net) for the two platforms. In addition, the
Main Pass 255  facilities  were  upgraded  by the  installation  of  compression
increasing the platform production  capabilities from 55 MMcf per day to 90 MMcf
per day.

         At the end of 1997, proved reserves totaled 62.0 Bcf of gas and 297,000
barrels of oil or 10.6  million  BOE, as compared to 52.1 Bcf of gas and 932,000
barrels of oil, or 9.6 million BOE at year end 1996.  The Pretax PW 10% Value at
December  31, 1997 was $109.4  million.  This  increase in reserves is primarily
attributable  to better than expected  performance  and extensions of the fields
resulting from further  development work. Two exploratory wells are scheduled to
be drilled during 1998.

         Ingrid Field.  The Ingrid Field (Main Pass 261) was discovered in 1996,
with a second confirmation well also drilled in the same year. The Company has a
50% working interest and a 37% net revenue  interest.  Proved reserves from both
wells  were  discovered  in the Tex W sands  series at  approximately  11,000 to
13,000 feet.  During 1997, the Company focused on the installation of a platform
for production  operations and arranging for transportation  and marketing.  The
Main Pass 261 platform  facilities are under  construction with 150 MMcf per day
capacity.  The  platform  jacket was  installed  in August  1997 and the deck in
February  1998.  Tie in of the  facilities is underway and  production  from the
first two wells is expected to  commence in April 1998.  Initial  transportation
has been  arranged  on  Viosca  Knoll  system  at 75 MMcf  per day  gross to the
Company's  working  interest  (56 MMcf per day net) until a second  pipeline  is
available  in the second half of 1998.  The new  pipeline  system  will  connect
onshore Alabama directly to the Main Pass 261 platform. An extension of the line
will then  connect the Main Pass 261  platform to the Main Pass 259  platform at
the Pabst  field.  The  Company  has firm  transport  in the new system to cover
projected production volumes from the Main Pass area and will retain 60 MMcf per
day gross of firm transport to the Company's  working  interest (41 MMcf per day
net) on the Viosca Knoll system.

         In the fourth quarter of 1997, two additional wells were spudded and in
progress  at year end.  Pipe was set on both  wells and the  Company  expects to
complete and further  test the wells after  initial  production  begins from the
Ingrid  platform.  Two  additional  wells are planned for 1998 at Main Pass 261.
Total proved  reserves in the field for the Company's  interest were 6.5 million
BOE (34.4 Bcf of gas and 798,000  barrels of oil) at year end,  with a Pretax PW
10% Value of $52 million.

         Other Gulf of Mexico. The Company has interests and operates in several
other areas in the Gulf of Mexico,  with working  interests  ranging from 14% to
100%.  During  1998,  the Company  will  continue to evaluate  these  blocks for

                                       4

<PAGE>

additional  exploratory  or  development  potential  using 3-D seismic data. The
Company  plans to drill up to four  exploratory  wells to test  these  prospects
during 1998 and 1999.  The Company  also  intends to subsea  complete  the South
Timbalier  231 #1 well and tie it back to an adjacent  platform.  Production  is
expected to begin in third quarter of 1998.


                                 North Louisiana

         The  Company's  focus in North  Louisiana  in 1998 is to drill and test
several  different  reef  settings  that were  identified  with the 3-D  seismic
program.  During 1996 and 1997,  the Company and its partners  conducted two 3-D
seismic  surveys  covering 166 square miles in three  acreage  blocks out of the
Company's over 560,000 acres  controlled in the area.  Merging and  interpreting
the two data sets was completed in 1997.  The Company is preparing to drill four
exploratory wells targeting  different types of reef anomalies at depths between
15,000 and 17,000 feet. The first well is scheduled for second quarter 1998, and
a second rig is  expected  to begin  drilling  shortly  thereafter.  These wells
require approximately 90 to 100 days to drill and an additional 30 to 60 days to
complete  and test.  Results from the first two wells are expected in late third
or early fourth quarter 1998. If successful,  the Company has mapped  sufficient
reef anomalies to support a multi-rig  drilling  program  beginning in 1999. The
Company retains a 33% working interest in the current  prospects within the area
of  the  seismic  surveys  and  is  the  operator  of  drilling  and  production
activities.

         The Company  has over 6,000 miles of 2-D seismic  data over its mineral
holdings in North  Louisiana and has mapped  numerous reef  anomalies as well as
untested  salt domes and  associated  drilling  prospects  in the Cotton  Valley
Sands, Hosston Sands and Cretaceous Limes.  Additional 3-D surveys to extend the
play  are  expected  to  commence  late in 1998  pending  drilling  results.  In
addition,  the Company retains the option to increase its working  interest from
33% to 50% in subsequent 3-D surveys and associated prospects.


                                 Rocky Mountains

         The  Company's  Rocky  Mountain  Region  continues  to focus on several
growth areas in the western Rockies. The Company increased its drilling activity
in 1997  by 65%,  drilling  a total  of 71  wells  and  positioning  itself  for
continued  future  growth.  The Company's core  development  projects are in the
Washakie,  Green River, and Piceance Basins. These projects continue as the main
thrust of the Region's activity; however, drilling success in the Wind River and
Big Horn Basins in 1997 and  additional  drilling in 1998 provides the potential
for these areas to add significant future growth in production and reserves.

         Washakie Basin. Since the mid-1980's,  the Company's  properties in the
Barrel  Springs Unit, the Blue Gap Field and the North Standard Draw area of the
Washakie  Basin  in  southern  Wyoming,  together  with  its gas  gathering  and
transportation  facilities there, have been one of its most significant  assets.
During 1997, the Company  continued to develop  Mesaverde  sands in the Washakie
Basin near its existing properties.  Nineteen wells were put on sales in 1997 at
depths  ranging from 8,000 to 11,500  feet.  Five wells were in progress at year
end.  Net  production  of  gas,  which  accounts  for  approximately  95% of the
reserves,  during the year  averaged  29.5 MMcf per day,  as compared to average
1996  production of 25.4 MMcf per day.  Proved  reserves at year end totaled 1.3
million barrels of oil and 139.3 Bcf of gas, or 24.6 million BOE, as compared to
1.1 million barrels and 133.1 Bcf, or 23.3 million BOE, at the end of 1996. This
increase  in  reserves  is  primarily   attributable  to  better  than  expected
performance  and extensions of the field.  The Company expects to accelerate its
activity  in this area in 1998,  with plans to drill 32 to 36 wells at net costs
expected to range from  $500,000 to $775,000 per well.  Significant  portions of
this area are the subject of a currently pending environmental impact statement.
Pending approval of the statement, which is not expected until 1999, drilling in
the affected areas will be limited.

         The Company  currently  operates  146 wells in the  Washakie  Basin and
holds hundreds of potential drilling  locations,  40 of which were classified as
proved   undeveloped  at  year  end  1997.   The  Company  holds   interests  in
approximately 95,000 gross (75,000 net) undeveloped acres in this area.

         Deep Green River.  Through the year, the Company continued  development
of the fluvial  Lance sands in the deep  portion of the Green River  Basin.  The
Company  participated  in 19 wells during  1997,  with five wells in progress at
year end. Year end proved  reserves  totaled 373,000 barrels of oil and 48.7 Bcf
of gas, or 8.5 million  BOE, as compared to 175,000  barrels of oil and 21.7 Bcf
of gas,  or 3.8  million  BOE,  at year end 1996.  This  increase in reserves is

                                       5

<PAGE>

primarily attributable to better than expected performance and extensions of the
field. With 30 wells, 19 of which are operated by the Company,  on sales at year
end,  net  production  averaged  1,733 BOE per day during  1997.  This more than
doubled 1996's average production of 829 BOE per day, despite the Company's sale
of 50% of its interest in the project to an industry  partner in July 1996.  The
Company holds interests in  approximately  92,000 gross (42,000 net) undeveloped
acres in this  project.  At the end of 1997,  proved  undeveloped  reserves were
assigned to 20 locations.  The Company  expects to participate in drilling 25 to
30 wells  in 1998.  Further  expansion  of  drilling  in this  area is  awaiting
approval of an environmental impact statement,  which if approved as expected in
April 1998, will allow the Company to participate in drilling 30 to 40 wells per
year after 1998.

         Piceance Basin.  The Company operates the 53,000 acre Hunter Mesa Unit,
the 9,000  acre Grass Mesa Unit and the  26,000  acre  Divide  Creek Unit in the
southeast  portion  of the  Piceance  Basin.  At year  end,  the  Company  owned
approximately  97,000 gross (43,000 net) undeveloped  acres in this area. During
1997, the Company  participated in 23 new wells to develop and further delineate
the fields.  Twenty-two  wells  (including  one in progress at the  beginning of
1997)  were  put on  sales,  and two  were in  progress  at  year  end.  Net gas
production  averaged 8.8 MMcf per day in 1997.  This is down  slightly  from 9.5
MMcf per day in 1996  reflecting  the  Company's  sale of 45% of its interest in
this project in May 1996. At year end 1997, there were 87 producing wells, 72 of
which are operated by the Company.  Proved reserves at year end were 33.7 Bcf of
gas and 150,000  barrels of oil, or 5.8 million  BOE, as compared  with 32.2 Bcf
and 118,000 barrels,  or 5.5 million BOE, at year end 1996.  Proved  undeveloped
reserves  were  assigned to 11  locations  at year end 1997.  During  1998,  the
Company plans to drill 30 to 33 wells to further  develop the Company's  acreage
positions  and  evaluate  the fields.  The primary  objective of drilling is the
fluvial sands of the  Mesaverde  formation at depths of 4,500 to 8,500 feet.

         Wind River Basin.  The Company owns the Riverton  Dome field,  a 33,000
acre  option on Tribal  lands  north and east of the  field,  and a 64,000  acre
primarily undeveloped lease block east of the option lands. The Company acquired
a 3-D seismic survey over the option lands in 1997 and plans to acquire one over
the Riverton Dome field and another on the option lands in 1998. The Company has
a 50% working  interest in the option lands and in the eastern  lease block.  In
late 1997,  a new Frontier  well was  completed on the Tribal block with initial
production  over 2,000 Mcf per day.  The  Company  plans to drill four 50% owned
Frontier wells in 1998.

         The Riverton Dome field produces  approximately  5,000 Mcf per day from
the Frontier  and  Phosphoria  formations  and 160 BOE per day from the Tensleep
formation. The Company owns 100% working interest in the 26 wells in this field.
Year end reserves total 447,000  barrels of oil and 21.0 Bcf or 3.9 million BOE.
There is one proved,  undeveloped  location in the field. Sweet gas is processed
at a Company owned plant;  sour gas is processed at a third party plant. In late
1997, a new Tensleep well was completed at an initial rate of 100 barrels of oil
per day. The Company  plans to drill 3 Frontier  wells and one Tensleep  well in
1998. The  Tensleep/Phosphoria  well is on a portion of the lease lands in which
the Company has a 100% interest. The Frontier is located at 8,000 to 10,500 feet
and the Tensleep  around 12,000 feet.  Frontier  wells cost  approximately  $1.2
million and Tensleep wells cost approximately $1.5 million each.

         Big Horn Basin.  The Company has assembled a 156,000 gross (78,000 net)
acre  undeveloped  lease block which is  prospective  for Frontier,  Muddy,  and
Lance/Mesaverde  formations.  The initial  well,  completed at the  beginning of
1998, tested at 550 Mcf per day and 20 barrels of oil per day from the Frontier,
a rate at which  the  Company  believes  can be  improved  with  different  frac
techniques. In January 1998, casing was set on the second well located 2.5 miles
northeast of the initial well and testing  should  commence in the first quarter
1998.  Two additional  wells are planned for 1998 at net costs of  approximately
$1.2 million each.

         Uinta  Basin.  In the Uinta  Basin,  the  Company  holds  interests  in
approximately  94,000  gross  (71,000  net)  acres.  During  1997,  the  Company
participated in drilling one operated and two non-operated wells in the basin. A
pilot waterflood in the Leland Bench field commenced during the third quarter of
1996.  The initial  response  was observed in 1997 and  production  continues to
improve.  Depending  on the level of oil  prices,  development  may begin in the
second  half of 1998.  A second  pilot  project,  in the  Horseshoe  Bend Field,
received all necessary regulatory approvals, and injection commenced in December
1997. The response of the pilot projects and the ability to select locations and
enhance  waterflood  efforts  through the use of 3-D seismic data will influence
the ultimate  success of these projects.  The projects are also sensitive to oil
prices.  During the last half of 1996, local oil prices,  which had historically
been at a premium to West Texas Intermediate prices,  deteriorated and now trade
at a significant  discount to such prices.  Throughout 1997, black wax crude oil

                                       6

<PAGE>

prices  remained  relatively  low with little  improvement  expected in the near
term.  As a result,  additional  development  drilling  will likely be curtailed
until oil prices in the area improve.

         During 1997, net  production  from the Uinta Basin averaged 267 barrels
of oil and  approximately  1,401 Mcf of gas per day,  as compared to 291 barrels
and 1,255 Mcf per day during 1996. At year end, the Company had interests in 126
producing  wells,  74 of which were operated by the Company.  Proved reserves at
year end were 596,000  barrels of oil and 4.4 Bcf of gas, or 1.3 million BOE, as
compared to 1.2 million  barrels and 3.9 Bcf, or 1.8 million  BOE, at the end of
1996.  The decrease in oil reserves is primarily due to normal field  production
decline  coupled  with  significantly  lower year end oil prices.  Gas  reserves
increased  primarily  due to improved  performance  following  work  programs to
increase production during 1997.

         Northern Wyoming. The Company holds significant interests in two large,
mature oil fields undergoing  waterflood in Northern Wyoming,  the Hamilton Dome
and Salt Creek fields.  The Company's 1997 production from these fields averaged
3,183 BOE per day. At year end, net proved reserves at these fields totaled 12.4
million BOE, including 12.3 million barrels of oil and 566 MMcf of gas, compared
to 12.2 million BOE (12.1 million barrels of oil and 531 MMcf of gas) at the end
of 1996. In Hamilton Dome,  the operator has reduced the  production  decline in
the field through an accelerated workover program throughout 1997. This work has
replaced  the  production  in 1997 and kept the  reserves  virtually  unchanged.
Hamilton Dome produces sour crude oil primarily  from the Tensleep,  Madison and
Phosphoria  formations  at depths of 2,500 to 5,500  feet.  Salt Creek  produces
sweet crude oil from the Wall Creek formation at depths of 2,000 to 2,900 feet.


















                                       7

<PAGE>


Proved Reserves

         The following  table sets forth  estimated year end proved reserves for
each of the years in the three  year  period  ended  December  31,  1997 for the
Company and the Company, excluding Patina, as of December 31, 1997 and 1996.
<TABLE>
<CAPTION>

                                                           Consolidated                   Excluding Patina
                                                           December 31,                     December 31,
                                               -----------------------------------     ---------------------
                                                 1997          1996         1995         1997         1996
                                               --------      --------     --------     --------     --------
<S>                                              <C>           <C>          <C>          <C>          <C>   
Crude oil and liquids (MBbl)
    Developed                                    16,101        31,869       21,637       16,101       16,070
    Undeveloped                                     659         8,628        2,610          659        1,952
                                               --------      --------     --------     --------     --------
       Total                                     16,760        40,497       24,247       16,760       18,022
                                               ========      ========     ========     ========     ========

Natural gas (MMcf)
    Developed                                   297,490       443,441      330,524      297,490      200,664
    Undeveloped                                  65,678       162,195       65,194       65,678      108,313
                                               --------      --------     --------     --------     --------
       Total                                    363,168       605,636      395,718      363,168      308,977
                                               ========      ========     ========     ========     ========

Total MBOE                                       77,288       141,436       90,200       77,288       69,518
                                               ========      ========     ========     ========     ========
</TABLE>


         The following table sets forth the estimated pretax future net revenues
from the  production  of  proved  reserves  and the  Pretax PW 10% Value of such
revenues.
<TABLE>
<CAPTION>


                                                                   December 31, 1997
                                            --------------------------------------------------------
                                            Developed              Undeveloped (a)           Total
                                            ---------              ---------------         ---------
                                                                    (In thousands)

          <S>                              <C>                       <C>                   <C>         
          1998                              $  98,710                $  (6,143)            $  92,567
          1999                                 76,583                    1,472                78,055
          2000                                 56,211                    5,967                62,178
          Remainder                           319,208                   61,204               380,412
                                            ---------                ---------             ---------
             Total                          $ 550,712                $  62,500             $ 613,212
                                            =========                =========             =========

          Pretax PW 10% Value (b)           $ 351,955                $  23,318             $ 375,273
                                            =========                =========             =========

<FN>
(a) Net of estimated capital costs,  including  estimated costs of $11.8 million during 1998.
(b) The after tax PW 10% value of proved  reserves  totaled $291.8 million at year end 1997.
</FN>
</TABLE>

         The  quantities  and values shown in the preceding  tables are based on
realized prices in effect at December 31, 1997,  averaging  $14.42 per barrel of
oil and $2.12 per Mcf of gas.  References  prices as of  December  31, 1997 were
NYMEX oil of $15.50 per barrel, Henry Hub gas of $2.55 per Mcf and CIG index gas
of $1.94 per Mcf.  Price  reductions  decrease  reserve  values by lowering  the
future net  revenues  attributable  to the  reserves  and also by  reducing  the
quantities  of  reserves  that  are  recoverable  on an  economic  basis.  Price
increases  have the  opposite  effect.  Any  significant  decline or increase in
prices of oil or gas could have a  material  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.

                                       8

<PAGE>

         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. See "Risk Factors and Investment Considerations."

         Netherland,  Sewell & Associates, Inc. ("NSAI"),  independent petroleum
consultants,   prepared   estimates  of  the  Company's  proved  reserves  which
collectively  represent  87% of Pretax PW 10% Value as of December 31, 1997.  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.



















                                       9

<PAGE>

Production, Revenue and Price History

         The following table sets forth information  regarding net production of
crude oil, liquids and natural gas,  revenues and expenses  attributable to such
production  and to natural gas  transportation,  processing  and  marketing  and
certain price and cost information for each of the years in the five year period
ended  December 31, 1997 for the  Company.  Also set forth is 1997 and 1996 data
for the Company, excluding Patina.
<TABLE>
<CAPTION>

                                                               Consolidated                               Excluding Patina
                                      --------------------------------------------------------------   -----------------------
                                        1997         1996         1995         1994          1993        1997          1996
                                      ---------    ---------    ---------    ----------    ---------   ---------     ---------
                                             (Dollars in thousands, except prices and per barrel equivalent information)

<S>                                   <C>          <C>          <C>          <C>          <C>          <C>           <C>
Production
    Oil (MBbl)                            3,490        3,884        4,278        4,366        3,451        2,050         2,196
    Gas (MMcf)                           61,638       55,840       53,227       43,809       35,080       41,377        31,893
    MBOE (a)                             13,763       13,191       13,149       11,668        9,297        8,946         7,512

Revenues
    Oil                               $  65,886    $  79,201    $  72,550    $  64,625    $  53,174     $ 37,397     $  44,661
    Gas (b)                             141,330      110,126       72,058       73,233       71,467       96,454        62,482
                                      ---------    ---------    ---------    ---------    ---------     --------     ---------
        Subtotal                        207,216      189,327      144,608      137,858      124,641      133,851       107,143
    Transportation, processing
        and marketing                     7,004       17,655       38,256      107,247       94,839        7,004        17,655
                                      ---------    ---------    ---------    ---------    ---------     --------     ---------
        Total                         $ 214,220    $ 206,982    $ 182,864    $ 245,105    $ 219,480     $140,855     $ 124,798
                                      ---------    ---------    ---------    ---------    ---------     --------     ---------

Operating expenses
    Production                        $  48,523    $  49,638    $  52,486    $  46,267    $  41,401     $ 35,016     $  35,118
    Transportation, processing
        and marketing                     6,692       15,020       29,374       94,177       85,640        6,692        15,020
                                      ---------    ---------    ---------    ---------    ---------     --------     ---------
                                      $  55,215    $  64,658    $  81,860    $ 140,444    $ 127,041     $ 41,708     $  50,138
                                      ---------    ---------    ---------    ---------    ---------     --------     ---------

Direct operating margin               $ 159,005    $ 142,324    $ 101,004    $ 104,661    $  92,439     $ 99,147     $  74,660
                                      =========    =========    =========    =========    =========     ========     =========

Production data
    Average sales price (c)
        Oil (Bbl)                     $   18.88    $   20.39    $   16.96    $   14.80    $   15.41     $  18.24     $   20.34
        Gas (Mcf) (b)                      2.29         1.97         1.35         1.67         1.94         2.33          1.96
        BOE (a)                           15.06        14.35        11.00        11.82        13.41        14.96         14.26
    Avg. production expense/BOE       $    3.53    $    3.76    $    3.99    $    3.97    $    4.45     $   3.91     $    4.67
    Avg. production margin/BOE        $   11.53    $   10.59    $    7.01    $    7.85    $    8.96     $  11.05     $    9.59


<FN>
(a) Gas  production  is  converted to oil  equivalents  at the rate of 6 Mcf per barrel.
(b) Sales of natural gas liquids are included in gas revenues.
(c) The Company estimates that its composite net wellhead prices at December 31, 1997 were  approximately  $2.12 per Mcf of
    gas and $14.42 per barrel of oil.
</FN>
</TABLE>

                                       10

<PAGE>



Producing Wells

         The following table sets forth certain information at December 31, 1997
relating to the producing  wells in which the Company owned a working  interest.
The Company  also held  royalty  interests  in 101  producing  wells.  Wells are
classified as oil or gas wells according to their predominant production stream.
<TABLE>
<CAPTION>

               Predominant                       Gross                    Net
             Product Stream                      Wells                   Wells
             --------------                      -----                   -----
         <S>                                     <C>                       <C>
         Crude oil and liquids                   1,023                     334
         Natural gas                               463                     223
                                                 -----                   -----
                                                 1,486                     557
                                                 =====                   =====
</TABLE>

Acreage

         The following table sets forth certain information at December 31, 1997
relating to domestic acreage held by the Company.  Developed  acreage is acreage
assigned to producing  wells. For offshore  blocks,  in the Gulf of Mexico,  the
entire block is  classified  as  developed if a producing  well has been drilled
within its boundries. Such blocks could contain up to 5,000 gross acres. In most
instances,  the Company  does not  consider  such blocks to be fully  developed.
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.
<TABLE>
<CAPTION>


                                               Gross                    Net
                                             ---------               ---------
           <S>                               <C>                       <C>
           Developed                           176,190                 106,015
           Undeveloped (a)                   1,131,657                 704,668
                                             ---------               ---------
                                             1,307,847                 810,683
                                             =========               =========
<FN>
(a) The Company  also holds  130,000  net  undeveloped  acres under  option in
    North Louisiana as of February 27, 1998.
</FN>
</TABLE>

Drilling Results

         The  following  table  sets  forth  information  with  respect to wells
drilled during the past three years.  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>
                                                          1997         1996        1995
                                                         ------       ------      ------
                    <S>                                   <C>          <C>         <C>
                    Development wells
                     Productive
                       Gross                              66.0         69.0        223.0
                       Net                                33.3         38.9        133.1
                     Dry
                       Gross                               3.0          2.0          5.0
                       Net                                 1.3           .5          3.8

                    Exploratory wells
                     Productive
                       Gross                               2.0          3.0            -
                       Net                                  .7           .5            -
                     Dry
                       Gross                               2.0          2.0            -
                       Net                                 1.7          1.6            -

</TABLE>

         At December 31, 1997,  the Company  had 15 gross (7.1 net)  development
  wells and 3 gross (1.5 net)  exploratory wells in progress.

                                       11

<PAGE>

Customers and Marketing


         The Company's oil and gas production is principally  sold to end users,
marketers and other  purchasers  having access to pipeline  facilities  near its
properties.  Where  there is no access to  pipelines,  crude oil is  trucked  to
storage facilities. In 1997, Sonat Marketing Company accounted for approximately
17% of revenues,  Engage Energy accounted for approximately  14%, and Duke Power
and Energy,  which  purchases a significant  portion of Patina's gas production,
accounted for  approximately  12%. In 1996, Duke Power and Energy  accounted for
approximately 11% of revenues.  In 1995, Amoco Production  Company accounted for
approximately  10% of revenues.  The marketing of oil and gas by the Company can
be affected by a number of factors  that are beyond its 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 material  adverse  effect on
its operations.

         The Company's gas  marketing  strategy  focuses on aligning the Company
with substantial marketers that are active in key ares of operation. The Company
also continues to participate in the midstream gas facilities  business  through
ownership of pipelines and alliances with other companies.

         In the Rocky Mountain  region,  essentially all of the Company's gas is
marketed through contracts with Engage Energy (a partnership between the Coastal
Corporation and Westcoast Energy,  Inc.).  Under the  arrangements,  the Company
receives  market value for its gas as it is  delivered  into  mainline  pipeline
receipt points.  The Company also  participates in downstream  marketing margins
realized by Engage,  after  recovery of costs,  for a broad spectrum of Engage's
marketing  activities in Wyoming,  Colorado and Utah. The agreements with Engage
extend through March 1999.

         Beginning in 1997, the Company pooled its gas transportation facilities
in Wyoming and Colorado with facilities  owned by Coastal Field Services to form
Great Divide Gas Services.  Great Divide is owned 73% by Coastal Field  Services
and 27% by the Company,  and encompases over 600 miles of pipeline  connected to
more than 650 wells. In addition to expanding  existing  pipelines in the Uinta,
Piceance  and  Washakie  Basins,  Great  Divide is working to develop  new Rocky
Mountain  pipeline  and  processing  opportunities.  In 1997,  Great  Divide was
responsible for the development of a new 16 mile pipeline  linking the Company's
gas production in the Piceance Basin directly to Colorado Interstate Gas.

         In the Gulf of Mexico, the Company has entered into a new contract with
Williams Energy Services Company ("WESCO") to increase the market access for gas
in this area.  In  conjunction  with the WESCO  contract,  Transcontinental  Gas
Pipeline  Corporation  ("Transco")  and Williams Field Services  ("WFS") will be
extending new pipelines into the Main Pass area, with  construction  expected to
be completed by mid-1998.

         As described in  "Operations - Offshore - Gulf of Mexico,"  during 1997
the Company also upgraded its  facilities and made  arrangements  with the major
gathering  system  in the  Main  Pass/Viosca  Knoll  area to  remove  historical
restraints  on production  in that area.  Since the beginning of 1998,  capacity
constraints  have increased on pipelines  downstream of the gathering  system in
southeastern  Louisiana.  Although  the  Company  cannot  predict  the extent or
duration of these  constraints,  it is possible  the  constraints  will  depress
realized prices,  reduce  production,  or both. At the present time, the Company
believes that the  completion of the new Transco and WFS  facilities  will allow
the Company's  Main Pass gas production to be delivered to markets in the Mobile
Bay area of  Alabama,  avoiding  the  pipeline  capacity  constraints  that have
recently developed in southeastern Louisiana.

Title to Properties

         Title to the  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  limited
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.

                                       12

<PAGE>

Regulation

         Regulation of Drilling and  Production.  The Company's  operations  are
affected by political  developments  and federal and state laws and regulations.
Oil and gas industry legislation and administrative regulations are periodically
changed  for a  variety  of  political,  economic  and other  reasons.  Numerous
departments  and agencies,  federal,  state,  local and Indian,  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.

         A  substantial  portion of the Company's oil and gas leases in the Gulf
of Mexico and in the Rocky Mountain area were granted by the U.S. Government and
are administered by two federal agencies,  the Bureau of Land Management ("BLM")
and the Minerals  Management  Service  ("MMS").  These leases are issued through
competitive  bidding,  contain relatively  standard terms and require compliance
with detailed BLM and MMS regulations and orders (which are subject to change by
the BLM and MMS). For offshore operations,  lessees must obtain MMS approval for
exploration  plans and development and production  plans before  commencement of
operations.  In addition to permits  required from other  agencies  (such as the
Coast  Guard,  the Army  Corps of  Engineers  and the  Environmental  Protection
Agency),  lessees  must  obtain  a  permit  from  the  BLM or MMS  prior  to the
commencement of onshore or offshore drilling.

         State  regulatory   authorities   have  also   established   rules  and
regulations  requiring permits for drilling,  reclamation and plugging bonds and
reports  concerning  operations,  among  other  matters.  Many  states also have
statutes and regulations  governing a number of  environmental  and conservation
matters.

         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. Under these orders,  FERC
has  caused  pipelines  to  open  up  access  to   transportation,   essentially
eliminating  pipelines  from the role of natural gas  merchant  and  "unbundled"
transportation  services  so that a buyer can  purchase  just those  services it
needs. FERC's regulatory programs generally 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 programs.  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.

         Environmental Regulations. The 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.  These laws and
regulations may require the  acquisition of a permit before drilling  commences,
prohibit drilling  activities on certain lands lying within wilderness and other
protected areas and impose remediation  obligations and substantial  liabilities
for pollution resulting from drilling operations. Such laws and regulations also
restrict  air or other  pollution  and  disposal  of wastes  resulting  from the
operation of gas processing plants,  pipeline systems and other facilities owned
directly or  indirectly by the Company.  Drilling and other  projects on federal
leases  may  also  require   preparation  of  an  environmental   assessment  or
environmental impact statement, which could delay the commencement of operations
and could  limit the  extent to which the  leases  may be  developed.  See "Risk
Factors and  Investment  Considerations  -  Environmental  and Other  Government
Regulation."

         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 other 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,  although  some  matters  identified  in the
environmental assessments are subject to ongoing review. The Company has assumed
responsibility  for  some  of the  matters  identified.  Some  of the  Company's
properties,  particularly  larger units that have been in operation  for several
decades, may require significant costs for reclamation and restoration when they

                                       13

<PAGE>

are divested or when operations eventually cease. Environmental assessments have
not been performed on all of the Company's properties. To date, expenditures for
environmental  control  facilities and for remediation have not been material to
the Company,  and the Company does not expect that,  under current  regulations,
future expenditures will have a material adverse impact on the Company.

         Under the Oil Pollution  Act of 1990  ("OPA"),  owners and operators of
onshore  facilities  and pipelines and lessees or permittees of an area in which
an offshore facility is located ("Responsible Parties") are strictly liable on a
joint and  several  basis for  removal  costs and  damages  that  result  from a
discharge  of oil into United  States  waters.  These  damages  include  natural
resource damages,  real and personal  property damages and economic losses.  OPA
limits the strict liability of Responsible Parties for removal costs and damages
that  result  from a  discharge  of oil to $350  million  in the case of onshore
facilities  and  $75  million  plus  removal  costs  in  the  case  of  offshore
facilities,  except that no limits  apply if the  discharge  was caused by gross
negligence or willful  misconduct,  or by the violation of an applicable federal
safety, construction or operating regulation by the Responsible Party, its agent
or subcontractor.

         States in which the Company  operates have also adopted  regulations to
implement the Federal Clean Air Act. These new  regulations  are not expected to
have a significant impact on the Company or its operations.  In the longer term,
regulations  under the Federal Clean Air Act may increase the number and type of
the  Company's  facilities  that  require  permits,  which  could  increase  the
Company's cost of operations and restrict its activities in certain areas.

Risk Factors and Investment Considerations

         Price Fluctuations and Markets. The Company's results of operations are
highly  dependent upon the prices received for the Company's oil and natural gas
production.  The majority of the Company's sales of oil and natural gas are made
in the spot market,  or pursuant to contracts  based on spot market prices,  and
not  pursuant  to  long-term,  fixed-price  contracts.  Accordingly,  the prices
received by the Company for its oil and  natural gas  production  are  dependent
upon numerous factors beyond the control of the Company.  These factors include,
but are not  limited  to, the level of  consumer  product  demand,  governmental
regulations  and taxes,  the price and  availability of alternative  fuels,  the
level of foreign  imports  of oil and  natural  gas,  and the  overall  economic
environment. Significant declines in prices for oil and natural gas could have a
material  adverse  effect  on the  Company's  financial  condition,  results  of
operations and quantities of reserves  recoverable on an economic basis.  Should
the industry experience  significant price declines from current levels or other
adverse market  conditions,  the Company may not be able to generate  sufficient
cash flow from  operations  to meet its  obligations  and make  planned  capital
expenditures.

         Price  reductions  decrease  reserve  values by lowering the future net
revenues  attributable  to the reserves and also by reducing the  quantities  of
reserves that are  recoverable on an economic  basis.  Price  increases have the
opposite  effect.  Prices in effect at  December  31, 1997  averaged  $14.42 per
barrel of oil and $2.12 per Mcf of gas. Reference prices as of December 31, 1997
were  NYMEX oil of  $15.50  per  barrel,  Henry Hub gas of $2.55 per Mcf and CIG
index  gas of $1.94 per Mcf.  Any  significant  decline  in prices of oil or gas
could have a material  adverse effect on the Company's  financial  condition and
results of operations.

         The  availability  of a ready market for the  Company's oil and natural
gas production also depends on a number of factors, including the demand for and
supply of oil and natural gas and the proximity of reserves to, and the capacity
of,  oil  and  gas  gathering  systems,   pipelines  or  trucking  and  terminal
facilities.  Wells may be shut-in or constrained  for lack of a market or due to
inadequacy  or  unavailability  of pipeline or gathering  system  capacity.  See
"Customers and Marketing."

         Replacement of Reserves.  In general, the volume of production from oil
and natural gas  properties  declines as reserves  are  depleted.  Except to the
extent the Company acquires  properties  containing  proved reserves or conducts
successful development and exploration activities,  or both, the proved reserves
of the Company will decline as reserves are produced.  The Company's  future oil
and gas production is, therefore,  highly dependent upon its level of success in
finding or acquiring additional reserves at attractive rates of return. In order
to increase  reserves and production,  the Company must continue its development
drilling and recompletion programs,  pursue its exploration drilling programs or
undertake other replacement activities.  The Company's current strategy includes
increasing its reserve base by continuing to exploit its existing properties, by
pursuing exploration opportunities and acquiring producing properties. There can
be no assurance, however, that the Company's planned development and exploration

                                       14


<PAGE>

projects  and  acquisition  activities  will  result in  significant  additional
reserves or that the Company will have continuing  success  drilling  productive
wells at favorable finding costs.

         Substantial Capital Requirements.  The Company makes, and will continue
to make,  substantial  capital  expenditures for the  acquisition,  development,
exploration,  production and  abandonment  of oil and natural gas reserves.  The
Company  intends to  finance  such  capital  expenditures  primarily  with funds
provided by operations and  borrowings  under its bank credit  facility.  During
1997,  the Company's  capital  expenditures  totaled $116.0  million,  including
$106.7 million for development,  exploration and gas  transportation  facilities
and $9.3 million for acquisitions.  During 1998, the Company expects to increase
its capital expenditures, excluding acquisitions, to $130 to $140 million.

         The Company believes that, after debt service,  it will have sufficient
cash  provided by  operating  activities  and capital  resources to fund planned
capital  expenditures  for  exploration  and  development   activities  for  the
foreseeable  future.  However,  if revenues decrease as a result of lower oil or
gas  prices  or  otherwise  or if  the  Company  incurs  substantial  additional
indebtedness to finance acquisitions or for other purposes, the Company may have
limited  ability to expend the capital  necessary  to replace its reserves or to
maintain  production  at current  levels,  resulting in a decrease in production
over time.  If the  Company's  cash flow from  operations  is not  sufficient to
satisfy its capital  expenditure  requirements,  there can be no assurance  that
additional   debt  or  equity   financing   will  be  available  to  meet  these
requirements.  See "Management's  Discussion and Analysis of Financial Condition
and Results of Operations - Financial Condition and Capital Resources."

         Acquisition  Risks.  The  Company  continually   evaluates  acquisition
opportunities   and   frequently   engages  in  bidding  and   negotiation   for
acquisitions,  many of which are substantial. If successful in this process, the
Company may be required to alter or increase substantially its capitalization to
finance these  acquisitions  through the issuance of  additional  debt or equity
securities, the sale of production payments or otherwise (although the Company's
credit facility and the Indenture for its subordinated  notes include  covenants
that limit the Company's ability to incur additional  indebtedness).  Changes in
capitalization  may  significantly  affect  the  risk  profile  of the  Company.
Significant acquisitions can change the nature of the operations and business of
the Company depending upon the character of the acquired  properties,  which may
be  substantially   different  in  operating  or  geologic   characteristics  or
geographic  location  from  existing  properties.  While the Company  intends to
concentrate on acquiring  producing  properties with development and exploration
potential  located in its current areas of operation,  the Company may decide to
pursue acquisitions of properties located in other geographic regions. There can
be no assurance  that the Company will be successful in the  acquisition  of any
material property interests.

         Drilling  Risks.   Drilling  activities  are  subject  to  many  risks,
including  the  risk  that  no  commercially   productive   reservoirs  will  be
encountered.  There can be no  assurance  that new wells  drilled by the Company
will be  productive  or that the Company  will recover all or any portion of its
investment.  Drilling for oil and natural gas may involve unprofitable  efforts,
not only from dry  wells,  but from wells  that are  productive  but that do not
produce sufficient net revenues to return a profit after drilling, operating and
other  costs.  The cost of drilling,  completing  and  operating  wells is often
uncertain.  The  Company's  drilling  operations  may be  curtailed,  delayed or
canceled as a result of numerous factors, many of which are beyond the Company's
control,   including  title  problems,   weather  conditions,   compliance  with
environmental and other governmental requirements and shortages or delays in the
delivery of equipment and services.

         Operating  Hazards and Uninsured  Risks.  The Company's  operations are
subject  to  hazards  and  risks   inherent  in  drilling  for,   producing  and
transporting oil and natural gas, such as fires, natural disasters,  explosions,
formations with abnormal pressures,  blowouts,  cratering, pipeline ruptures and
spills,  any  of  which  can  result  in  loss  of  hydrocarbons,  environmental
pollution,  personal injury claims and other damage to properties of the Company
and others.  As protection  against  operating  hazards,  the Company  maintains
insurance  coverage against some, but not all,  potential losses.  The Company's
coverages  include,  but are not limited to, operator's extra expense,  physical
damage on  certain  assets,  comprehensive  general  liability,  automobile  and
workers'  compensation  insurance.  The Company  believes  that its insurance is
adequate and  customary  for  companies of a similar size engaged in  operations
similar to those of the  Company,  but losses  could  occur for  uninsurable  or
uninsured  risks or in amounts in excess of  existing  insurance  coverage.  The
occurrence  of an event  that is not fully  covered  by  insurance  could have a
material and adverse impact on the Company's  financial condition and results of
operations.

                                       15

<PAGE>

         Uncertainty of Estimates of Reserves and Future Net Revenues. There are
numerous  uncertainties  inherent in estimating  quantities of proved  reserves,
including  many  factors  beyond  the  control  of  the  Company.   The  reserve
information included in this annual report represents estimates based on reports
prepared by the Company's independent petroleum engineers. Petroleum engineering
is not an exact science.  Estimates of economically  recoverable oil and natural
gas  reserves and of future net cash flows  necessarily  depend upon a number of
variable  factors and assumptions,  such as historical  production from the area
compared with  production  from other  producing  areas,  the assumed effects of
regulation by governmental  agencies and assumptions  concerning  future oil and
natural gas prices, future operating costs,  severance and excise taxes, capital
expenditures  and  workover and  remedial  costs,  all of which may in fact vary
considerably   from   actual   results.   For  these   reasons,   estimates   of
classifications  of such  reserves  based on risk of recovery  and  estimates of
expected  future net cash flows  prepared by different  engineers or by the same
engineers at different times may vary substantially. Actual production, revenues
and  expenditures  with respect to the Company's  reserves will likely vary from
estimates, and the variances may be material.

         The present  values of future net cash flows referred to in this annual
report  should  not be  construed  as either  the  current  market  value of the
estimated oil and gas reserves  attributable  to the  Company's  properties or a
prediction  of the future net cash flows from those  properties.  In  accordance
with  applicable  requirements  of the Securities and Exchange  Commission  (the
"Commission"),  the  discounted  future net cash flows from proved  reserves are
determined in  accordance  with certain  rules  designed to  facilitate  uniform
presentation  by different  companies.  The present values and future cash flows
are generally based on prices and costs as of the date of the estimate,  whereas
actual  future prices and costs may be  materially  higher or lower.  Future net
cash flows  also will be  affected  by factors  such as the amount and timing of
actual production and expenses,  supply and demand for oil and gas, curtailments
or  increases  in  consumption  by gas  purchasers  and changes in  governmental
regulations or taxation. In addition, the 10% discount factor, which is required
by the Commission to be used to calculate  discounted  future net cash flows for
reporting  purposes,  is not  necessarily the most  appropriate  discount factor
based on interest  rates in effect from time to time and risks  associated  with
the Company or the oil and gas industry in general.

         Environmental  and  Other   Governmental   Regulation.   The  Company's
operations  are affected by extensive  regulation  pursuant to various  federal,
state and local laws and regulations  relating to the  exploration  for, and the
development,  production,  transportation  and marketing of, oil and natural gas
and the release of  materials  into the  environment  or  otherwise  relating to
protection of the environment.  In particular, the Company's oil and natural gas
exploration,  development and production,  and its activities in connection with
the storage and transportation of liquid hydrocarbons,  are subject to stringent
environmental  regulations by governmental  authorities.  Such  regulations have
increased the costs of planning, designing, drilling, installing,  operating and
abandoning oil and natural gas wells and other related facilities.

         The Company is required to expend significant resources, both financial
and  managerial,   to  comply  with  environmental  regulations  and  permitting
requirements.  Although the Company  believes that its operations are in general
compliance with all such laws and  regulations,  risks of substantial  costs and
liabilities are inherent in oil and natural gas operations,  and there can be no
assurance that  significant  costs and  liabilities  will not be incurred in the
future.  Moreover, it is possible that other developments,  such as increasingly
strict  environmental laws and regulations and enforcement  policies thereunder,
and claims for damages to property, employees, other persons and the environment
resulting from the Company's  operations,  could result in substantial costs and
liabilities in the future.

         The Company expects to maintain  customary  insurance  coverage for its
operations,  including coverage for sudden  environmental  damages, but does not
believe that insurance  coverage that explicitly  covers  environmental  damages
that occur over time will be available at a  reasonable  cost.  The Company does
not believe that insurance  coverage  against the full potential  liability that
could be caused by environmental  damages is currently available at a reasonable
cost.  Accordingly,  the Company might be subject to uninsured or only partially
insured liability  because of the prohibitive  premium costs of insuring against
certain hazards.

         Drilling  and  other  projects  on  federal  leases  may  also  require
preparation of an environmental  assessment or environmental  impact  statement,
which could delay the  commencement  of operations and could limit the extent to
which the leases may be developed. Environmental impact statements are currently
pending in two  significant  areas of the Company's  operations,  the Deep Green
River  Basin  and the  northern  part of the  Washakie  Basin.  Approval  of new
drilling in these areas is limited until the statements  receive final approval.
While  the  timing  of  final  approval,  and  terms  of  conditions  placed  on
development in the affected areas, is uncertain,  the Company currently does not

                                       16

<PAGE>

expect the statements to significantly  impact plans to develop these two areas.
However,  delays in approving  the  statements  or the  inclusion of  unexpected
conditions,  could limit or delay  development plans in these areas in 1998, and
possibly beyond.

         Competition.  The oil and  gas  industry  is  highly  competitive.  The
Company will compete in the acquisition,  development,  production and marketing
of oil and  natural  gas with major oil  companies,  other  independent  oil and
natural gas concerns  and  individual  producers  and  operators.  There is also
competition  in the  hiring  of  experienced  personnel.  Many of the  Company's
competitors have  substantially  greater  financial and other resources than the
Company.  Furthermore,  the oil and natural  gas  industry  competes  with other
industries in supplying the energy and fuel needs of industrial,  commercial and
other consumers.

Forward-looking Information

         All statements  other than  statements of historical  fact contained in
this Annual Report on Form 10-K and other  materials filed or to be filed by the
Company with the  Securities  and Exchange  Commission  (as well as  information
included in oral  statements or other written  statements  made or to be made by
the  Company)  contain or will  contain or  include  forward-looking  statements
within the meaning of the Private Securities Litigation Reform Act of 1995. Such
forward-looking  statements may be or may concern,  among other things,  capital
expenditures,  drilling activity, acquisitions and dispositions,  development or
exploratory activities, cost savings efforts, production activities and volumes,
hydrocarbon  reserves,  hydrocarbon  prices,  hedging activities and the results
thereof,  financing plans,  liquidity,  regulatory matters,  competition and the
Company's  ability to realize  efficiencies  related to certain  transactions or
organizational changes.

         Forward-looking  statements  generally are accompanied by words such as
"anticipate,"  "believe,"  "estimate,"  "expect,"  "intend," "plan,"  "project,"
"potential"  or similar  statements.  Although  the  Company  believes  that the
expectations  reflected in such  forward-looking  statements are reasonable,  no
assurance can be given that such expectations  will prove correct.  Factors that
could  cause  the  Company's  results  to  differ  materially  from the  results
discussed in such  forward-looking  statements include the risks described under
"Risk Factors and Investment  Considerations,"  such as the  fluctuations of the
prices  received or demand for the Company's oil and gas, the ability to replace
depleting  reserves,  potential  additional  indebtedness,  the requirements for
capital,  drilling  risks,  operating  hazards,  the  cost and  availability  of
drilling  rigs,   acquisition  risks,  the  uncertainty  of  reserve  estimates,
competition and the effects of governmental and  environmental  regulation.  All
forward-looking  statements  are  expressly  qualified in their  entirety by the
cautionary statements in this section.

Officers

         Listed  below are the  officers  of the  Company and a summary of their
business experience.
<TABLE>
<CAPTION>

        Name                                          Position
------------------------           -------------------------------------------------
<S>                                <C>
John C. Snyder                     Chairman
William G. Hargett                 President and Chief Operating Officer
Charles A. Brown                   Senior Vice President - Rocky Mountain Region
Mark A. Jackson                    Senior Vice President and Chief Financial Officer
Jay H. Smith                       Senior Vice President - Southern Region
Steven M. Burr                     Vice President - Engineering and Planning
Peter E. Lorenzen                  Vice President - General Counsel
H. Richard Pate                    Vice President - Rocky Mountain Region, Operations and Engineering
David M. Posner                    Vice President - Gas Management
Roger B. Rice                      Vice President - Human Resources
Rodney L. Waller                   Vice President - Treasurer
</TABLE>

         John C. Snyder (55), Chairman and a director,  founded a predecessor of
the  Company  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.  From
1969 to 1971, Mr. Snyder was with Canadian-American  Resources Fund, Inc., which
he  founded.  From 1964 to 1966,  Mr.  Snyder  was  employed  by Humble  Oil and

                                       17

<PAGE>

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.  In 1995, Mr.
Snyder was named Wildcatter of the Year by the Independent Petroleum Association
of  Mountain  States.  He  currently  serves as a director  of SOCI plc and is a
member of the National Petroleum Council.

         William G.  Hargett  (48),  President,  Chief  Operating  Officer and a
director,  has been with the  Company  since  April  1997.  Prior to joining the
Company, Mr. Hargett served as President of Greenhill Petroleum Corporation from
1994 to 1997,  Amax Oil & Gas,  Inc.  from  1993 to 1994 and North  Central  Oil
Corporation from 1988 to 1993 and in various  exploration  capacities at Tenneco
Oil Company  from 1974 to 1988 and Amoco  Production  Company from 1973 to 1974.
Mr.  Hargett earned  Bachelor of Science and Master of Science  degrees from the
University of Alabama.

         Charles A. Brown (50),  Senior Vice President - Rocky Mountain  Region,
joined the Company in 1987. He was a petroleum engineering  consultant from 1986
to 1987. He served as President of CBW Services,  Inc., a petroleum  engineering
consulting  firm, from 1979 to 1986 and was employed by Kansas Nebraska  Natural
Gas Company  from 1971 to 1979 and Amerada Hess  Corporation  from 1969 to 1971.
Mr. Brown received his Bachelor of Science degree in Petroleum  Engineering from
the Colorado School of Mines.

         Mark A.  Jackson  (42),  Senior  Vice  President  and  Chief  Financial
Officer,  joined the Company in August,  1997. Prior to joining the Company, Mr.
Jackson served in various executive  capacities at Apache Corporation  including
Vice President and Controller from 1988,  Vice President,  Finance from 1994 and
Chief  Financial  Officer from 1996. From 1984 until 1988, Mr. Jackson served as
Assistant  Controller of Diamond Shamrock and Maxus Energy Company.  Mr. Jackson
began his career with the  certified  public  accounting  firm of Ernst & Ernst,
specializing in the oil and gas industry.  Mr. Jackson  received his Bachelor of
Science degree in Accounting from Oklahoma Christian University.

         Jay H. Smith (51),  Senior  Vice  President - Southern  Region,  joined
the Company in February 1998.  From 1993 until he joined the Company,  Mr. Smith
served as Executive Vice President of Sonat Exploration Company. From 1983 until
1993, Mr. Smith served in a variety of positions  with BP Exploration  and Sohio
Petroleum  Company,  most recently as Chief of Staff,  Western Hemisphere North.
From 1981 to 1983, Mr. Smith was Vice President - Operations of Spectrum Oil and
Gas  Company.  Mr.  Smith began his career  with Shell Oil Company in 1968.  Mr.
Smith received his Bachelor of Science degree from Syracuse University.
 
         Steven M. Burr (41), Vice President - Engineering and Planning,  joined
the  Company  in 1987.  From  1982 to  1987,  he was a Vice  President  with the
petroleum engineering consulting firm of Netherland,  Sewell & Associates,  Inc.
From 1978 to 1982, Mr. Burr was employed by Exxon Company, USA in the Production
Department.   Mr.  Burr  received  his  Bachelor  of  Science  degree  in  Civil
Engineering  from Tulane  University  and  attended  the Program for  Management
Development at the Harvard University School of Business Administration.

         Peter E. Lorenzen (48), Vice President - General Counsel and Secretary,
joined the Company in 1991.  From 1983 through 1991, he was a shareholder in the
Dallas law firm of Johnson & Gibbs,  P.C.  Prior to that,  Mr.  Lorenzen  was an
associate with Cravath,  Swaine & Moore.  Mr.  Lorenzen  received his law degree
from New York University  School of Law and his Bachelor of Arts degree from The
Johns Hopkins University.

         H.  Richard  Pate  (44),  Vice  President  -  Rocky  Mountain   Region,
Operations and  Engineering,  joined the Company in 1988. From 1981 to 1988, Mr.
Pate held various positions with Mitchell Energy  Corporation,  including Region
Engineer and Production  Manager.  He was employed by Champlin Petroleum Company
from 1979 to 1981 and Atlantic Richfield Corporation from 1975 to 1979. Mr. Pate
received  his  Bachelor  of  Science  degree in  Chemical  Engineering  from the
University of Wyoming.

         David M.  Posner  (44),  Vice  President - Gas  Management,  joined the
Company in 1991. From 1980 to 1991 he held various positions with Ladd Petroleum
Corporation  (a  subsidiary  of the General  Electric  Company)  including  Vice
President of Gas Gathering,  Processing and Marketing.  Mr. Posner  received his
Bachelor  of Arts  degree  from  Brown  University  and his Master of Science in
Mineral Economics from the Colorado School of Mines.

         Roger B. Rice  (53),  Vice  President  - Human  Resources,  joined  the
Company in 1997.  From 1992 to 1997, Mr. Rice was Vice President Human Resources

                                       18

<PAGE>

and Administration with Apache  Corporation.  From 1989 to 1992, he was Managing
Consultant  with Barton Raben,  Inc., an executive  search and  consulting  firm
specializing  in the energy  industry.  Previously,  Mr. Rice was Vice President
Administration  for  The  Superior  Oil  Company  and  held  various  management
positions  with Shell Oil  Company.  He earned his  Bachelor  of Arts degree and
Masters Degree in Business Administration from Texas Technological University.

         Rodney L. Waller (48),  Vice President - Treasurer,  joined the Company
in 1977 as an  officer.  Since  that time,  Mr.  Waller  has  performed  various
corporate,  operational  and  finance  functions.  Previously,  Mr.  Waller  was
employed  by Arthur  Andersen & Co. Mr.  Waller  received  his  Bachelor of Arts
degree from Harding University.

ITEM 3.  LEGAL PROCEEDINGS

         In September  1996, the Company and other interest owners in a lease in
southern  Texas were sued by the  royalty  owners in Texas state court in Brooks
County, Texas. The Company's working interest in the lease is approximately 20%.
The complaint  alleges,  among other things,  that the defendants have failed to
pay proper royalties under the lease, have unlawfully  comingled production with
production  from  other  leases and have  breached  their  duties to  reasonably
develop the lease.  The  plaintiffs  also claim damages for fraud,  trespass and
similar matters, and demand actual and punitive damages.  Although the complaint
does not  specify  the  amount of damages  claimed,  plaintiffs  have  submitted
calculations showing total damages against all owners in excess of $100 million.
The  Company  and the other  interest  owners  have filed an answer  denying the
claims and intend to  contest  the suit  vigorously.  The suit is  currently  in
discovery.

         At this time,  the Company is unable to estimate the range of potential
loss, if any, from the foregoing uncertainty. However, the Company believes that
resolution should not have a material adverse effect on the Company's  financial
position,  although an unfavorable  outcome in any reporting period could have a
material impact on the Company's results of operations for that period.

         The Company and its subsidiaries and affiliates are named defendants in
lawsuits and involved from time to time in governmental proceedings, all arising
in the ordinary  course of business.  Although the outcome of these lawsuits and
proceedings cannot be predicted with certainty, management does not expect these
matters to have a  material  adverse  effect on the  financial  position  of the
Company.

ITEM 4.  SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS

         No matters were  submitted  for a vote of security  holders  during the
fourth quarter of 1997.












                                       19
<PAGE>


                                     PART II

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


         The Company's stock is listed on the New York Stock Exchange and trades
under the symbol "SNY." The following  table sets forth,  for 1997 and 1996, the
high and low  closing  prices for the  Company's  securities  for New York Stock
Exchange composite transactions, as reported by The Wall Street Journal.
                                                ----------------------- 
<TABLE>
<CAPTION>


                                                    1997                              1996
                                           ---------------------             ---------------------
                                             High          Low                 High          Low
                                           -------       -------             -------       -------
         <S>                               <C>           <C>                 <C>           <C>
         First Quarter                     $19-1/8       $14-5/8             $12-1/8       $ 7-1/4
         Second Quarter                     19            15-1/4              10-1/4         7-5/8
         Third Quarter                      23-5/8        18-3/16             12             9-3/8
         Fourth Quarter                     24-7/8        16-3/4              17-3/4        11-3/4
</TABLE>

         On  February  27,  1998,  the  closing  price of the  common  stock was
$18-5/8.  Quarterly  dividends  were paid at the rate of $.065 per share  during
1997 and 1996.  For federal income tax purposes,  100% of common  dividends paid
during  1996  were a  non-taxable  return of  capital.  The  Company's  dividend
payments in 1997 were taxable for federal income tax purposes.  Shares of common
stock receive dividends as, if and when declared by the Board of Directors.  The
amount of future  dividends  will depend on debt service  requirements,  capital
expenditures and other factors.  On December 31, 1997, there were  approximately
2,300 holders of record of the common stock and 33.3 million shares outstanding.

ITEM 6.  SELECTED FINANCIAL DATA

         The  following   table  presents   selected   financial  and  operating
information  for each of the years in the five year period  ended  December  31,
1997.  Share  and per  share  amounts  refer to  common  shares.  The  following
information  should  be read in  conjunction  with  the  consolidated  financial
statements presented elsewhere herein.
<TABLE>
<CAPTION>

(In thousands, except per share data)                           As of or for the Year Ended December 31,
                                                       -----------------------------------------------------------------
                                                          1997          1996          1995          1994         1993
                                                       ----------    ----------    ----------    ----------   ----------

<S>                                                    <C>           <C>           <C>           <C>           <C>  
Income Statement
       Revenues                                        $  255,728    $  285,111    $  197,301    $  262,328    $ 228,852
       Income (loss) before extraordinary items            35,465        62,950       (39,831)       12,372       22,538
          Per share                                           .96          1.81         (1.53)          .07          .58
       Net income (loss)                                   32,617        62,950       (39,831)       12,372       19,545
          Per share                                           .87          1.81         (1.53)          .07          .45
          Dividends per share                                 .26           .26           .26           .25          .22
       Weighted average shares outstanding                 30,588        31,308        30,186        23,704       23,096

Cash Flow
       Net cash provided by operations                 $  122,041    $  101,730    $   69,121    $   86,397    $  68,728
       Net cash realized (used) by investing               31,808       (62,356)       32,421      (245,503)    (207,933)
       Net cash realized (used) by financing              (92,328)      (38,715)      (96,012)      169,926      129,633

Balance Sheet
       Working capital                                 $   56,326    $    9,168    $    5,842    $      708    $     491
       Oil and gas properties, net                        274,304       635,387       435,217       472,239      316,406
       Total assets                                       546,088       879,459       555,493       673,259      453,301
       Senior debt                                              1       188,231(a)    150,001       234,857      114,952
       Subordinated notes                                 173,635       183,842(b)     84,058        83,650         -
       Stockholders' equity                               263,756       294,668       235,368       274,086      274,734


<FN>
(a) Includes  $93.7  million of SOCO  senior  debt and $94.5  million of Patina senior debt.
(b) Includes $80.7 million of SOCO convertible  subordinated  notes and $103.1 million of Patina subordinated notes.
</FN>
</TABLE>

                                       20

<PAGE>

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


(In thousands, except per share data)                                                     1997
                                                                     -----------------------------------------------
                                                                      First        Second       Third        Fourth
                                                                     --------     ---------   ---------     --------
<S>                                                                  <C>          <C>         <C>           <C>      
Revenues                                                             $ 87,664     $ 73,187    $  56,299     $ 38,578
Depletion, depreciation and amortization and property impairments      23,208       23,389       26,802       13,738
Gross profit                                                           30,637       13,960       16,791       17,755
Income before extraordinary items                                      19,926        5,992        3,633        5,914
    Per share                                                             .59          .15          .07          .14
Net income                                                             19,926        3,144        3,633        5,914
  Per share                                                               .59          .05          .07          .14
</TABLE>

<TABLE>
<CAPTION>



(In thousands, except per share data)                                                      1996
                                                                     -----------------------------------------------
                                                                       First       Second       Third        Fourth
                                                                     --------     ---------    --------     --------
<S>                                                                  <C>          <C>          <C>          <C> 
Revenues                                                             $ 40,960     $ 54,604     $ 59,960     $129,587
Depletion, depreciation and amortization and property impairments      16,771       22,745       24,673       23,111
Gross profit                                                            9,376       11,099       10,835       26,467
Income (loss) before extraordinary items                                1,777       (9,983)       5,560       65,596
    Per share                                                             .01         (.37)         .13         2.06
Net income (loss)                                                       1,777       (9,983)       5,560       65,596
  Per share                                                               .01         (.37)         .13         2.06
  
</TABLE>


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

Overview

         Snyder Oil  Corporation  (the  "Company") is engaged in the production,
development,  acquisition  and  exploration of domestic oil and gas  properties,
primarily in the Gulf of Mexico, the Rocky Mountains and northern Louisiana. The
Company also has  investments in two  international  exploration  and production
companies,  SOCO  International plc ("SOCI plc") and Cairn Energy plc ("Cairn"),
both listed on the London Stock Exchange.

         During 1997, the Company consummated  several  transactions to simplify
its operating and capital structure.

       * The  Company exchanged its international operational holdings for stock
         in SOCI plc, which simultaneously  completed an initial public offering
         of its stock on the London Stock  Exchange to raise capital to fund its
         ongoing   exploration  and  development   efforts.   This   transaction
         effectively  replaced  the  Company's  equity  investments  in  various
         international ventures with one marketable security.
       * The Company  issued $175 million in ten-year,  8.75%  subordinated debt
         and  used  the  proceeds  to  redeem  the  outstanding  7%  convertible
         subordinated debt and to pay down its revolving credit facility.  These
         transactions  provided  the  capacity  for the  Company to enter into a
         large  acquisition from existing credit sources,  extended the maturity
         of  subordinated  debt at an attractive rate for the next ten years and
         eliminated  the  potential  dilution  of common  shareholders  from the
         convertible subordinated debt.
       * The  Company  sold its 74%  interest in Patina Oil and Gas  Corporation
         ("Patina") for  approximately  $127 million in cash and the elimination
         of approximately  $170 million in debt. This transaction  provided cash
         and  additional  acquisition  capacity  while  simplifying  the capital
         structure of the Company.  Patina was  restricted by its debt covenants
         from paying  dividends  to its  shareholders;  thus the Company did not
         directly benefit from the cash flow of Patina.
       * The  Company  issued  300,000 common shares in exchange for 2.1 million
         outstanding warrants,  which also reduced the potential dilution of the
         common shareholders of the Company.
       * The  Company  called  its   preferred  stock  for  redemption  with 72%
         converting  to common (3.6  million  shares  issued) and the  remainder
         being redeemed for $30.1 million of cash. This  transaction  eliminated
         1.4  million  shares of  additional  potential  dilution  to the common
         shareholders  of the  Company  and over $6 million per year in dividend
         payments.

                                       21

<PAGE>

         The  aforementioned   transactions  simplified  the  Company's  capital
structure  and,  together with the sale of  nonstrategic  assets during 1995 and
1996,  positioned  the Company to focus on its core growth areas with all future
increases in value going to the common shareholders of the Company.

         Unless  indicated  otherwise,  amounts in this  discussion  reflect the
consolidated results of the Company, including Patina. References to the Company
"excluding  Patina"  refer to the  Company  on a  consolidated  basis  but after
excluding amounts attributable to Patina.

Results of Operations

         Comparison  of 1997  results  to 1996.  Net  income  for 1997 was $32.6
million  as  compared  to  $63.0  million  in 1996.  During  1997,  the  Company
recognized a $13.0 million gain on the sale of 4.5 million shares of Cairn stock
and a $19.8  million  gain on the  formation  of SOCI  plc.  Net  income in 1996
benefited from a $65.5 million gain on the exchange of the Company's  stock held
in Command Petroleum Limited  ("Command"),  for stock in Cairn, a United Kingdom
based company.

         The following  table sets forth certain  operating  information  of the
Company for the periods presented.
<TABLE>
<CAPTION>

                                           Excluding Patina                             Consolidated           
                                        -----------------------     Increase       -----------------------     Increase 
                                          1997           1996      (Decrease)        1997           1996      (Decrease)
                                        --------       --------    ----------      ---------      --------    ----------

<S>                                     <C>            <C>           <C>            <C>           <C>            <C>
Oil and gas sales (in thousands)        $133,851       $107,143       25%           $207,216      $189,327         9%
Production margin (in thousands)        $ 98,835       $ 72,025       37%           $158,693      $139,689        14%
Daily production:
     Oil (Bbls)                            5,617          6,000       (6%)             9,561        10,611       (10%)
     Gas (Mcf)                           113,361         87,139       30%            168,873       152,570        11%
     Equivalent barrels (BOE)             24,510         20,525       19%             37,707        36,040         5%
Average Prices:
     Oil ($/Bbl)                        $  18.24       $  20.34      (10%)           $ 18.88      $  20.39        (7%)
     Gas ($/Mcf)                        $   2.33       $   1.96       19%            $  2.29      $   1.97        16%
     Equivalent barrel ($/BOE)          $  14.96       $  14.26        5%            $ 15.06      $  14.35         5%
DD&A per BOE                            $   4.87       $   5.29      (10%)           $  5.80      $   6.41       (10%)

</TABLE>

         Oil and gas sales, excluding Patina, increased 25% due to a significant
increase in gas production along with higher gas prices.  Production in the Gulf
of Mexico more than doubled due to two fourth quarter 1996  acquisitions and the
Company's  drilling  efforts  beginning  to come on stream.  The Rocky  Mountain
Region  also  increased  production  due  to  successful   development  drilling
primarily  in the  second  and third  quarters  of 1997,  but the  increase  was
partially  offset by sales of nonstrategic  properties  during 1996. The Company
expects increasing  production from exploratory and development  drilling during
1997 and 1998 to largely replace  Patina's 1997  production  contribution by the
end of 1998. The largest contributor to increased production in 1998 is expected
to be the commencement of production from the Ingrid Field in the Gulf of Mexico
by April 1998.

         Production  margin (oil and gas sales less direct  operating  expenses)
for 1997,  excluding Patina,  increased 37% compared to 1996 as direct operating
expenses decreased in spite of the significant  increase in production.  This is
primarily due to the sale of noncore  properties which had high operating costs,
increased  production in the Gulf of Mexico which has much lower operating costs
per BOE produced, and an increased emphasis on operating efficiencies. Operating
costs per BOE, excluding Patina, were $3.91 compared to $4.67 in 1996.

         Gains on sales of  properties  of $8.7 million in 1997 and $8.8 million
in 1996 were a result of the  Company's  ongoing plan to divest of  nonstrategic
assets.  The most  significant  items  in 1997  were  the  sales of two  noncore
properties in the Gulf of Mexico for a $5.1 million gain.  The most  significant
item during 1996 was a $7.4  million  gain on the sale of a 50%  interest in the
Green River Basin holdings.

         General and administrative  expenses,  net of reimbursements,  for 1997
were $20.4 million,  a $3.2 million increase  compared to 1996 as several of the

                                       22


<PAGE>

properties  sold during 1996,  while having high operating  costs and depletion,
depreciation  and  amortization   rates,   provided   significant   general  and
administrative expense reimbursements. Net general and administrative costs have
declined  three to six percent  each quarter  since the fourth  quarter of 1996.
There was a 16%  decrease  in the  fourth  quarter of 1997  attributable  to the
disposition of Patina.

         Interest  expense,  net of interest income,  was $23.0 million in 1997,
$12.5 million of which was incurred by Patina. In 1996, interest expense, net of
interest  income,  was $22.9  million,  $14.3  million of which was  incurred by
Patina.  The majority of the increase was the result of higher average  interest
rates,  as  subordinated  notes  represented a higher  percentage of total debt.
Interest  income in 1997 was $2.4  million  compared  to $664,000 in 1996 as the
Company had a higher average cash balance, particularly in the fourth quarter of
1997, due to the proceeds from the disposition of Patina.

         Depletion,  depreciation  and  amortization  expense for 1997 decreased
$4.7 million to $79.9 million in spite of higher production levels. The decrease
is primarily due to higher 1996 amortization costs on a noncompete  agreement at
Patina, but was also the result of lower production depletion,  depreciation and
amortization rates. Production depletion, depreciation and amortization per BOE,
excluding  Patina,  was $4.44 in 1997 compared to $4.70 in 1996. The lower rates
were the  result of upward  revisions  in  reserve  quantities  at year end 1996
primarily in proved undeveloped  reserves which became economic at year end 1996
prices.

         Property  impairments  in  1997  included  a  $4.5  million  impairment
recorded on the Uinta Field. At the end of 1996,  Uinta prices  benefited from a
tight local oil supply and very high Rocky Mountain area oil prices. Since then,
new supplies have  depressed the oil market and prices in the area have returned
to more normal levels. Additionally, a $2.2 million impairment was recorded on a
Gulf of Mexico oil well after it did not respond to workover attempts.

         Comparison of 1996 results to 1995. Total revenues for 1996 were $285.1
million,  a $87.8 million increase from 1995. The increase was in large part due
to a $67.2 million increase in gains on sales of investments which was primarily
due to a $65.5  million  gain  recognized  in the fourth  quarter  related to an
exchange of the Company's  stock held in Command for stock in Cairn. An increase
in oil and gas sales of $44.7 million was also  experienced  in 1996 as a result
of a 31% rise in the price received per BOE while production remained relatively
stable compared to 1995.  Natural gas prices  rebounded in 1996 to $1.97 per Mcf
from $1.35 per Mcf in 1995, a 46% increase.  Oil prices  improved 20% to average
$20.39 per barrel  during  1996.  Partially  offsetting  these  increases  was a
decrease  in gas  transportation,  processing  and  marketing  revenues of $20.6
million  primarily  as a result  of the  sale of the  Company's  Wattenberg  gas
facilities in 1995.

         Net income for 1996 was $63.0  million,  compared to a net loss in 1995
of $39.8  million.  The 1996 income was boosted by the net effect of the Command
transaction  ($57.2  million after  minority  interest  expense and deferred tax
expense).  However,  the Company also recorded a noncash charge of $15.5 million
in the second quarter related to the  contribution  of the Company's  Wattenberg
oil and gas properties to a newly formed public company, Patina, in return for a
70% stake in Patina. The 1995 loss was primarily due to $27.4 million in noncash
property  impairment charges and almost $11 million in combined losses resulting
from a  litigation  settlement,  losses  on  marketable  securities,  as well as
severance and restructuring  costs.  Absent these special  non-recurring  items,
there was an  increase  in net  income  from 1995 to 1996 of  approximately  $23
million.  This  increase  can be  attributed  primarily  to the 31%  increase in
average price  received per BOE which  increased  revenues  $44.7 million offset
partially by a decrease in gas management margin of $6.2 million and an increase
in depreciation, depletion and amortization expense of $8.2 million.

         Revenues from production  operations,  less direct operating  expenses,
for 1996 were $139.7 million, an increase of 52% from 1995 net revenue.  Average
daily production  during 1996 was 36,040 BOE, almost exactly what it was in 1995
(36,024 BOE).  However,  the average product price received  increased by 31% to
$14.35 per BOE.  Production remained relatively constant from 1995 to 1996 which
can be  attributed  to  additional  interests  acquired  in four  Gulf of Mexico
acquisitions  in late 1995 and during  1996 and the  properties  acquired in the
Patina transaction  offset by decreased  production related to numerous sales of
noncore  properties in 1995 and 1996 and the reduction of development  drilling.
Total  operating  expenses  for 1996  decreased by $2.8 million in line with the
Company's efforts of divesting of marginal  properties with high operating costs
and  acquiring   incremental   interests  in  offshore   properties  which  have
historically  had lower  operating  costs per BOE.  Operating costs per BOE were
$3.76 compared to $3.99 in 1995.

                                       23

<PAGE>

         Direct  operating  margin  from  gas  transportation,   processing  and
marketing  for 1996 was $2.6  million  compared  to $8.9  million  in 1995.  The
decrease  resulted  primarily from a reduction in processing  margins due to the
sale of the Company's  Wattenberg gas processing  facilities which was completed
in the third quarter of 1995. The Company  realized  almost $80 million in sales
proceeds during 1995 on these  facilities and recognized a total of $8.7 million
in gains.

         Gains on sales of investments  were $69.3 million in 1996,  compared to
$2.2 million in 1995. The $65.5 million gain on the Command  exchange  accounted
for the bulk of the increase.  The remaining gains are primarily due to sales of
a portion of the Company's  interests in Russia and  Mongolia.  In January 1997,
the Company's interest in Mongolia was further reduced.

         Gains on sales of  properties  were $8.8  million in 1996,  compared to
$12.3 million in 1995. The most  significant gain during 1996 was a $7.4 million
gain on the sale of a 50%  interest in the Green River Basin  holdings for $16.9
million.  The most  significant  gain  during  1995 was the  $8.7  million  gain
recognized  as  part of the  sale of the  Company's  Wattenberg  gas  processing
facilities for almost $80 million.

         Other income,  net of other expense,  increased $1.8 million from 1995.
The  increase  can be  primarily  attributed  to equity in  earnings  of Command
increasing $1.9 million from the equity in losses recorded in 1995.

         Exploration expenses for 1996 were $4.2 million, down $3.8 million from
1995.  The decrease  was due  primarily to a writeoff of $4.1 million of acreage
costs in 1995 that was not incurred in 1996.  Included in the 1996  expenditures
of $4.2 million was a $1.2 million dry hole drilled in the Gulf of Mexico in the
third quarter on an unexplored  block  adjacent to one of the Company's  current
producing blocks.

         General and administrative  expenses,  net of reimbursements,  for 1996
were $17.1 million as compared to $17.7 million in 1995. The slight  decrease is
the result of ongoing expense  reduction efforts and reductions in personnel due
to the  property  divestitures  that have  taken  place  over the past two years
offset somewhat by increased expenses related to the Patina transaction.

         Net  financing  costs were $22.9  million  compared to $21.7 million in
1995.  The majority of the increase is the result of a higher  average  interest
rate  primarily  due to  Patina's  subordinated  notes  which have an  effective
interest rate of 11.1%.

         Depletion,  depreciation and amortization  expense in 1996 increased to
$84.5 million from $76.4 million in 1995.  The increase  reflects an increase in
the overall depletion,  depreciation and amortization rate per equivalent barrel
from $5.80 to $6.41.  This increase can be  attributed to downward  revisions in
reserve  quantities at year end 1995  primarily in proved  undeveloped  reserves
which became  uneconomic  at year end 1995 prices and the growing  impact of the
Gulf of Mexico operations which are typically more capital intensive thus having
a higher depletion rate.

Acquisition, Exploration and Development

         During 1997, the Company,  excluding  Patina incurred $103.9 million in
capital expenditures, including $74.7 million for development, $17.2 million for
exploration, $8.9 million for property acquisitions,  $2.2 million for field and
office equipment and $900,000 for gas facility expansion.

         Of the total development  expenditures,  $36.4 million was concentrated
in the Gulf of Mexico where five wells were placed on sales with two in progress
at year end. The Company  expended  $13.0 million in the East Washakie  Basin of
southern  Wyoming to place 19 wells on sales with five in  progress at year end.
In the Green River  Basin of southern  Wyoming,  $10.1  million was  incurred to
place 16 wells on sales with five in progress at year end. The Company  expended
$6.2  million in the  Piceance  Basin of western  Colorado  to place 22 wells on
sales with two in progress at year end.

         Exploration expenditures for 1997 totaled $17.2 million, including $8.0
million for two exploratory dry holes drilled in the Gulf of Mexico. The Company
has been successful on two of four exploratory wells in the Gulf of Mexico.  The
balance  is  primarily  the  cost of 3-D  seismic  in the Gulf of  Mexico  ($4.5
million),  in northern Louisiana ($2.3 million) and in the Rocky Mountain region
($2.2 million).

                                       24


<PAGE>

         The  Company,  excluding  Patina,  expended  $8.9  million  relating to
property  acquisitions  during  1997.  Of  this  amount,  $3.3  million  was for
producing properties and $5.6 million was for unevaluated properties.

Financial Condition and Capital Resources

         During 1997,  net cash provided by operations  was $122.0  million,  an
increase of 20%  compared to 1996.  As of December  31,  1997,  commitments  for
capital  expenditures  totaled $10.3 million.  The Company anticipates that 1998
expenditures  for  exploration  and development  will  approximate  $130 to $140
million.   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 internally  generated cash flow,
available cash, marketable securities and existing credit facilities.

         At December 31, 1997,  the Company had total assets of $546.1  million.
Total  capitalization  was  $437.4  million,  of which  60% was  represented  by
stockholders'  equity and 40% by  subordinated  debt. At December 31, 1997,  the
Company had $89.4 million in cash, and marketable securities with a market value
of $143.1  million for its shares of Cairn and SOCI plc. The Patina  disposition
generated cash proceeds of  approximately  $127 million,  of which $30.1 million
was used in the fourth quarter to redeem the preferred stock.

         The Company  maintains a $500 million  revolving  credit  facility (the
"SOCO  Facility").  The SOCO Facility is divided into a $100 million  short-term
portion and a $400 million  long-term portion that expires on December 31, 2000.
Management's  policy  is to  renew  the  facility  on a  regular  basis.  Credit
availability  is adjusted  semiannually to reflect changes in reserves and asset
values. The borrowing base available under the facility at December 31, 1997 was
$120  million.  During 1997,  the average  interest  rate under the facility was
6.5%.  At  December  31,  1997,  the Company  had $1,000  outstanding  under the
facility. Covenants, in addition to other requirements, require maintenance of a
current  working  capital  ratio of 1 to 1 as defined,  limit the  incurrence of
additional debt and restrict dividends, stock repurchases,  certain investments,
other indebtedness and unrelated business  activities.  Such restricted payments
are limited by a formula that includes  proceeds from certain  securities,  cash
flow and other  items.  Based on such  limitations,  more than $120  million was
available for the payment of dividends and other restricted payments at December
31, 1997.

         In June 1997,  SOCO issued $175.0 million of 8.75% Senior  Subordinated
Notes  ("Notes") due June 15, 2007. The net proceeds of the offering were $168.3
million which were used to redeem the Company's  convertible  subordinated notes
due May 15, 2001,  and reduce the balance  outstanding  under the SOCO Facility.
Through the issuance of the new Notes and the  redemption of the old notes,  the
Company has effectively  extended its debt maturity by over six years. The Notes
contain  covenants that, among other things,  limit the ability of SOCO 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 unrestricred subsidiaries.  Such restricted payments are
limited by a formula that includes proceeds from certain  securities,  cash flow
and other items. Based on such limitations, more than $100 million was available
for the payment of dividends and other restricted payments at December 31, 1997.

         The Company seeks to diversify its exploration and development risks by
attracting partners for its significant  development  projects and maintaining a
program to divest of marginal  properties  and assets  which do not fit its long
range plans.  During 1997,  the Company  received $10.7 million in proceeds from
sales of properties which were used primarily to fund development  expenditures.
None of the sales were individually significant.

         The Board has authorized, at management's discretion, the repurchase of
up to $70 million of the Company's securities. During 1996 and 1997, the Company
repurchased 3.4 million common shares for $52.6 million under this plan.  During
1997,  the  Company  redeemed  its  preferred  depositary  shares by issuing 3.6
million shares of common stock and paying $30.1 million in cash. As a result,  a
$1.0 million redemption  premium is included in preferred  dividends in the 1997
consolidated statement of operations.

         The  Company has  developed a plan to ensure its systems are  compliant
with the requirements to process  transactions in the year 2000 and beyond.  The

                                       25

<PAGE>

majority of the Company's  systems are already  compliant,  with a detailed plan
for the remaining  systems scheduled to be modified or replaced within one year.
The costs associated with final compliance are not considered material.

         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.

Inflation and Changes in Prices

         While  certain of the Company's costs are affected by the general level
of inflation,  factors  unique to the petroleum  industry  result in independent
price  fluctuations.  Over the past five years,  significant  fluctuations  have
occurred in oil and gas prices.  In addition,  changing prices often cause costs
of  equipment  and  supplies to vary as industry  activity  levels  increase and
decrease to reflect perceptions of future price levels. Although it is 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
1997 and 1996.  Average gas prices for 1997 and 1996 were  increased by $.05 and
$.08 per Mcf, respectively,  by the benefit of the Company's hedging activities.
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 6 Mcf per barrel.
<TABLE>
<CAPTION>

                                                                      Average Prices
                                                      --------------------------------------------
                                                      Crude Oil
                                                         and              Natural       Equivalent
                                                       Liquids              Gas           Barrels
                                                      ---------          ---------       ---------
                                                      (Per Bbl)          (Per Mcf)       (Per BOE)
                        <S>                            <C>                <C>             <C>             
                        Annual
                        ------
                          1997                         $ 18.88            $ 2.29          $ 15.06
                          1996                           20.39              1.97            14.35
                          1995                           16.96              1.35            11.00
                          1994                           14.80              1.67            11.82
                          1993                           15.41              1.94            13.41

                        Quarterly
                        ---------
                         1997
                         ----
                         First                         $ 21.18            $ 2.83          $ 18.10
                         Second                          18.33              1.85            13.09
                         Third                           18.09              1.97            13.38
                         Fourth                          16.86              2.65            16.09

                         1996
                         ----
                         First                        $  17.95           $  1.78         $  12.80
                         Second                          20.52              1.62            12.90
                         Third                           20.25              1.78            13.60
                         Fourth                          22.26              2.64            17.69
</TABLE>

         In December 1997, the Company  received an average of $15.37 per barrel
and $2.43 per Mcf for its production.

                                       26


<PAGE>

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA


         Reference is made to the Index to Consolidated  Financial Statements on
page 28 for the Company's  consolidated  financial statements and notes thereto.
Quarterly  financial  data for the Company is  presented on page 21 of this Form
10-K.  Supplementary schedules for the Company have been omitted as not required
or not applicable  because the information  required to be presented is included
in the financial statements and related notes.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 
         FINANCIAL DISCLOSURES

         None














                                       27

<PAGE>


                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



                                                                            Page
                                                                            ----
Report of Independent Public Accountants......................................29

Consolidated Balance Sheets as of December 31, 1997 and 1996..................30

Consolidated Statements of Operations
     for the years ended December 31, 1997, 1996 and 1995.....................31

Consolidated Statements of Changes in Stockholders' Equity
     for the years ended December 31, 1997, 1996 and 1995.....................32

Consolidated Statements of Cash Flows
     for the years ended December 31, 1997, 1996 and 1995.....................33

Notes to Consolidated Financial Statements....................................34













                                       28
<PAGE>


                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
                    ----------------------------------------


To the Stockholders of Snyder Oil Corporation:

         We have audited the accompanying  consolidated balance sheets of Snyder
Oil  Corporation (a Delaware  corporation)  and  subsidiaries as of December 31,
1997 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, 1997. These financial  statements are the  responsibility  of
the Company's  management.  Our responsibility is to express an opinion on these
financial statements based on our audits.

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

         In our opinion,  the  financial  statements  referred to above  present
fairly,  in  all  material  respects,  the  financial  position  of  Snyder  Oil
Corporation  and  subsidiaries as of December 31, 1997 and 1996, and the results
of their  operations  and their  cash  flows for each of the three  years in the
period ended December 31, 1997, in conformity with generally accepted accounting
principles.

         As explained in Note 2 to the financial statements, the Company adopted
Statement  of  Financial  Accounting  Standards  No.  121,  "Accounting  for the
Impairment of Long-Lived  Assets and for Long-Lived Assets to Be Disposed Of" in
1995.




                                                       ARTHUR ANDERSEN LLP

Fort Worth, Texas,
February 10, 1998












                                       29

<PAGE>
<TABLE>

                                                 SNYDER OIL CORPORATION

                                               CONSOLIDATED BALANCE SHEETS
                                                     (In thousands)

<CAPTION>
                                                                                          December 31,
                                                                                --------------------------------
                                                                                   1997                  1996
                                                                                ----------           -----------
                                                         ASSETS
<S>                                                                             <C>                  <C>
Current assets
     Cash and equivalents                                                       $   89,443           $    27,922
     Accounts receivable                                                            21,521                58,944
     Inventory and other                                                             2,911                11,212
                                                                                ----------           -----------
                                                                                   113,875                98,078
                                                                                ----------           -----------

Investments                                                                        143,066               129,681
                                                                                ----------           -----------

Oil and gas properties, successful efforts method                                  410,973               887,721
     Accumulated depletion, depreciation and amortization                         (136,669)             (252,334)
                                                                                ----------           -----------
                                                                                   274,304               635,387
                                                                                ----------           -----------

Gas facilities and other                                                            21,317                28,111
     Accumulated depreciation and amortization                                      (6,474)              (11,798)
                                                                                ----------           -----------
                                                                                    14,843                16,313
                                                                                ----------           -----------
                                                                                $  546,088           $   879,459
                                                                                ==========           ===========

                                          LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
     Accounts payable                                                           $   23,278           $    51,867
     Accrued liabilities                                                            34,271                37,043
                                                                                ----------           -----------
                                                                                    57,549                88,910
                                                                                ----------           -----------

Senior debt                                                                              1               188,231
Subordinated notes                                                                 173,635               103,094
Convertible subordinated notes                                                      -                     80,748

Deferred taxes payable                                                              31,649                 9,034
Other noncurrent liabilities                                                        19,498                28,064

Minority interest                                                                   -                     86,710
Commitments and contingencies

Stockholders' equity
     Preferred stock,  $.01 par,  10,000,000 shares  authorized,
         6% Convertible preferred stock, zero and 1,033,500
         shares issued and outstanding                                              -                         10
     Common stock, $.01 par, 75,000,000 shares authorized,
         35,696,213 and 31,456,027 issued                                              357                   315
     Capital in excess of par value                                                234,118               260,221
     Retained earnings                                                              44,390                25,711
     Common stock held in treasury, 2,366,891 and 250,000 shares at cost           (40,461)               (3,510)
     Unrealized gain on investments                                                 25,352                11,921
                                                                                ----------           -----------
                                                                                   263,756               294,668
                                                                                ----------           -----------
                                                                                $  546,088           $   879,459
                                                                                ==========           ===========

                              The accompanying notes are an integral part of these statements.
</TABLE>

                                                           30
<PAGE>
<TABLE>


                                                 SNYDER OIL CORPORATION

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

                                                                                  Year Ended December 31,
                                                                       --------------------------------------------
                                                                           1997            1996            1995
                                                                       -----------     -----------      -----------
<S>                                                                    <C>             <C>              <C>    
Revenues
   Oil and gas sales                                                   $  207,216      $   189,327      $   144,608
   Gas transportation, processing and marketing                             7,004           17,655           38,256
   Gains on sales of equity interests in investees                         32,800           69,343            2,183
   Gains on sales of properties                                             8,708            8,786           12,254
                                                                       ----------      -----------      -----------
                                                                          255,728          285,111          197,301
                                                                       ----------      -----------      -----------
Expenses
   Direct operating                                                        48,523           49,638           52,486
   Cost of gas and transportation                                           6,692           15,020           29,374
   Exploration                                                             17,046            4,232            8,033
   General and administrative                                              20,363           17,143           17,680
   Financing costs, net                                                    23,029           22,923           21,679
   Other expense (income)                                                     935           (1,327)             463
   Litigation settlement                                                     -                -               4,400
   (Gain) loss on sale of subsidiary interest                              (5,437)          15,481             -
   Depletion, depreciation and amortization                                79,862           84,547           76,378
   Property impairments                                                     7,275            2,753           27,412
                                                                       ----------      -----------      -----------

Income (loss) before income taxes, minority interest
   and extraordinary item                                                  57,440           74,701          (40,604)
                                                                       ----------      -----------      -----------

Provision (benefit) for income taxes
   Current                                                                    975               33               25
   Deferred                                                                16,881            4,313           (1,370)
                                                                       ----------      -----------      -----------
                                                                           17,856            4,346           (1,345)
                                                                       ----------      -----------      -----------

Minority interest in subsidiaries                                           4,119            7,405              572
                                                                       ----------      -----------      -----------

Income (loss) before extraordinary item                                    35,465           62,950          (39,831)

Extraordinary item - loss on early extinguishment of debt,
   net of income tax benefit of $1,533                                      2,848             -                -
                                                                       ----------      -----------      -----------

Net income (loss)                                                          32,617           62,950          (39,831)
                                                                       ----------      -----------      -----------

Preferred dividends                                                         5,978            6,210            6,210
                                                                       ----------      -----------      -----------

Income (loss) applicable to common                                     $   26,639      $    56,740      $   (46,041)
                                                                       ==========      ===========      ===========

Income (loss) per common share before extraordinary item               $      .96      $      1.81      $     (1.53)
                                                                       ==========      ===========      ===========

Net income (loss) per common share                                     $      .87      $      1.81      $     (1.53)
                                                                       ==========      ===========      ===========

Income (loss) per common share before extraordinary
   item - assuming dilution                                            $      .95      $      1.72      $     (1.53)
                                                                       ==========      ===========      ===========

Net income (loss) per common share - assuming dilution                 $      .86      $      1.72      $     (1.53)
                                                                       ==========      ===========      ===========

Weighted average shares outstanding                                        30,588           31,308           30,186
                                                                       ==========      ===========      ===========

                               The accompanying notes are an integral part of these statements.
</TABLE>

                                                            31
<PAGE>
<TABLE>


                                               SNYDER OIL CORPORATION
                                        CONSOLIDATED STATEMENTS OF CHANGES IN
                                                STOCKHOLDERS' EQUITY
                                                   (In thousands)
<CAPTION>
                                                                                
                               Preferred Stock            Common Stock           Capital in     Retained
                              ------------------       -------------------        Excess of      Earnings       Treasury
                              Shares      Amount       Shares      Amount        Par Value      (Deficit)        Stock
                              ------      ------       ------     --------       ---------      ---------      --------

<S>                           <C>       <C>            <C>        <C>            <C>            <C>           <C>         
Balance, December 31, 1994    1,035     $     10       30,209     $    302       $ 255,961      $  20,959     $  (2,288)

    Common stock grants and
       exercise of options    -           -               138            1             856         -               (169)

    Issuance of common        -           -             1,083           11          13,021         -             -

    Dividends                 -           -             -           -               (3,927)       (10,129)       -

    Net loss                  -           -             -           -               -             (39,831)       -
                            -------     --------      -------     --------       ---------      ---------     ---------

Balance, December 31, 1995    1,035           10       31,430          314         265,911        (29,001)       (2,457)

    Common stock grants and
       exercise of options    -           -               267            3           3,179         -               (258)

    Issuance of common        -           -               399            4           3,689         -             -

    Repurchase of common      -           -              (640)          (6)         (6,243)        -               (795)

    Repurchase of preferred      (1)      -             -           -                 (142)        -             -

    Dividends                 -           -             -           -               (6,173)        (8,238)       -

    Net income                -           -             -           -               -              62,950        -
                            -------     --------      -------     --------       ---------      ---------     ---------

Balance, December 31, 1996    1,034           10       31,456          315         260,221         25,711        (3,510)

    Common stock grants and
       exercise of options    -           -               607            6           2,951         -             -

    Issuance of treasury      -           -             -           -               -              -              8,655

    Conversion of subordinated
       notes into common      -           -                 1       -                   25         -             -

    Repurchase of common      -           -             -           -               -              -            (45,606)

    Redemption of preferred    (291)          (3)       -           -              (29,050)        (1,049)       -

    Conversion of preferred    (743)          (7)       3,632           36             (29)        -             -

    Dividends                 -           -             -           -               -             (12,889)       -

    Net income                -           -             -           -               -              32,617        -
                            -------     --------      -------     --------       ---------      ---------     ---------

Balance, December 31, 1997    -           -            35,696     $    357       $ 234,118      $  44,390     $ (40,461)
                            =======     ========      =======     ========       =========      =========     =========


                              The accompanying notes are an integral part of these statements.

 
                                                          32
</TABLE>

<PAGE>
<TABLE>


                                               SNYDER OIL CORPORATION
                                        CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                   (In thousands)
<CAPTION>
                                                                                 Year Ended December 31,
                                                                     ---------------------------------------------
                                                                        1997              1996             1995
                                                                     ------------     -----------       ----------
<S>                                                                  <C>              <C>               <C>    
Operating activities
   Net income (loss)                                                 $    32,617      $    62,950       $  (39,831)
   Adjustments to reconcile net income (loss) to net
      cash provided by operations

          Amortization of deferred credits                                -                (1,052)          (2,511)
          Gains on sales of investments                                  (32,800)         (68,343)            (809)
          Gains on sales of properties                                    (8,708)          (8,786)         (12,254)
          Exploration expense                                             17,046            4,232            8,033
          Equity in (earnings) losses of unconsolidated subsidiaries        (760)            (421)           1,319
          (Gain) loss on sale of subsidiary interest                      (5,437)          15,481           -
          Depletion, depreciation and amortization                        79,862           84,547           76,378
          Property impairments                                             7,275            2,753           27,412
          Deferred taxes                                                  15,348            4,313           (1,370)
          Minority interest                                                4,119            7,405              572
          Loss on early extinguishment of debt                             4,381           -                -

          Changes in current and other assets and liabilities
            Decrease (increase) in
               Accounts receivable                                        24,612          (15,869)           7,142
               Inventory and other                                           426            5,175            3,617
            Increase (decrease) in
               Accounts payable                                           (8,688)           2,771           (8,521)
               Accrued liabilities                                        (9,497)            (316)           5,165
               Other liabilities                                           2,245            6,890            4,779
                                                                     -----------      -----------       ----------
          Net cash provided by operations                                122,041          101,730           69,121
                                                                     -----------      -----------       ----------

Investing activities
   Acquisition, development and exploration                             (135,901)        (128,598)         (92,353)
   Proceeds from sales of investments                                    156,969            1,635           14,786
   Outlays for investments                                                -                (9,013)          -
   Proceeds from sales of properties                                      10,740           73,620          109,988
                                                                     -----------      -----------       ----------
          Net cash realized (used) by investing                           31,808          (62,356)          32,421
                                                                     -----------      -----------       ----------

Financing activities
   Issuance of common                                                      2,982            1,523              688
   Issuance of subordinated notes                                        168,261           -                -
   Increase (decrease) in senior indebtedness                            (89,775)         (13,289)         (86,193)
   Early extinguishment of convertible subordinated notes                (85,199)          -                -
   Dividends                                                             (12,889)         (14,411)         (14,056)
   Deferred credits                                                       -                  (120)           3,549
   Redemption of preferred                                               (30,102)          -                -
   Repurchase of stock                                                   (45,606)          (7,186)          -
   Repurchase of subordinated notes                                       -                (5,232)          -
                                                                     -----------      -----------       ----------
          Net cash used by financing                                     (92,328)         (38,715)         (96,012)
                                                                     -----------      -----------       ----------

Increase in cash                                                          61,521              659            5,530
Cash and equivalents, beginning of year                                   27,922           27,263           21,733
                                                                     -----------      -----------       ----------
Cash and equivalents, end of year                                    $    89,443      $    27,922       $   27,263
                                                                     ===========      ===========       ==========

Noncash investing and financing activities
   Acquisition of properties and stock via stock issuances           $     8,655      $     3,693       $   13,032
   Acquisition of properties recorded as senior debt                      -                31,730           -
   Acquisition via subsidiary stock issuance                              -               115,067           -
   Exchange of subsidiary stock for stock of investee                     30,923           -                -


                              The accompanying notes are an integral part of these statements.
</TABLE>
                                                           33
<PAGE>


                                                                  
                             SNYDER OIL CORPORATION

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)      ORGANIZATION AND NATURE OF BUSINESS

         Snyder Oil Corporation ("SOCO") and its subsidiaries (collectively, the
"Company")  are  engaged  in  the  production,   development,   acquisition  and
exploration of domestic oil and gas properties, primarily in the Gulf of Mexico,
the Rocky Mountains and northern Louisiana.  The Company also has investments in
two international  exploration and production companies,  SOCO International plc
("SOCI  plc")  and  Cairn  Energy  plc  ("Cairn").   The  Company,   a  Delaware
corporation, is the successor to a company formed in 1978.

         In October  1997,  the Company  sold its 74% interest in Patina Oil and
Gas Corporation  ("Patina").  Net proceeds from the sale were approximately $127
million  resulting  in a $2.8 million  gain,  net of tax.  The  following  table
represents the Company's condensed  statements of operations,  excluding Patina.
Had the  disposition  of Patina  been  consummated  on January 1, 1997 and 1996,
financing  costs,  net of tax,  would have been reduced by $3.3 million in 1997,
and $4.5  million in 1996,  from the amounts  shown in the  following  schedule.
Future results may differ  substantially from these condensed  statements or pro
forma  results due to changes in oil and gas  prices,  production  declines  and
other factors.  Therefore,  such statements  cannot be considered  indicative of
future operations.
<TABLE>
<CAPTION>

(In thousands, except per share and production data)                          For the Year Ended December 31,
                                                                           -----------------------------------
                                                                               1997                    1996
                                                                           -----------             -----------
                                                                                       Unaudited
<S>                                                                        <C>                     <C>    
Revenues
     Oil and gas sales                                                     $   133,851             $   107,143
     Other                                                                      48,512                  95,784
                                                                           -----------             -----------
                                                                               182,363                 202,927

Expenses
     Direct operating                                                           35,016                  35,118
     Exploration                                                                16,926                   4,008
     General and administrative                                                 16,566                  10,993
     Financing costs, net                                                       10,556                   8,619
     Depletion, depreciation and amortization                                   43,599                  39,725
     Other                                                                      10,143                  32,930
                                                                           -----------             -----------

Income before taxes, minority interest and extraordinary item                   49,557                  71,534

Provision for income taxes                                                      17,856                   4,740
Minority interest                                                                  616                   4,866
Extraordinary item, net of tax                                                   2,848                    -
                                                                           -----------             -----------

Net income                                                                 $    28,237             $    61,928
                                                                           ===========             ===========

Net income per common share                                                $       .73             $      1.78
                                                                           ===========             ===========

Weighted average shares outstanding                                             30,588                  31,308
                                                                           ===========             ===========

Daily Production
     Oil (Bbls)                                                                  5,617                   6,000
     Gas (Mcf)                                                                 113,361                  87,139
</TABLE>

                                                           34


<PAGE>


(2)      SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

         The  consolidated  financial  statements  include  the  accounts of the
Company.  Affiliates  in which the Company owns more than 50% but less than 100%
are fully  consolidated,  with the related minority interest being deducted from
subsidiary  earnings and stockholders'  equity.  Affiliates in which the Company
owns between 20% and 50% are accounted for using the equity  method.  Affiliates
in which the Company owns less than 20% are accounted for using the cost method.
At December 31, 1997,  affiliates accounted for under this method included Cairn
and SOCI plc.  The  Company  accounts  for its  interest in joint  ventures  and
partnerships  using  the  proportionate   consolidation   method,   whereby  its
proportionate   share  of  assets,   liabilities,   revenues  and  expenses  are
consolidated.

Risks and Uncertainties

         Historically,  the market for oil and gas has  experienced  significant
price  fluctuations.  Prices  for gas in the Rocky  Mountain  region,  where the
Company  produces a substantial  portion of its natural gas, have  traditionally
been  particularly  volatile.  Prices are  significantly  impacted  by the local
weather,  supply in the area,  seasonal  variations  in local demand and limited
transportation capacity to other regions of the country.  Increases or decreases
in  prices  received,   particularly  in  the  Rocky  Mountains,  could  have  a
significant impact on the Company's future results of operations.

         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.

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.  During 1997
and 1996, the Company  provided  unproved  property  impairments of $700,000 and
$2.8 million,  respectively.  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 6 Mcf to 1 barrel. Amortization of capitalized costs is generally
provided on a  property-by-property  basis.  Estimated future  abandonment costs
(net of salvage values) are accrued at  unit-of-production  rates and taken into
account in determining depletion, depreciation and amortization.

         The Company follows Statement of Financial Accounting Standards No. 121
("SFAS  121"),  "Accounting  for the  Impairment  of  Long-Lived  Assets and for
Long-Lived  Assets to be Disposed  Of." SFAS 121  requires the Company to assess
the need for an impairment of  capitalized  costs of oil and gas  properties and
other   assets.   Oil  and  gas   properties   are   generally   assessed  on  a
property-by-property  basis. If an impairment is indicated based on undiscounted
expected  future net cash flows,  then it is  recognized  to the extent that net
capitalized costs exceed discounted expected future net cash flows. Accordingly,
during 1997 and 1995,  the Company  provided for $6.6 million and $27.4 million,
respectively, for such impairments. During 1996, the Company did not provide for
any such impairments.

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 $2.4 million  during 1997 and $2.5 million  during each of 1996
and 1995. Of these  amounts,  $1.3 million in 1997 and $1.5 million in 1996 were

                                       35


<PAGE>

recognized by Patina.  These  arrangements,  excluding  Patina,  are expected to
continue 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
proportionate  share of gas  produced.  Gas  imbalances at December 31, 1997 and
1996 were not significant.

Financial Instruments

         The following table sets forth the book value and estimated fair values
of financial instruments:
<TABLE>
<CAPTION>

                                                                    December 31,               December  31,
                                                                       1997                       1996
                                                              ----------------------     ----------------------
                                                                Book         Fair          Book         Fair
                                                                Value        Value         Value        Value
                                                              ---------    ---------     ---------    ---------
                                                                                (In thousands)
         <S>                                                  <C>          <C>           <C>          <C>    
         SOCO
              Cash and equivalents                            $  89,443    $  89,443     $  21,769    $  21,769
              Investments                                       143,066      143,066       129,681      163,477
              Senior debt                                            (1)          (1)      (93,731)     (93,731)
              Subordinated notes                               (173,635)    (178,063)       -            -
              Convertible subordinated notes                     -            -            (80,748)     (82,866)
              Long-term commodity contracts                      -             7,318        -             5,040
              Interest rate swap                                 -            -             -               (19)
         Patina
              Cash and equivalents                               -            -              6,153        6,153
              Senior debt                                        -            -            (94,500)     (94,500)
              Subordinated notes                                 -            -           (103,094)    (105,650)
</TABLE>


         The book value of cash and equivalents  approximates fair value because
of the short maturity of those instruments. See Note (3) for a discussion of the
Company's investments.  The fair value of senior debt is presented at face value
given its floating rate structure.  The fair value of the subordinated notes and
convertible  subordinated  notes are estimated  based on their December 31, 1997
and 1996 closing prices 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 in the period to which the contracts relate.

         In 1994, the Company  entered into a long-term gas swap  arrangement in
order to lock in the price differential between the Rocky Mountain and Henry Hub
prices on a portion of its Rocky Mountain gas  production.  The contract  covers
20,000  MMBtu's  per day  through  2004.  At  December  31,  1997,  that  volume
represented  approximately  30% of the Company's  Rocky Mountain gas production.
The fair  value of the  contract  was based on the  market  price  quoted  for a
similar instrument.

         At December 31,  1997,  the Company had entered into various swap sales
contracts  with a weighted  average  price  (NYMEX  based) of $2.62 for contract
volumes of  4,205,000  MMBtu's of natural gas for January 1998 through May 1998.
Also, the Company had entered into various swap sales  contracts with a weighted
average price (CIG-Inside FERC based) of $2.14 for contract volumes of 2,250,000
MMBtu's of natural gas for January 1998  through  March 1998.  The  unrecognized
gain on these  contracts  totaled $2.4 million based on December 31, 1997 market
values.

         Subsequent  to  December  31,  1997,   the  Company  has  entered  into
additional swap sales  contracts with a weighted  average price (NYMEX based) of
$2.30 for contract  volumes of 17,120,000  MMBtu's of natural gas for April 1998

                                       36


<PAGE>

through  October 1998.  Also, the Company has entered into additional swap sales
contracts  with a weighted  average price  (CIG-Inside  FERC based) of $1.71 for
contract  volumes of  3,638,000  MMBtu's of natural  gas for April 1998  through
October 1998.

         In  September  1995,  the Company  entered  into an interest  rate swap
covering  $50  million of its bank debt.  The  agreement  required  payment to a
counterparty  based on a fixed rate of 5.585% and required the  counterparty  to
pay the  Company  interest  at the then  current  30 day  LIBOR  rate.  Accounts
receivable  or payable under this  agreement  were  recorded as  adjustments  to
financing  costs and  settled  on a monthly  basis.  The  agreement  matured  in
September  1997.  At December  31,  1996,  the fair value of the  agreement  was
estimated at the net present value discounted at 10%.

Other

         All liquid  investments  with an original  maturity of three  months or
less are  considered  to be cash  equivalents.  Certain  amounts in prior  years
consolidated financial statements have been reclassified to conform with current
classification.

(3)       INVESTMENTS

          The Company has investments in foreign energy  companies and long-term
notes  receivable.  The following table sets forth the book values and estimated
fair values of these investments:
<TABLE>
<CAPTION>

                                                               December 31, 1997             December 31, 1996
                                                          --------------------------    --------------------------
                                                             Book           Fair           Book           Fair
                                                             Value          Value          Value          Value
                                                          -----------    -----------    -----------    -----------
                                                                              (In thousands)

          <S>                                             <C>            <C>            <C>            <C>        
          Marketable securities                           $   143,066    $   143,066    $   115,558    $   115,558
          Equity method investments                            -              -               8,789         42,585
          Long-term notes receivable                           -              -               5,334          5,334
                                                          -----------    -----------    -----------    -----------

                                                          $   143,066    $   143,066    $   129,681    $   163,477
                                                          ===========    ===========    ===========    ===========
</TABLE>

         The Company follows SFAS 115,  "Accounting  for Certain  Investments in
Debt and Equity  Securities,"  which  requires  that  investments  in marketable
securities accounted for using the cost method and long-term notes receivable be
adjusted  to their  market  value with a  corresponding  increase or decrease to
stockholders'  equity. The pronouncement does not apply to investments accounted
for using the equity method.

Cairn

         From May 1993 to  November  1996,  the  Company  had an  investment  in
Command  Petroleum  Limited  ("Command"),  an Australian oil company,  which was
accounted for using the equity method.  In November 1996, the Company  exchanged
its  interest in Command for 16.2  million  shares of freely  marketable  common
stock of Cairn,  an  international  independent  oil company based in Edinburgh,
Scotland  whose  shares are listed on the London  Stock  Exchange.  The  Company
recognized a gain of $65.5 million in 1996 as a result of this exchange.

SOCI plc

         In 1993,  SOCO Perm Russia,  Inc.  ("SOCO Perm"),  was organized by the
Company and a U.S. industry participant.  SOCO Perm and a Russian partner formed
the Permtex joint venture to develop proven oil fields in the Volga-Urals  Basin
of Russia. A private  placement in April 1996 reduced the Company's  interest to
34.91%.  The  Company  recognized  a gain of $2.6  million  as a result  of this
transaction.

         In 1994,  the Company  formed a consortium to explore the Tamtsag Basin
of eastern Mongolia,  SOCO Tamtsag Mongolia, Inc. ("SOCO Tamtsag"). In 1996, the
Company  completed  the  exchange  of a portion of its  interest  to an industry
participant for consulting  services valued at $1.5 million. As a result of this
transaction, the Company's ownership was reduced to 42% and an $832,000 gain was
recognized.

                                       37


<PAGE>

         In May 1997,  a newly  formed  entity,  SOCI plc,  completed an initial
public offering of its shares on the London Stock Exchange.  Simultaneously with
the offering, the Company exchanged its shares of SOCO International Operations,
Inc.,  which  included the  Company's  interests in SOCO Perm,  SOCO Tamtsag and
certain Thailand  properties,  for shares of SOCI plc. Certain minority interest
owners  in these  ventures  also  contributed  their  interests.  As part of the
listing,  SOCI plc acquired Cairn's UK onshore company as well as certain assets
in Yemen and Tunisia that were formerly  owned by Command.  The offering  raised
approximately  $75  million  of new equity  capital  for SOCI plc.  The  Company
received  7.8  million  shares  (15.9% of the  total) of SOCI plc,  which it has
agreed not to sell for the two-year  period  following the listing.  The Company
recognized a gain of $19.8 million as a result of this exchange.

Marketable Securities

         As a result  of the  transactions  described  above,  the  Company  has
investments  in  equity   securities  of  two  publicly  traded  foreign  energy
companies, Cairn and SOCI plc. Both investments are accounted for using the cost
method.  In the first quarter of 1997, the Company sold 4.5 million Cairn shares
at an average  price of $8.81 per share  realizing  $39.2  million  in  proceeds
resulting in a gain of $13.0 million.  The Company's  carrying cost in the Cairn
and SOCI plc  shares  was $73.1  million  and $30.9  million,  respectively,  at
December  31,  1997.  The  market  value  of  the  Cairn  and  SOCI  plc  shares
approximated  $96.1  million and $47.0  million,  respectively,  at December 31,
1997. In accordance with SFAS 115, at December 31, 1997 and 1996,  respectively,
investments  were  increased  by  $39.0  million  and  $20.4  million  in  gross
unrealized  holding gains,  stockholders'  equity was increased by $25.3 million
and $11.9 million and deferred taxes payable were increased by $13.7 million and
$7.2 million.  In addition,  minority  interest  liability was increased by $1.3
million at December 31, 1996.

Notes Receivable

         The Company held notes  receivable  due from a director at December 31,
1997 and 1996.  At December  31, 1996,  the Company  also held a long-term  note
receivable due from SOCO Tamtsag,  a Mongolian  affiliate,  with a book value of
$4.7 million which was contributed to SOCI plc along with the Company's interest
in SOCO  Tamtsag in May 1997.  The notes from a director,  which  originated  in
connection  with  an  option  to  purchase  10% of the  Company's  international
affiliates  are due April 10,  1998,  and are  secured by shares of the  Company
which are owned by the director. At December 31, 1997, the notes were classified
as current assets in the accompanying  financial statements and had a book value
of  $647,000.  At  December  31,  1997 and  1996,  the fair  value of the  notes
receivable,  based on existing market conditions and the anticipated  future net
cash flow related to the notes, approximated their carrying cost.

                                       38

<PAGE>
(4)      OIL AND GAS PROPERTIES AND GAS FACILITIES

         The  cost of oil and gas  properties  at  December  31,  1997  and 1996
includes  $21.3  million  and  $32.7  million  of  unevaluated  leasehold.  Such
properties are held for exploration,  development or resale. The following table
sets forth costs  incurred  related to oil and gas properties and gas processing
and transportation facilities:
<TABLE>
<CAPTION>

                                                                             Excluding Patina
                                                            --------------------------------------------------
                                                               1997               1996                 1995
                                                            -----------       ------------         -----------
                                                                             (In thousands)

     <S>                                                    <C>               <C>                  <C>        
     Proved acquisitions                                    $     3,338       $     54,708         $    13,025
     Acreage acquisitions                                         5,609             24,589               7,388
     Development                                                 74,676             34,774              50,437
     Exploration                                                 17,217              4,364               7,798
     Gas processing, transportation and other                     3,096              3,612               7,873
                                                            -----------       ------------         -----------
                                                            $   103,936       $    122,047         $    86,521
                                                            ===========       ============         ===========
</TABLE>
<TABLE>
<CAPTION>

                                                                                  Patina
                                                            --------------------------------------------------
                                                                1997               1996                1995
                                                            ------------      ------------         -----------
                                                                              (In thousands)

     <S>                                                    <C>               <C>                  <C>        
     Proved acquisitions                                    $        338      $    218,380         $       650
     Development                                                  11,322             8,301              12,141
     Exploration                                                     121               224                 416
     Gas processing, transportation and other                        329           -                        13
                                                            ------------      ------------         -----------
                                                            $     12,110      $    226,905         $    13,220
                                                            ============      ============         ===========

</TABLE>

         Excluding  Patina,  the 1997 development  expenditures of $74.7 million
were  concentrated in the Gulf of Mexico and Rocky  Mountains.  During 1997, the
Company  placed 72 wells on sales with 24 wells in  progress  at year end.  1997
exploration  costs include the costs of two exploratory dry holes in the Gulf of
Mexico and continuing seismic programs in the Gulf of Mexico, northern Louisiana
and the Rocky Mountains.

         Proved  acquisitions during 1996 included $218.4 million related to the
formation of Patina  including the  acquisition of Gerrity Oil & Gas Corporation
("GOG").  In October 1997, the Company sold its interest in Patina. Net proceeds
from the sale were approximately $127 million.

(5)       INDEBTEDNESS

          The following indebtedness was outstanding on the respective dates:
<TABLE>
<CAPTION>

                                                                      December 31,        December 31,
                                                                         1997                 1996
                                                                      ------------        ------------
                                                                               (In thousands)

          <S>                                                          <C>                  <C> 
          SOCO subordinated notes                                      $   173,635          $  -
          SOCO bank facility                                                     1             93,731
          SOCO convertible subordinated notes                               -                  80,748
                                                                       -----------          ---------
                                                                           173,636            174,479
          Patina subordinated notes                                         -                 103,094
          Patina bank facilities                                            -                  94,500
                                                                       -----------          ---------
                                                                       $   173,636          $ 372,073
                                                                       ===========          =========
</TABLE>

         SOCO  maintains  a  $500  million   revolving  credit  facility  ("SOCO
Facility").  The SOCO Facility is divided into a $400 million  long-term portion
and  a  $100  million  short-term  portion.   Credit  availability  is  adjusted
semiannually to reflect changes in reserves and asset values. The borrowing base
available  under the facility was $120 million at December 31, 1997.  Borrowings
under the facility  generally  bear interest at prime,  with an option to select

                                       39

<PAGE>

LIBOR plus .75% or CD plus .75%.  The margin on LIBOR or CD increases to 1% when
the  Company's  consolidated  senior  debt  becomes  greater  than  80%  of  its
consolidated  tangible net worth, as defined.  During 1997, the average interest
rate under the  facility  was 6.5%.  The Company  pays certain fees based on the
unused  portion  of  the  borrowing  base.  Covenants,   in  addition  to  other
requirements,  require  maintenance of a current working capital ratio of 1 to 1
as defined,  limit the  incurrence  of additional  debt and restrict  dividends,
stock  repurchases,   certain  investments,  other  indebtedness  and  unrelated
business  activities.  Such  restricted  payments  are limited by a formula that
includes proceeds from certain  securities,  cash flow and other items. Based on
such  limitations,  more than $120  million  was  available  for the  payment of
dividends and other restricted payments at December 31, 1997.

         In June 1997,  SOCO issued $175.0 million of 8.75% Senior  Subordinated
Notes  ("Notes") due June 15, 2007. The Notes were sold at a discount  resulting
in an 8.875%  effective  interest  rate.  The net proceeds of the offering  were
$168.3 million which were used to redeem convertible  subordinated notes and pay
down the balance outstanding under the credit facility. The Notes are redeemable
at the option of the Company on or after June 15, 2002, initially at 104.375% of
principal,  and at prices  declining  to 100% of  principal on or after June 15,
2005. Upon the occurrence of a change of control,  as defined in the Notes, SOCO
would be obligated to make an offer to purchase all outstanding Notes at a price
of 101% of the principal amount thereof.  In addition,  SOCO would be obligated,
subject to certain conditions, to make offers to purchase the Notes with the net
cash proceeds of certain asset sales or other  dispositions of assets at a price
of 100% of the  principal  amount  thereof.  The  Notes  are  unsecured  general
obligations  of SOCO  and  are  subordinated  to the  SOCO  Facility  and to any
existing  and future  indebtedness  of SOCO's  subsidiaries.  The Notes  contain
covenants  that,  among  other  things,  limit  the  ability  of SOCO  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.  Such restricted payments are
limited by a formula that includes proceeds from certain  securities,  cash flow
and other items. Based on such limitations, more than $100 million was available
for the payment of dividends and other restricted payments at December 31, 1997.
The Company's international  subsidiaries and Patina are considered unrestricted
subsidiaries.  As such,  their  activities  and the proceeds  realized  from any
disposition of these interests are not restricted by the Note convenants.

         In 1994, SOCO issued $86.3 million of 7% convertible subordinated notes
due May  15,  2001.  The  net  proceeds  were  $83.4  million.  The  notes  were
convertible into common stock at $22.57 per share. During 1996 and the first six
months of 1997, the Company repurchased $3.8 million and $824,000, respectively,
of these notes in accordance with a repurchase program.  The notes were redeemed
by the  Company in June 1997 at 103.51%  of  principal.  As a result of the note
redemption,  the Company  incurred a loss of $4.4 million or $2.8 million net of
tax ($.09 per common share) which has been recorded as an extraordinary  item in
the accompanying financial statements.

         As a result of the  disposition  of Patina in  October  1997,  Patina's
indebtedness  is no longer  included  in the  Company's  consolidated  financial
statements.

         Scheduled  maturities of indebtedness  for the next five years are zero
in 1998 and  1999,  $1,000  in 2000 and zero in 2001  and  2002.  The  long-term
portion of the SOCO  Facility is  scheduled  to expire in 2000.  However,  it is
management's  policy to renew both the short-term  and long-term  facilities and
extend their maturities on a regular basis.

         Consolidated  cash  payments  for  interest  were $28.6 million,  $21.9
million and $22.1 million,  respectively, for 1997, 1996 and 1995.

                                       40

<PAGE>


(6)      FEDERAL INCOME TAXES

         At December 31, 1997, the Company had no liability for foreign taxes. A
reconciliation  of the United  States  federal  statutory  rate to the Company's
effective income tax rate for 1997, 1996 and 1995 follows:
<TABLE>
<CAPTION>

                                                               1997                  1996                1995
                                                            ----------            -----------         ----------

<S>                                                               <C>                    <C>                <C>  
Federal statutory rate                                             35%                    35%               (35%)
Net change in valuation allowance                                  (3%)                  (29%)            -
Tax effect of cumulative earnings of subsidiary                     1%                 -                  -
Loss in excess of net deferred tax liability                    -                      -                     32%
                                                            ----------             ----------          ---------
Effective income tax rate                                          33%                     6%                (3%)
                                                            ==========             ==========          =========
</TABLE>

         For book  purposes,  the  components  of the net deferred tax asset and
liability at December 31, 1997 and 1996, respectively, were:
<TABLE>
<CAPTION>

                                                                          1997               1996
                                                                       -----------        -----------
                                                                               (In thousands)
<S>                                                                    <C>                <C>  
Deferred tax assets
     NOL and capital loss carryforwards                                $    27,307        $    65,126
     AMT credit carryforwards                                                1,401                644
     Production payment receivables                                          5,557             32,654
     Reserves and other                                                      6,031              5,613
                                                                       -----------        -----------
                                                                            40,296            104,037
                                                                       -----------        -----------

Deferred tax liabilities
     Depreciable and depletable property                                   (30,964)           (59,865)
     Investments and other                                                 (25,884)           (42,252)
     Unrealized investments gains                                          (15,097)            (7,131)
                                                                       ------------       -----------
                                                                           (71,945)          (109,248)
                                                                       -----------        -----------

Deferred tax liability                                                     (31,649)            (5,211)
Valuation allowance                                                        -                   (3,823)
                                                                       -----------        -----------

Net deferred tax liability                                             $   (31,649)       $    (9,034)
                                                                       ===========        ===========
</TABLE>

         The  Company  had regular net  operating  loss  carryforwards  of $78.0
million at December 31, 1997. The majority of these carryforwards expire between
2006 and 2010 with a minimal amount expiring  between 1998 and 2005. At December
31, 1997, the Company also had alternative  minimum tax credit  carryforwards of
$1.4 million  which are available  indefinitely.  Cash payments for income taxes
were  $500,000 in 1997 and  $245,000  in 1995.  No cash  payments  were made for
income taxes in 1996.

(7)       STOCKHOLDERS' EQUITY

         A total of 75 million common shares,  $.01 par value, are authorized of
which 35.7 million were issued and 33.3 million were outstanding at December 31,
1997. In 1997,  the Company issued a total of 4.2 million shares of common stock
as follows:  3.6 million for the  conversion  of  preferred  shares,  300,000 in
exchange for 2.1 million of outstanding  warrants and 308,000  primarily for the
exercise of stock  options.  The Company also issued  530,000 shares of treasury
stock in exchange for a director's 10% interest in SOCO International  Holdings,
Inc. During 1997, the Company repurchased 2.6 million shares of common stock for
$45.6 million.  In 1996, the Company issued 666,000 shares of common stock, with
399,000  shares issued in exchange for the remaining  outstanding  stock of SOCO
Offshore,  Inc.  (formerly  DelMar  Operating,  Inc.) and 267,000  shares issued
primarily for the exercise of stock options and  repurchased  725,000  shares of
common stock for $7.0 million.  Quarterly dividends of $.065 per share were paid
in 1997 and  1996.  For book  purposes,  for the  period  between  June 1995 and
September 1996,  common stock dividends were in excess of retained earnings and,
as such, were treated as distributions of capital.

                                       41
<PAGE>

         A total of 10  million  preferred  shares,  $.01 par  value,  have been
authorized.  In 1993, 4.1 million depositary shares (each representing a quarter
interest in a share of $100 liquidation  value stock) of 6% preferred stock were
sold through an underwriting.  The net proceeds were $99.3 million. During 1996,
the Company  repurchased  6,000 shares for  $142,000.  During 1997,  the Company
called the preferred stock for  redemption.  The preferred stock was convertible
into common stock at $20.46 per share or the  liquidation  preference was $25.00
per  depositary  share,  plus accrued and unpaid  dividends.  As a result of the
call,  72% of the preferred  shares were  converted  into 3.6 million  shares of
common  stock.  The remaining  preferred  shares were redeemed for $29.1 million
before accrued dividends and a redemption premium. The Company paid $5.0 million
and $6.2  million  ($1.50  per 6%  convertible  depositary  share per  annum) in
preferred  dividends  during  1997  and  1996,  respectively.   A  $1.0  million
redemption  premium  for the  preferred  shares  is also  included  in the  1997
preferred dividend amount in the statement of operations.

         Effective December 31, 1997, the Company adopted Statement of Financial
Accounting Standards No. 128 ("SFAS 128"), "Earnings per Share" which prescribes
standards for computing and  presenting  earnings per share and  supersedes  APB
Opinion  No. 15,  "Earnings  per  Share." In  accordance  with SFAS 128,  income
applicable to common has been  calculated  based on the weighted  average shares
outstanding  during the year and income applicable to  common-assuming  dilution
has  been  calculated  assuming  the  exercise  or  conversion  of all  dilutive
securities  as of January  1, 1997 and 1996,  or as of the date of  issuance  if
later. The following table illustrates the calculation of earnings per share for
income from continuing operations.
<TABLE>
<CAPTION>

                                                                Income                 Shares          Per-Share
                                                             ------------             --------       ------------
       For the Year Ended December 31, 1997
       ------------------------------------
<S>                                                           <C>                      <C>           <C>             
Income before extraordinary item                              $    35,465
Preferred dividends                                                (5,978)
                                                              -----------

Income applicable to common
Income available to common shareholders                            29,487              30,588        $       .96


Effect of Dilutive Securities
Stock options                                                                             513
                                                              -----------         ----------- 
Income applicable to common-assuming dilution
Income available to common shareholders +
    assumed conversions                                       $    29,487              31,101        $       .95
                                                              ===========         ===========        ===========

       For the Year Ended December 31, 1996
       ------------------------------------
Income before extraordinary item                              $    62,950
Preferred dividends                                                (6,210)
                                                              -----------

Income applicable to common
Income available to common shareholders                            56,740              31,308        $      1.81

Effect of Dilutive Securities
Stock options                                                                             153
Convertible preferred stock                                         6,210               5,052
                                                              -----------         -----------

Income applicable to common-assuming dilution
Income available to common shareholders +
    assumed conversions                                       $    62,950              36,513        $      1.72
                                                              ===========         ===========        ===========
</TABLE>


         As of December  31,  1997,  the only  potentially  dilutive  securities
outstanding were stock options that have yet to be exercised.

         The  Company  maintains  a stock  option  plan  for  certain  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 determined by a

                                       42


<PAGE>

committee of independent  members of the Board. A stock grant and option plan is
also maintained by the Company whereby each  nonemployee  Director  receives 500
common shares  quarterly in payment of their annual  retainer.  It also provides
for 2,500  options to be granted  annually  to each  nonemployee  Director.  The
majority of  currently  outstanding  options vest over a three year period (30%,
60%, 100%) and expire five years from the date of grant.

          At  December  31,  1997,  the  Company  has  two  fixed  stock  option
compensation  plans,  which are 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
the method established by SFAS 123,  "Accounting for Stock-Based  Compensation,"
the Company's net income (in  thousands)  and earnings per share would have been
reduced to the pro forma amounts indicated below:
<TABLE>
<CAPTION>

                                                                1997              1996             1995
                                                              ---------         --------         ---------

<S>                                                            <C>              <C>               <C>      
Net income (loss)                   As Reported                $ 32,617         $ 62,950          $(39,831)
                                    Pro forma                  $ 29,260         $ 61,936          $(40,567)

Net income (loss) per common        As Reported                  $  .87           $ 1.81            $(1.53)
     share                          Pro forma                    $  .76           $ 1.78            $(1.55)
</TABLE>

         The fair value of each option  grant is  estimated on the date of grant
using the Black-Sholes  option-pricing model with the following weighted-average
assumptions used for grants in 1997, 1996 and 1995, respectively: dividend yield
of 1.6%,  2.8% and 1.9%;  expected  volatility  of 41%,  44% and 46%;  risk-free
interest rates of 6.1%, 5.7% and 7.2%; and an expected life of 4.5 years.

         A summary of the status of the  Company's  two fixed stock option plans
as of December  31,  1997,  1996 and 1995 and changes  during the years ended on
those dates is presented below (shares are in thousands):
<TABLE>
<CAPTION>

                                           1997                      1996                       1995
                                   --------------------       -------------------      ---------------------
                                              Weighted-                 Weighted-                  Weighted-
                                               Average                   Average                    Average
                                              Exercise                  Exercise                   Exercise
                                   Shares       Price         Shares      Price        Shares        Price
                                   ------   -----------       ------    ---------      ------      ---------

<S>                                 <C>        <C>             <C>       <C>            <C>         <C>
Outstanding at beginning
   of year                          1,674      $12.72          1,711     $13.21         1,484       $12.96
Granted                             1,013       16.82            519       9.50           610        14.06
Exercised                            (295)      11.27           (255)      6.69          (124)        7.34
Forfeited                             (65)      14.88           (301)     14.71          (259)       16.62
                                   ------                     ------                  -------      
Outstanding at end of year          2,327       14.64          1,674      12.72         1,711        13.21
                                   ======                     ======                  =======

Options exercisable at
   year end                         1,105                        772                      743

Weighted-average fair
   value of options
   granted during
   the year                         $5.96                       $3.27                   $5.78
</TABLE>

                                                          43

<PAGE>


         The following table  summarizes  information  about fixed stock options
outstanding at December 31, 1997:
<TABLE>
<CAPTION>

                                      Options Outstanding                           Options Exercisable
                     ----------------------------------------------------     --------------------------------
                                           Weighted-
                         Number             Average                              Number
       Range         Outstanding at        Remaining         Weighted-        Exercisable at      Weighted-
        of            December 31,      Contractual Life      Average          December 31,        Average
  Exercise Prices         1997             (in years)      Exercise Price         1997          Exercise Price
-----------------    --------------     ----------------   --------------     ---------------   --------------
 <S>                    <C>                  <C>             <C>                   <C>             <C>             
 $ 6.00  to  9.75          443,000            3.0             $ 8.64                  232,000       $ 7.96
  10.63  to 14.13          585,000            2.1              13.58                  427,000        13.55
  16.13  to 17.50          858,000            4.0              16.24                  176,000        16.37
  18.13  to 23.81          441,000            2.9              18.93                  270,000        18.27
                     -------------                                              -------------
 $ 6.00  to 23.81        2,327,000            3.1             $14.64                1,105,000       $13.97
                     -------------                                              -------------
</TABLE>


(8)      MAJOR CUSTOMERS

         In 1997, Sonat Marketing  Company  accounted for  approximately  17% of
revenues,  Engage  Energy  accounted for  approximately  14%, and Duke Power and
Energy accounted for approximately 12%. In 1996, Duke Power and Energy accounted
for approximately 11% of revenues.  In 1995, Amoco Production  Company accounted
for  approximately  10% of revenues.  Management  believes  that the loss of any
individual  purchaser would not have a material  adverse impact on the financial
position or results of operations of the Company.

(9)       EMPLOYEE RETIREMENT PLAN

         The Company has a defined  contribution plan pursuant to Section 401(k)
of the  Internal  Revenue  Code.  Substantially  all  employees  are eligible to
participate after the completion of four months of service and may contribute up
to 15% of their  compensation.  The Board of Directors  elected to contribute an
amount equal to at least 7% of each employee's pretax salary for the years ended
December 31, 1997,  1996 and 1995  resulting in total Company  contributions  of
$766,000, $1.2 million and $1.0 million, respectively.

(10)      GUARANTOR CONDENSED CONSOLIDATING FINANCIAL INFORMATION

         Pursuant to the Notes, all of the Company's  subsidiaries except Patina
and SOCO International (the "Unrestricted  Subsidiaries") would be guarantors of
the Notes  (the  "Restricted  Group").  The  condensed  consolidating  financial
information  below  shows the  impact  of the  guarantors  and the  Unrestricted
Subsidiaries to the Company's consolidated position as of and for the year ended
December 31, 1997. "SOCO" includes all subsidiaries other than SOCO Offshore and
the Unrestricted  Subsidiaries.  In the aggregate,  the subsidiaries  other than
SOCO Offshore and the Unrestricted  Subsidiaries hold less than 10% of the total
assets and revenues included in SOCO.


                                       44

<PAGE>
<TABLE>



                                   CONDENSED CONSOLIDATING BALANCE SHEETS
                                               December 31, 1997
                                                 (In thousands)
<CAPTION>
                                           Restricted Group
                                      ----------------------------
                                                           SOCO          Unrestricted
                                         SOCO            Offshore        Subsidiaries     Eliminations     Consolidated
                                      -----------      -----------       ------------     ------------     ------------

<S>                                   <C>              <C>               <C>              <C>               <C>        
Current assets                        $    87,843      $    21,671       $     4,361      $   -             $   113,875
Investments                               141,501          -                 143,066         (141,501)          143,066
Oil and gas properties, net               174,160          100,144           -                -                 274,304
Gas facilities and other, net              14,843          -                 -                -                  14,843
                                      -----------      -----------       -----------      -----------       -----------
     Total assets                     $   418,347      $   121,815       $   147,427      $  (141,501)      $   546,088
                                      ===========      ===========       ===========      ===========       ===========

Current liabilities                   $    52,201      $     5,348       $   -            $   -             $    57,549
Senior debt                                     1          -                 -                -                       1
Subordinated notes                        173,635          -                 -                -                 173,635
Deferred taxes payable                    (15,832)         -                  47,481          -                  31,649
Other noncurrent liabilities                7,413           12,085           -                -                  19,498
Total stockholders' equity                200,929          104,382            99,946         (141,501)          263,756
                                      -----------      -----------       -----------      -----------       -----------
     Liabilities and stockholders'
         equity                       $   418,347      $   121,815       $   147,427      $  (141,501)      $   546,088
                                      ===========      ===========       ===========      ===========       ===========
</TABLE>
<TABLE>



                                 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
                                           Year Ended December 31, 1997
                                                  (In thousands)
<CAPTION>
                                                        Restricted Group
                                                   -----------------------------
                                                                        SOCO         Unrestricted
                                                      SOCO            Offshore       Subsidiaries      Consolidated
                                                   -----------      ------------     ------------      ------------

<S>                                                <C>              <C>               <C>              <C>            
Revenues                                           $    90,015      $     59,549      $   106,164      $    255,728
Expenses                                                86,029            44,117           68,142           198,288
                                                   -----------      ------------      -----------      ------------
Income before taxes, minority interest
     and extraordinary item                              3,986            15,432           38,022            57,440
Income taxes                                             5,504           -                 12,352            17,856
Minority interest                                      -                 -                  4,119             4,119
Extraordinary item                                       2,848           -                -                   2,848
                                                   -----------       -----------      -----------       -----------
Net income                                         $    (4,366)      $    15,432      $    21,551       $    32,617
                                                   ===========       ===========      ===========       ===========
</TABLE>




                                                          45

<PAGE>


(11)     COMMITMENTS AND CONTINGENCIES

         The Company  rents  offices at various  locations  under  noncancelable
operating  leases.  Minimum future payments under such leases  approximate  $2.4
million  for 1998,  $2.6  million for 1999 and 2000,  $1.7  million for 2001 and
$153,000 for 2002.

         In September  1996, the Company and other interest owners in a lease in
southern  Texas were sued by the  royalty  owners in Texas state court in Brooks
County, Texas. The Company's working interest in the lease is approximately 20%.
The complaint  alleges,  among other things,  that the defendants have failed to
pay proper royalties under the lease, have unlawfully  comingled production with
production  from  other  leases and have  breached  their  duties to  reasonably
develop the lease.  The  plaintiffs  also claim damages for fraud,  co-mingling,
trespass and similar matters,  and demand actual and punitive damages.  Although
the complaint does not specify the amount of damages  claimed,  plaintiffs  have
submitted  calculations  showing total  damages  against all owners in excess of
$100  million.  The Company and the other  interest  owners have filed an answer
denying  the  claims  and intend to  contest  the suit  vigorously.  The suit is
currently in discovery.

         At this time,  the Company is unable to estimate the range of potential
loss, if any, from the foregoing uncertainty. However, the Company believes that
resolution should not have a material adverse effect on the Company's  financial
position,  although an unfavorable  outcome in any reporting period could have a
material impact on the Company's results of operations for that period.

         The Company and its subsidiaries and affiliates are named defendants in
lawsuits and involved from time to time in governmental proceedings, all arising
in the ordinary  course of business.  Although the outcome of these lawsuits and
proceedings cannot be predicted with certainty, management does not expect these
matters to have a  material  adverse  effect on the  financial  position  of the
Company.

         In April 1995, the Company  settled a lawsuit in Harris  County,  Texas
filed by certain  landowners  relating to certain alleged  problems at a Company
well site. The Company  recorded a charge of $4.4 million during 1995 to reflect
the cost of the  settlement.  A primary  insurer honored its commitments in full
and participated in the settlement. The Company's excess carriers have declined,
to date, to honor  indemnification for the loss. Based on the advice of counsel,
the Company has brought  suit  against the  non-participating  carriers  for the
great majority of the cost of settlement.

         In the second  quarter of 1996,  the Company  received  $1.5 million in
proceeds  related to a judgment  involving a pipeline dispute.

         The Company's  operations  are affected by political  developments  and
federal and state laws and  regulations.  Oil and gas industry  legislation  and
administrative  regulations are periodically changed for a variety of political,
economic and other reasons.  Numerous departments and agencies,  federal, state,
local  and  Indian,  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.

         The financial  statements reflect favorable legal proceedings only upon
receipt of cash,  final  judicial  determination  or  execution  of a settlement
agreement.  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.

(12)  UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

         Independent  petroleum consultants directly evaluated 87%, 99%, and 81%
of proved  reserves at  December  31,  1997,  1996 and 1995,  respectively.  All
reserve  estimates are based on economic and operating  conditions at that time.
Future net cash flows as of each year end were computed by applying then current
prices to estimated future production less estimated future  expenditures (based
on current costs) to be incurred in producing and developing the reserves.

                                       46

<PAGE>

         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 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
below.  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 reserves  included in the tables  below are located  onshore in the
United  States and in the waters of the Gulf of Mexico.  The first set of tables
reflects the Company,  excluding Patina  (including  Wattenberg area reserves of
the Company  prior to  formation  of Patina in May 1996),  and the second set of
tables shows consolidated Company totals.








                                       47

<PAGE>


EXCLUDING PATINA
<TABLE>
<CAPTION>

Quantities of Proved Reserves -                                             Crude Oil     Natural Gas
                                                                            ---------     -----------
                                                                             (MBbl)         (MMcf)

<S>                                                                           <C>            <C>    
Balance, December 31, 1995                                                    16,826         256,861

          Revisions                                                            3,407          42,699
          Extensions, discoveries and additions                                  845          60,479
          Production                                                          (2,196)        (31,893)
          Purchases                                                              891          41,606
          Sales                                                               (1,751)        (60,775)
                                                                           ---------       ---------

Balance, December 31, 1996                                                    18,022         308,977

          Revisions                                                             (266)         (6,649)
          Extensions, discoveries and additions                                1,790         100,874
          Production                                                          (2,049)        (41,377)
          Purchases                                                               11           1,568
          Sales                                                                 (748)           (225)
                                                                           ---------       ---------

Balance, December 31, 1997                                                    16,760         363,168
                                                                           =========       =========
</TABLE>
<TABLE>
<CAPTION>


Proved Developed Reserves -                                                 Crude Oil     Natural Gas
                                                                            ---------     -----------
                                                                             (MBbl)         (MMcf)

<S>                                                                           <C>            <C>    
December 31, 1995                                                             14,682         197,436
                                                                           =========      ==========

December 31, 1996                                                             16,070         200,664
                                                                           =========      ==========

December 31, 1997                                                             16,101         297,490
                                                                           =========      ==========
</TABLE>





                                                           48

<PAGE>


EXCLUDING PATINA
<TABLE>
<CAPTION>

Standardized Measure -                                                  December 31,
                                                              --------------------------------
                                                                  1997                1996
                                                              ------------        ------------
                                                                       (In thousands)

<S>                                                           <C>                 <C>         
Future cash inflows                                           $  1,016,597        $  1,476,338

Future costs:
          Production                                              (339,147)           (442,798)
          Development                                              (64,237)            (72,761)
                                                              ------------        ------------

Future net cash flows                                              613,213             960,779

Undiscounted income taxes                                         (148,049)           (246,113)
                                                              ------------        ------------

After tax net cash flows                                           465,164             714,666

10% discount factor                                               (173,346)           (276,010)
                                                              ------------        ------------

Standardized measure                                          $    291,818        $    438,656
                                                              ============        ============
</TABLE>

<TABLE>
<CAPTION>


Changes in Standardized Measure -
                                                                   Year Ended December 31,
                                                               -------------------------------
                                                                   1997               1996
                                                               -----------        ------------
                                                                       (In thousands)

<S>                                                            <C>                <C>         
Standardized measure, beginning of year                        $   438,656        $    203,590

Revisions:
         Prices and costs                                         (284,824)            176,801
         Quantities                                                  2,676              10,414
         Development costs                                          (9,241)             (2,003)
         Accretion of discount                                      43,866              18,426
         Income taxes                                               70,050            (112,924)
         Production rates and other                                (31,871)             14,758
                                                               -----------        ------------

         Net revisions                                            (209,344)            105,472

Extensions, discoveries and additions                              142,209             108,006
Production                                                        (104,465)            (78,591)
Future development costs incurred                                   21,250              10,494
Purchases                                                            2,374             136,227
Sales                                                                1,138             (46,542)
                                                               -----------        ------------

Standardized measure, end of year                              $   291,818        $    438,656
                                                               ===========        ============
</TABLE>


                                                           49

<PAGE>
<TABLE>



CONSOLIDATED
<CAPTION>

Quantities of Proved Reserves -                                                Crude Oil       Natural Gas
                                                                               ---------       -----------
                                                                                (MBbl)           (MMcf)

<S>                                                                               <C>              <C>    
Balance, December 31, 1994                                                        34,977           511,251

          Revisions                                                               (3,633)          (89,455)
          Extensions, discoveries and additions                                      782            32,835
          Production                                                              (4,278)          (53,227)
          Purchases                                                                2,002            13,449
          Sales                                                                   (5,603)          (19,135)
                                                                             -----------       -----------

Balance, December 31, 1995                                                        24,247           395,718

          Revisions                                                                4,127            41,385
          Extensions, discoveries and additions                                    1,039            61,821
          Production                                                              (3,884)          (55,840)
          Purchases                                                               16,725           225,335
          Sales                                                                   (1,757)          (62,783)
                                                                             -----------       -----------

Balance, December 31, 1996                                                        40,497           605,636

          Revisions                                                               (3,829)          (34,334)
          Extensions, discoveries and additions                                    1,790           100,874
          Production                                                              (3,490)          (61,638)
          Purchases                                                                   11             1,568
          Sales                                                                  (18,219)         (248,938)
                                                                             -----------       -----------

Balance, December 31, 1997                                                        16,760           363,168
                                                                             ===========       ===========
</TABLE>

         The  quantities of proved reserves above at December  31, 1996  include
5.8 MBbl and 77.1 MMcf related to the minority interest owners  of Patina  which
was sold in October 1997.

<TABLE>
<CAPTION>

Proved Developed Reserves -                                                    Crude Oil       Natural Gas
                                                                               ---------       -----------

                                                                                (MBbl)           (MMcf)

<S>                                                                              <C>               <C>    
December 31, 1994                                                                 26,104           353,930
                                                                             ===========       ===========

December 31, 1995                                                                 21,637           330,524
                                                                             ===========       ===========

December 31, 1996                                                                 31,869           443,441
                                                                             ===========       ===========

December 31, 1997                                                                 16,101           297,490
                                                                             ===========       ===========
</TABLE>


                                                           50

<PAGE>

<TABLE>
CONSOLIDATED
<CAPTION>

Standardized Measure -                                                          December 31,
                                                                       ------------------------------
                                                                           1997              1996
                                                                       -------------    -------------
                                                                               (In thousands)

<S>                                                                    <C>              <C>         
Future cash inflows                                                    $  1,016,597     $  3,144,813

Future costs:
          Production                                                       (339,147)        (781,550)
          Development                                                       (64,237)        (233,617)
                                                                       ------------     ------------

Future net cash flows                                                       613,213        2,129,646

Undiscounted income taxes                                                  (148,049)        (540,520)
                                                                       ------------     ------------

After tax net cash flows                                                    465,164        1,589,126

10% discount factor                                                        (173,346)        (650,534)
                                                                       ------------     ------------

Standardized measure                                                   $    291,818     $    938,592
                                                                       ============     ============
</TABLE>

          The table above includes standardized measure attributable to minority
interests of $129.5 million at December 31, 1996.

<TABLE>

Changes in Standardized Measure -
<CAPTION>
                                                                            Year Ended December 31,
                                                               -------------------------------------------------
                                                                  1997              1996                1995
                                                               ------------       -----------        -----------
                                                                                (In thousands)

<S>                                                            <C>                <C>                <C>        
Standardized measure, beginning of year                        $   938,592        $   331,106        $   361,682

Revisions:
         Prices and costs                                         (609,467)           528,525             18,975
         Quantities                                                  2,676             10,915            (30,495)
         Development costs                                          (9,241)           (13,027)            (2,806)
         Accretion of discount                                      81,361  (a)        46,045  (b)        36,168
         Income taxes                                              230,075           (242,536)            16,249
         Production rates and other                                (31,871)            11,052            (29,991)
                                                               -----------        -----------        -----------

         Net revisions                                            (336,467)           340,974              8,100

Extensions, discoveries and additions                              142,209            111,797             18,171
Production                                                        (164,330)          (146,257)           (96,232)
Future development costs incurred                                   21,250             18,400             43,551
Purchases                                                            2,374            330,225  (b)        31,142
Sales                                                             (311,810) (a)       (47,653)           (35,308)
                                                               -----------        -----------        -----------

Standardized measure, end of year                              $   291,818        $   938,592        $   331,106
                                                               ===========        ===========        ===========
<FN>
(a)      In 1997,  $12.5  million in "Accretion of Discount" was included in "Sales" due to the sale of Patina
         in October 1997.

(b)      In 1996,  $12.9 million in  "Purchases"  were included in "Accretion of
         Discount"  due to the  significance  of the  accretion  related  to the
         reserves purchased in the acquisition of GOG.
</FN>
</TABLE>


                                                          51
<PAGE>


                                                         PART IV


ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.


      (a)      1.  Reference is made to Item 8 on page 27.


               2.  Schedules  otherwise  required by Item 8 have been omitted as
                   not required or not applicable.

               3.  Exhibits.

      3.1      -   Certificate  of  Incorporation  of Registrant -- incorporated
                   by   reference  from   Exhibit  3.1   to   the   Registrant's
                   Registration Statement on Form S-4(Registration No.33-33455).

      3.1.1    -   Certificate of Amendment to  Certificate  of Incorporation of
                   Registrant filed February 9, 1990 --incorporated by reference
                   from Exhibit 3.1.1 to the Registrant's Registration Statement
                   on Form S-4 (Registration No. 33-33455).

      3.1.2    -   Certificate  of  Amendment to Certificate of Incorporation of
                   Registrant filed May 22, 1991 --  incorporated  by  reference
                   from Exhibit 3.1.2 to the Registrant's Registration Statement
                   on Form S-1 (Registration No. 33-43106).

      3.1.3    -   Certificate  of  Amendment to Certificate of Incorporation of
                   Registrant  filed May 24, 1993 --  incorporated  by reference
                   from Exhibit 3.1.5 to the  Registrant's  Quarterly  Report on
                   Form  10-Q for the  quarter-ended  June 30,  1993  (File  No.
                   1-10509).

      3.2      -   By-laws of the Registrant, as amended.*

      4.1      -   Indenture   dated  as of June 10, 1997 between the Registrant
                   and Texas  Commerce  Bank  National  Association  relating to
                   Registrant's  8 3/4%  Senior  Subordinated  Notes due 2007 --
                   incorporated   by   reference   from   Exhibit   4.1  to  the
                   Registrant's  Current  Report on Form 8-K dated June 10, 1997
                   (File No. 1-10509).

      4.1.1    -   First  Supplemental  Indenture  dated  as of June 10, 1997 to
                   Exhibit 4.1.5 --  incorporated  by reference from Exhibit 4.2
                   to the Registrant's Current Report on Form 8-K dated June 10,
                   1997 (File No. 1-10509).

      4.1.2    -   Second  Supplemental  Indenture  dated as of June 10, 1997 to
                   Exhibit 4.1.5 --  incorporated  by reference from Exhibit 4.3
                   to the Registrant's Current Report on Form 8-K dated June 10,
                   1997 (File No. 1-10509).

      4.2      -   Rights   Agreement,  dated  as of May 27,  1997,  between the
                   Company and  ChaseMellon  Shareholder  Services,  L.L.C.,  as
                   Rights  Agent,  specifying  the  terms of the  Rights,  which
                   includes the form of  Certificate  of  Designation  of Junior
                   Participating  Preferred  Stock as  Exhibit A and the form of
                   Right  Certificate as Exhibit B --  incorporated by reference
                   from Exhibit 1 to the Registrant's Current Report on Form 8-K
                   dated June 2, 1997 (File No. 1-10509).

      4.3      -   Form of Certificate  of  Designation of Junior  Participating
                   Preferred  Stock  setting  forth  the  terms  of  the  Junior
                   Participating  Preferred  Stock,  par value $.01 per share --
                   incorporated  by reference from Exhibit A to Exhibit 1 to the
                   Registrant's  Current  Report on Form 8-K dated  June 2, 1997
                   (File No.1-10509).

                                       52


<PAGE>

      10.1     -   Snyder  Oil   Corporation   1990   Stock   Option   Plan  for
                   Non-Employee  Directors --  incorporated  by  reference  from
                   Exhibit 10.4 to the  Registrant's  Registration  Statement on
                   Form S-4 (Registration No. 33-33455).

      10.1.1   -   Amendment  dated  May 20, 1992 to the Registrant's 1990 Stock
                   Plan for  Non-Employee Directors -- incorporated by reference
                   from Exhibit 10.1.1 to the  Registrant's  Quarterly Report on
                   Form  10-Q for the  quarter-ended  June 30,  1993  (File  No.
                   1-10509).

      10.2     -   Registrant's Amended and Restated 1989 Stock Option Plan.*

      10.3     -   Registrant's Deferred Compensation Plan for Select Employees,
                   adopted  effective June 1, 1994, as amended.*

      10.4     -   Registrant's  Profit   Sharing  &  Savings  Plan and Trust as
                   amended and restated effective October 1, 1993 --incorporated
                   by reference from Exhibit 10.12 to the Registrant's Quarterly
                   Report on Form 10-Q for the quarter-ended  September 30, 1993
                   (File No. 1-10509).

      10.5     -   Form of Indemnification Agreement --incorporated by reference
                   from Exhibit 10.15 to the Registrant's Registration Statement
                   on Form S-4 (Registration No. 33-33455).

      10.6     -   Form of Change in Control Protection Agreement --incorporated
                   by reference  from   Exhibit  10.11   to   the   Registrant's
                   Registration Statement on Form S-1(Registration No.33-43106).

      10.7     -   Long-term   Retention   and   Incentive  Plan  and  Agreement
                   between the Registrant and Charles A. Brown --incorporated by
                   reference from Exhibit 10.1.2 to the  Registrant's  Quarterly
                   Report on Form 10-Q for the quarter-ended June 30, 1993 (File
                   No. 1-10509).

      10.8     -   Agreement  dated  as of April 30, 1993 between the Registrant
                   and Edward T. Story --incorporated  by reference from Exhibit
                   10.8 to the  Registrant's  Annual Report on Form 10-K for the
                   year ended December 31, 1993 (File No. 1-10509).

      10.9     -   Formation  and  Capitalization Agreement dated as of December
                   30, 1996 among  Registrant,  SOCO  International,  Inc., SOCO
                   International Holdings, Inc., SOCO International  Operations,
                   Inc. and Edward T. Story. --  incorporated  by reference from
                   Exhibit 10.9 to the  Registrant's  Annual Report on Form 10-K
                   for the year ended December 31, 1996 (File No. 1-10509).

      10.9.1   -   Promissory  Note  dated   December  30,  1996 from  Edward T.
                   Story  payable to the order of SOCO  International  Holdings,
                   Inc. --  incorporated by reference from Exhibit 10.9.1 to the
                   Registrant's  Annual  Report on Form 10-K for the year  ended
                   December 31, 1996 (File No. 1-10509).

      10.9.2   -   Promissory  Note  dated   December  30,  1996  from Edward T.
                   Story payable to the order of SOCO International  Operations,
                   Inc. -- incorporated  by reference from Exhibit 10.9.2 to the
                   Registrant's  Annual  Report on Form 10-K for the year  ended
                   December 31, 1996 (File No. 1-10509).

      10.9.3   -   Exchange   Agreement   dated   July  10,  1997   between SOCO
                   International, Inc. and Edward T. Story, Jr. *

      10.10    -   Amended  and  Restated Stock Repurchase Agreement dated as of
                   July 31, 1997 and amended and  restated as of  September  18,
                   1997 among the Registrant and Patina Oil & Gas Corporation --
                   incorporated by reference to Exhibit 10.12 to Amendment No. 2
                   to the Registration Statement on Form S-3 of Patina Oil & Gas
                   Corporation (Commission File No. 333-32671).

      10.11    -   Fifth  Restated   Credit  Agreement dated as of June 30, 1994
                   among  the   Registrant   and  the  banks  party   thereto --
                   incorporated   by  reference   from  Exhibit   10.11  to  the
                   Registrant's   Quarterly   Report   on  Form   10-Q  for  the
                   quarter-ended June 30, 1994 (File No. 1-10509).

                                       53


<PAGE>

      10.11.1  -   First  Amendment   dated  as of May 1, 1995 to Fifth Restated
                   Credit  Agreement -- incorporated  by reference  from Exhibit
                   10.11.1 to Registrant's Quarterly Report on Form 10-Q for the
                   quarter-ended June 30, 1995 (File No. 1-10509).

      10.11.2  -   Second  Amendment  dated  as  of  June  30,  1995   to  Fifth
                   Restated  Credit Agreement -- incorporated  by reference from
                   Exhibit 10.12.2 to Registrant's Quarterly Report on Form 10-Q
                   for the quarter-ended June 30, 1995 (File No. 1-10509).

      10.11.3  -   Third  Amendment  dated  as  of   November  1,  1995 to Fifth
                   Restated  Credit Agreement -- incorporated  by reference from
                   Exhibit 10.11.3 to Registrant's Annual Report on Form 10-K of
                   the year ended December 31, 1995 (File No. 1-10509).

      10.11.4  -   Fourth  Amendment   dated   as  of  April  4,  1996 to  Fifth
                   Restated  Credit Agreement --  incorporated  by  reference to
                   Registrant's   Quarterly   Report   on  Form   10-Q  for  the
                   quarter-ended March 31, 1996 (File No. 1-10509).

      10.11.5  -   Fifth  Amendment  dated  as  of   November  1,  1996 to Fifth
                   Restated  Credit Agreement -- incorporated  by reference from
                   Exhibit  10.11.5 to the  Registrant's  Annual  Report on Form
                   10-K for the year ended December 31, 1996 (File No. 1-10509).

      10.11.6  -   Sixth Amendment dated  as  of  May 19, 1997 to Fifth Restated
                   Credit  Agreement -- incorporated  by reference  from Exhibit
                   10.11.6 to the Registrant's Quarterly Report on Form 10-Q for
                   the quarter ended June 30, 1997 (File No. 1-10509).

      10.11.7  -   Seventh  Amendment  dated  as  of  October 13, 1997  to Fifth
                   Restated Credit Agreement. *

      10.12    -   Directors  Deferral  Plan  for  Independent  Directors of the
                   Registrant. *

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

      10.14    -   Employment  Agreement  effective  as  of  May 2, 1997 between
                   Snyder Oil Corporation and William G. Hargett -- incorporated
                   by  reference  from  Exhibit  1 to the  Registrant's  Current
                   Report on Form 8-K dated April 24, 1997 (File No. 1-10509).

      10.15    -   Indemnification  Agreement  dated  as  of May 2, 1997 between
                   Snyder Oil Corporation and William G. Hargett -- incorporated
                   by  reference  from  Exhibit  2 to the  Registrant's  Current
                   Report on Form 8-K dated April 24, 1997 (File No. 1-10509).

      10.16    -   Severance  Agreement  dated  as  of  April 17,  1997  between
                   Snyder Oil  Corporation and Thomas J. Edelman -- incorporated
                   by  reference  from  Exhibit  3 to the  Registrant's  Current
                   Report on Form 8-K dated April 24, 1997 (File No. 1-10509).

      10.17    -   Advisory  Agreement  entered into effective as of May 1, 1997
                   between  Snyder  Oil  Corporation  and  Thomas J.  Edelman --
                   incorporated by reference from Exhibit 4 to the  Registrant's
                   Current  Report on Form 8-K dated  April 24,  1997  (File No.
                   1-10509).

      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.*

      22.1     -   Subsidiaries of the Registrant.*

                                       54


<PAGE>

      23.1     -   Consent of Arthur Andersen LLP.*

      23.2     -   Consent of Netherland, Sewell & Associates, Inc.*

      27       -   Financial Data Schedule.*

      99.1     -   Reserve  letter from  Netherland,  Sewell & Associates,  Inc.
                   dated February 5, 1998 to the Snyder Oil Corporation interest
                   as of December 31, 1997.*

      (b)      The  following  report  on  Form 8-K was filed during the quarter
               ended December 31, 1997:

               October 22, 1997 - Item 2. Acquisition or Disposition of  Assets;
               Item 5.  Other Events; Item 7.


      * Filed herewith.





                                       55

<PAGE>


                                    SIGNATURE


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




/s/ John C. Snyder      Director and Chairman of the Board     February 27, 1998
----------------------  (Principal Executive Officer)
John C. Snyder                

/s/ William G. Hargett  Director, President and Chief          February 27, 1998
----------------------  Operating Officer
William G. Hargett                         


/s/ Roger W. Brittain   Director                               February 27, 1998
----------------------                                                      
Roger W. Brittain


/s/ John A. Hill        Director                               February 27, 1998
----------------------                                                        
John A. Hill


/s/ William J. Johnson  Director                               February 27, 1998
----------------------                                                        
William J. Johnson


/s/ B. J. Kellenberger  Director                               February 27, 1998
----------------------
B. J. Kellenberger


/s/ Harold R.Logan, Jr. Director                               February 27, 1998
----------------------                                                        
Harold R. Logan, Jr.


/s/ James E. McCormick  Director                               February 27, 1998
----------------------                                                         
James E. McCormick


/s/ Edward T.  Story    Director                               February 27, 1998
----------------------                                                       
Edward T.  Story

/s/ Mark A. Jackson     Senior Vice President and Chief        February 27, 1998
----------------------  Financial Officer (Principal Financial
Mark A. Jackson         and Accounting Officer)
                  

                                          

                                       56