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                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

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


                                    Form 10-K
(Mark one)
 [X]

                  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 1996

                                       OR
 [ ]              TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
              FOR THE TRANSACTION PERIOD FROM ________ TO ________

                         COMMISSION FILE NUMBER 1-10509

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


                             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
$6.00 CONVERTIBLE EXCHANGEABLE PREFERRED STOCK       NEW YORK STOCK EXCHANGE
     7% CONVERTIBLE SUBORDINATED NOTES               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 March 10, 1997................................$482,325,221
 Number of shares of common stock outstanding as of March 10, 1997....31,268,557

                       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,
1997.

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<PAGE>

                             SNYDER OIL CORPORATION

                           ANNUAL REPORT ON FORM 10-K
                                DECEMBER 31, 1996

                                     PART I

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

GENERAL

         Snyder Oil Corporation  (the "Company") is engaged in the  development,
acquisition  and  exploration of oil and gas  properties  primarily in the Rocky
Mountain region of the United States and the Gulf of Mexico. The Company is also
engaged  in  international   exploration  and  production,   primarily   through
affiliates. During 1996, consolidated revenues were $292.4 million and cash flow
provided by operations  approximated  $101.7 million.  At December 31, 1996, the
Company's net proved  reserves  totaled 141.4 million  barrels of oil equivalent
("BOE"),  having a pretax present value at 10% based on constant prices ("Pretax
PW 10% Value") of $1.2  billion.  Approximately  71% of the reserves are natural
gas.

         During 1996, the Company completed the  repositioning  begun in 1995 in
response to dramatic  deterioration  of Rocky  Mountain gas markets.  During the
year,  the  Company  has  concentrated  investment  in its  growing  core areas,
primarily  in  the  Gulf  of  Mexico,  added  industry  partners  in  major  gas
development  projects in the Rockies,  disposed of nearly all remaining non-core
properties  and  consolidated  its Wattenberg  properties  with those of another
major producer in the area to create Patina Oil & Gas Corporation ("Patina"),  a
separately-managed  New  York  Stock  Exchange  listed  company.  The  Company's
investment  in Patina  should  allow the  Company to benefit  from  efficiencies
arising out of the combination of the two largest producers in this field, while
affording  the Company a range of financial  options in the future.  The Company
also  made   significant   progress  in   strengthening   its  organization  and
administrative  systems to ensure that it can deal with its expected growth in a
more efficient and timely manner.

         As  a  result,  the  Company's  domestic   operations,   excluding  its
investment  in  Patina,  are  focused  on three  areas,  all of  which  have the
potential to contribute significantly to future growth. These areas include:

o        The Gulf of Mexico,  where 1997 efforts will be concentrated on further
         development in the Main Pass area, including construction of facilities
         for a major  discovery and  exploring  the potential of other  operated
         fields through drilling based on 3-D seismic.

o        The Rocky  Mountain  region in Wyoming,  Colorado  and Utah,  where the
         Company  expects to expand  development of its three major gas projects
         in  the  Washakie,   Deep  Green  River  and  Piceance  Basins,   begin
         exploratory drilling on two potentially significant gas projects in the
         Wind  River  and Big Horn  Basins  and  further  test  the  development
         potential of its oil projects in the Uinta Basin.

o        North  Louisiana,  where the 3-D seismic program to survey a portion of
         the  Company's  position of  approximately  600,000 gross acres will be
         expanded.  The Company expects to commence exploratory drilling in late
         1997.

         The  Company  expects  to  increase  its  development  and  exploratory
expenditures  to  $112  million  for  1997,  up  from  $51  million,   excluding
acquisitions, during 1996. Approximately $85 million is expected to be spent for
development drilling programs, $19 million for expanded exploratory activity and
$8 million  for gas  facilities  and other  activities.  In total,  the  Company
expects to drill 124 wells domestically, up from 85 wells in 1996. Approximately
$48 million is targeted for  continued  development  in the Gulf of Mexico,  $38
million for expanded  development of its major Rocky Mountain  projects,  and $2
million for additional leasing and seismic costs in North Louisiana.

         Internationally,  the Company  tendered its interest in its  Australian
affiliate for 16.2 million shares (approximately 9.6% of the outstanding shares)
of Cairn Energy plc ("Cairn"), realizing a  pretax  gain  of  $65.5 million  and

                                        1

<PAGE>


retaining a significant investment in a company positioned to become a major gas
provider to the developing Indian Subcontinent.  In Mongolia, where an affiliate
holds over 10 million acres, two wells were drilled,  one of which resulted in a
second  discovery.  Ten wells were drilled in Russia,  resulting in that venture
increasing  production to over 3,500 barrels per day. Near year end, the Company
entered into an agreement with an  international  oil company that will fund the
initial well on a prospective  block  offshore  Thailand,  while  permitting the
Company  to  retain  a  significant  interest  in  the  block.  As the  pace  of
international  activity is  accelerating,  the Company is pursuing  plans for an
offering  of  its  primary  operating   international   subsidiary  on  a  major
international  stock  exchange to enhance the value of these  investments to the
Company's   shareholders  by   establishing  an  independent   valuation  in  an
appropriate market.

DOMESTIC OPERATIONS

         GENERAL.  During  1996 the  Company  greatly  increased  the  focus and
balance of its domestic  operations by investing  capital  primarily in its core
operating areas and selling its remaining non-core assets. In Wattenberg,  which
represents over 50% of the Company's  consolidated  reserves, the Company formed
Patina to combine  the  Company's  properties  with  those of Gerrity  Oil & Gas
Corporation.  Patina is a separately  managed,  New York Stock  Exchange  traded
company that is 74% owned by the Company.  Nearly all non-core  properties  were
sold by the end of the year, with the Company's  remaining  domestic  properties
now concentrated in three operating divisions:

o        The  Offshore   Division  holds  interests  in  producing   fields  and
         prospective  blocks in the Gulf of Mexico. As the result of three major
         acquisitions  and a significant  discovery near year end, this Division
         increased its proved  reserves to 17.4 million BOE at year end (up from
         3.6 million  BOE at year end 1995),  representing  12% of  consolidated
         year end reserves.

o        The Rocky Mountain  Division,  which consists of two operating  groups.
         The Major Gas Properties  Group  includes  three major gas  development
         programs,   one  mature  gas  field  and  two  potentially   large  gas
         development  projects  on which  initial  drilling is expected to begin
         this year. The Rockies  Group's  properties  include two large,  mature
         non-operated oil fields in northern Wyoming and a potentially large oil
         development  project in the Uinta Basin.  This  Division's  properties,
         located in Wyoming,  western  Colorado and Utah, had proved reserves of
         50.3  million  BOE at year end  (essentially  unchanged  from  year end
         1995), representing 36% of consolidated year end reserves.

o        The Southern Division, whose most significant remaining holding is over
         300,000 gross mineral acres,  with leases and lease options covering an
         equivalent  position,  in North  Louisiana.  A number of prospects have
         been  identified  through  2-D seismic and as a result of a 3-D seismic
         program  during  1996,  and it is likely that at least one well will be
         commenced by the end of 1997. The majority of the producing  properties
         of the Southern Division,  including its properties in the Austin Chalk
         Trend in Texas, were sold during 1996.

Summary  information at December 31, 1996 regarding the Company's major domestic
projects is set forth in the following table.


                                        2

<PAGE>

<TABLE>
<CAPTION>

                                                          PROVED RESERVE QUANTITIES
                                          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 Division
   Main Pass Area              15        8,553          1,570          86,238       15,943     $  236,349        19%
   Other                       26            0            851           3,717        1,470          8,488         1

Major Gas Properties
   Washakie (WY)              154       75,726          1,144         133,101       23,327        147,880        12
   Piceance (CO)               70       44,355            118          32,170        5,479         39,045         3
   Deep Green River (WY)       10       43,309            175          21,717        3,794         27,973         2
   Wind River Basin (WY)       27       65,577            235          21,151        3,760         15,376         1
   Big Horn Basin (WY)          0       80,550              0               0            0              0         0

Rockies Properties
   Northern Wyoming (WY)      932          787         12,083             531       12,172         76,938         6
   Uinta Basin (UT)           127       79,899          1,152           3,861        1,795          9,042         1

Southern Division
   North Louisiana (LA)        96 (a)  318,090 (b)         40           2,715          492          6,615         1
                            -----      -------         ------         -------      -------     ----------       ----

    Total Major Projects    1,457      716,846         17,368         305,201       68,232        567,706        46
Other                         117       78,587            654           3,776        1,286         10,501         1
                            -----      -------         ------         -------      -------     ----------       ----
    Total SOCO              1,574      795,433         18,022         308,977       69,518        578,207        47
Patina (CO)                 3,602 (c)  141,713         22,475         296,659       71,918        648,797        53
                            -----      -------         ------         -------      -------     ----------       ----
    Company consolidated    5,176      937,146         40,497         605,636      141,436     $1,227,004       100%
                            =====      =======         ======         =======      =======     ==========       ====

<FN>
(a)   Includes royalty interests in 82 wells.
(b)   Does not include 225,000 net acres under option.
(c)   Includes royalty interests in 195 wells.
</FN>
</TABLE>

                                  SOCO OFFSHORE

         During 1996,  the Company  acquired  the  remaining  stock  interest in
DelMar  Petroleum,  Inc.,  now  named  SOCO  Offshore,  Inc.  With  three  large
acquisitions  of interests in its major  properties and a major  discovery,  the
Company has accomplished its goal of creating a significant presence in the Gulf
of Mexico.  The  Offshore  Division  contributes  a  significant  portion of the
Company's  reserves and production,  with the potential to rapidly  increase its
contribution  in the  future  as the major  discovery  comes on  production  and
pipeline  constraints are eliminated.  The Company believes that many properties
in the Gulf of Mexico have, and will continue to be,  under-exploited  and that,
while offshore  operations  have greater risks than the Company's Rocky Mountain
operations,  the  potential  benefits  and  exposure to Gulf Coast  markets will
compliment  the Company's  Rocky  Mountain  activities and result in significant
benefits to the Company.

          By year end, the Offshore  Division had proved reserves of 2.4 million
barrels of oil and 90 Bcf of gas (17.4 million BOE), up from 748,000  barrels of
oil and 16.3 Bcf (3.5 million BOE) at year end 1995.  Acquisitions accounted for
7.8 million BOE of this increase,  and the discovery of the Ingrid Field in Main
Pass Block 261 accounted for 6.3 million BOE. At year end the Offshore  Division
had  interests in 41 (15.2 net) wells,  35 (14.1 net) of which were  operated by
the Company, and held interests in 103,000 (43,600 net) acres. December 1996 net
production  averaged  7,250 BOE per day,  up from 1,100 BOE per day in  December
1995. As the result of an acquisition at the end of the year, the Division's net
daily production has reached 10,000 BOE per day.

         During 1997,  the Gulf of Mexico will  continue to be a major focus for
the  Company.  Capital  expenditures  are  expected to total $45 to $50 million,
including  $20.7  million to install  platforms  and  related  facilities,  $8.9

                                        3
<PAGE>

million  to drill  three  development  wells and $16.2  million  to drill  eight
exploratory wells, primarily on existing projects. In addition, the Company will
continue  its  acquisition  efforts  in  the  area,  including  acquisitions  of
additional  interest in its existing  properties,  and will continue to evaluate
its existing properties for additional development or exploratory potential.

         The largest project, comprising the Pabst and Busch Fields in Main Pass
Blocks 255 and 259, is in the Main Pass/Viosca Knoll area offshore  Mississippi.
The Offshore  Division owns interests in 10 lease blocks in the project area and
operates two platforms there. During 1996,  additional interests in these Fields
were  acquired  from three joint  venture  partners,  increasing  the  Company's
ownership  from 12% to 60%. Four wells were  successfully  completed,  and three
successful  workovers  were  completed.  One dry hole was drilled.  By year end,
SOCO's  proved  reserves  in these  Fields  totaled  52.1 Bcf of gas and 932,000
barrels of oil (9.6 million  BOE),  representing  55% of SOCO  Offshore's  total
proved  reserves.  In 1997, the Offshore  Division will continue to evaluate 3-D
seismic data to evaluate these blocks for additional  exploratory or development
potential, with plans to commence two development wells during the year.

         During the year,  the  Offshore  Division  successfully  generated  and
drilled two exploratory  wells,  resulting in the discovery of the Ingrid Field,
on farm-in  acreage  in Main Pass  Block  261,  just west of the Pabst and Busch
Fields.  Initial proved  reserves  assigned to the Company's 50% interest in the
Field were 34.1 Bcf of gas and 638,000  barrels of oil (6.3 million BOE) at year
end.  During  1997,  the  Company  will begin  installation  of a  platform  and
production facilities,  with production initially expected to total 100 MMcf per
day (37 MMcf per day net to the  Company's  interest)  and to  commence in early
1998.  Full  development  of the Field,  including  four  productive  reservoirs
already discovered,  as well as additional prospects,  is expected to require at
least four additional  wells. Two additional  exploratory  wells are expected to
commence during 1997.

         Limited  pipeline  capacity  has  constrained  production  in the  Main
Pass/Viosca Knoll area. The Pabst and Busch Fields are capable of producing over
160 MMcf per day, but are currently producing approximately 100 MMcf per day due
to pipeline  constraints.  The Company is negotiating with several  pipelines to
alleviate  these  constraints  and to provide  additional  capacity to transport
production from the Ingrid Field.  Based on the proposals  received,  management
expects  to  be  able  to  secure   arrangements  that  will  increase  capacity
sufficiently to transport its production by late 1997 or early 1998.

         The Offshore  Division  also has  interests in several  other  operated
field areas in the Gulf of Mexico,  with the Company's  interest often exceeding
40%.  During  1997,  the Company  will  continue to  evaluate  these  blocks for
additional  development or  exploratory  potential  using recently  acquired 3-D
seismic  data.  Up to four  exploratory  wells  could be drilled in 1997 to test
these prospects,  including one well that commenced drilling in February at High
Island 208 offshore Texas.  The Company also signed a farm-in  agreement in late
1996 that will  allow the  Company to acquire a 50%  interest  in two  suspended
wells and a significant  exploratory prospect in South Timbalier 231. A platform
will be  installed  during  the year to produce  the  suspended  wells,  and the
initial exploratory well should commence in early 1998.



                               MAJOR GAS PROJECTS

         During 1996, the Company,  while maintaining a modest drilling schedule
in view of low prices  prevailing  during the first ten months of the year, made
significant  strides in positioning its Rocky Mountain  properties for long term
growth.  Significant  interests were sold to industry  partners in two major gas
projects.  The sales will allow expanded  development of these  Company-operated
projects,  while limiting the Company's capital  requirements.  In January 1997,
the Company sold a one-half interest in two additional  potentially  large-scale
gas projects on which initial  drilling is scheduled for 1997.  The Company also
entered into an alliance with  subsidiaries of Coastal  Corporation  ("Coastal")
whereby  the  Company's  gas  production  throughout  most of the region will be
pooled  with that of other  producers  and  marketed  by Coastal  Gas  Marketing
Company ("CGM") affording greater efficiency and the opportunity to share in the
value associated with downstream  sales of gas. As part of the venture,  most of
the Company's gas facilities  were placed under common  management with those of
Coastal Field Services Company through the formation

                                        4

<PAGE>


of Great Divide Gas Services,  LLC ("Great  Divide"),  allowing  more  efficient
management and greater direction of future expansion.

         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 1996, the Company  continued to develop  Mesaverde  sands in the Washakie
Basin near its  existing  properties.  Twelve wells were put on sales in 1996 at
depths ranging from 8,000 to 11,500 feet,  developing net proved reserves of 1.4
million BOE.  Three wells were in progress at year end. Net  production  of gas,
which accounts for approximately  95% of the reserves,  during the year averaged
25.5 MMcf per day, as compared to average 1995  production of 22.9 MMcf per day.
Proved  reserves at year end totaled 1.1 million barrels of oil and 133.1 Bcf of
gas, or 23.3  million  BOE,  as compared to 1.1 million  barrels and 105 Bcf, or
18.6  million  BOE, at the end of 1995.  This  increase in reserves is primarily
attributable  to  increased  gas prices at year end 1996 and  extensions  of the
field. The Company expects to accelerate its activity in this area in 1997, with
plans to drill 25 wells at costs ranging from $500,000 to $600,000 per well.

           The  Company  currently  operates  128  wells in this  area and holds
hundreds of potential drilling locations,  66 of which were classified as proved
undeveloped  at year end 1996.  The Company  holds  interests  in  approximately
97,000 gross (76,000 net) undeveloped acres in the Washakie Basin.

         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 eight wells during 1996, with two wells in progress at
year end.  Despite the sale of a 50% interest in the project to Amoco Production
Company in the  middle of the year,  year end proved  reserves  totaled  175,000
barrels of oil and 21.7 Bcf of gas, or 3.8  million  BOE, as compared to 107,000
barrels of oil and 15.9 Bcf of gas, or 2.8 million  BOE, at year end 1995.  This
increase in reserves is primarily  attributable  to  extensions of the field and
increased gas prices at year end 1996. With 10 wells,  six of which are operated
by the Company,  on sales at year end, net  production  averaged 832 BOE per day
during 1996. The Company holds interests in  approximately  95,000 gross (43,000
net) undeveloped acres in this project.  At the end of 1996, proved  undeveloped
reserves were assigned to 17 locations. During 1996, the Company participated in
a 51 square mile 3-D seismic  survey that should  allow  high-grading  of future
drilling  locations.  The Company  expects to  participate  in drilling up to 21
wells in 1997. Further expansion of drilling in this area is awaiting regulatory
approval  after  preparation  of an  environmental  impact  statement,  which is
expected to be approved  by  mid-1997.  Assuming  the  approval is granted,  the
Company  expects to  participate in drilling 25 to 30 wells per year after 1997.
The primary  objective  of drilling is the stacked,  fluvial  sands of the Lance
formation.

         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. During the year, a 45% interest in this
project  was  sold  to  Destec  Energy  Inc.  At year  end,  the  Company  owned
approximately  99,000 gross (44,000 net) undeveloped  acres in this area. During
1996, the Company  participated in 21 new wells to develop and further delineate
the fields.  Twenty-two wells (including two in progress at the beginning of the
year) were put on sales,  and one was in  progress at year end.  Net  production
averaged  9.7 MMcf per day in 1996,  down from 1995 average  production  of 11.9
MMcf per day as a result of the sale of a 45% interest in the  project.  At year
end  1996,  there  were 70  producing  wells,  55 of which are  operated  by the
Company. Proved reserves at year end were 32.2 Bcf of gas and 118,000 barrels of
oil, or 5.5 million BOE, as compared with 42.6 Bcf and 145,300  barrels,  or 7.2
million BOE, at year end 1995.  The decrease in reserves is primarily the result
of the sale to Destec, partially offset by extensions of the field and increased
gas prices at year end 1996.  Proved  undeveloped  reserves  were assigned to 37
locations at year end 1996.

         During 1997, the Company plans to drill 23 wells to further develop the
Company's  acreage  positions and evaluate the fields.  An expanded  development
effort might be warranted if additional transportation  arrangements can be made
and gas prices stabilize at acceptable levels. The primary objective of drilling
is the stacked,  fluvial sands of the Mesaverde  formation at depths of 4,500 to
8,500 feet.


                                        5

<PAGE>


         WIND RIVER AND BIG HORN BASINS. The Riverton Dome Field, located in the
Wind River  Basin,  produces  gas  primarily  from the Frontier and Dakota tight
sands at depths of 8,000 to 10,000  feet,  with some sour  crude oil  production
from the Tensleep and Phosphoria formations.  At year end 1996, proved reserves,
nearly all gas,  totaled 3.8 million BOE.  The Company  operates 27 wells having
net production of approximately 1,000 BOE per day. Production from this field is
processed at a Company-owned plant.

         The Company has assembled approximately 65,000 (63,000 net) undeveloped
acres in an area east of the Riverton Dome Field.  In addition,  the Company has
obtained an option  agreement to exploit oil and gas resources on  approximately
33,000 net acres on  Shoshone/Arapaho  tribal lands toward the east and north of
the Riverton Dome Field.  In January 1997,  the Company sold a 50% interest in a
portion of this project,  which targets  various  Cretaceous  sands at depths of
8,500 to 12,500 feet, to Belco Oil & Gas. The Company expects to drill two wells
during 1997, with the first well expected to commence in the second quarter.

         In the Big Horn Basin,  northwest of the Worland Field, the Company has
assembled approximately 120,000 gross (81,000 net) undeveloped acres. Belco also
agreed to participate in this project,  which also targets  Cretaceous  sands at
depths of 9,500 to 12,000 feet. The first well was commenced in January 1997.

         GREAT DIVIDE. The Company owns over 225 miles of pipeline systems which
transport gas from the Company's  properties in the Washakie  Basin and Piceance
Basin. Effective January 1, 1997 the Company and Coastal Field Services Company,
a  subsidiary  of Coastal,  formed  Great  Divide to combine the  operations  of
approximately 200 miles of pipelines owned by the Company with over 400 miles of
Coastal  systems in the Uinta,  Washakie and Wind River  Basins.  Great  Divide,
which  is 27%  owned  by the  Company  and will be  jointly  managed  by its two
shareholders,  has combined  assets of more than 600 miles of  nonjurisdictional
pipelines, connecting 650 natural gas wells producing approximately 165 MMcf per
day. Great Divide will oversee the future expansion of gas pipelines and related
facilities within six areas of mutual interest in Wyoming, Colorado and Utah.

         Also effective  January 1, 1997,  the Company  entered into a gas sales
agreement and gas marketing  agreement with CGM, another  subsidiary of Coastal,
to pool the  Company's  and and  other  producers'  gas  supplies  in the  Rocky
Mountain region. The initial supply pool is expected to exceed 100 MMcf per day,
with over half the supply provided by the Company. The Company will sell its gas
to CGM based on agreed  market index prices and will share in the margin  earned
by CGM on downstream  sales of the gas, based in part on the portion of the pool
represented  by Company gas. CGM and the Company will also evaluate  commitments
for firm  transportation  or longer term contracts,  with commitments  requiring
joint agreement.

         The Company  expects  the joint  venture to result in  efficiencies  in
operating and managing their pipeline  facilities,  as well as creating  greater
focus for future  expansion in the region.  In addition,  the Company hopes that
the pooling of gas supplies and the expertise of Coastal, one of North America's
largest   gas   marketers,   will   result  in  greater   downstream   marketing
opportunities.  Both the  Company and Coastal  intend to  encourage  other Rocky
Mountain  producers to join the joint venture,  which would further increase the
venture's potential to become a significant developer of facilities and marketer
in the Rocky Mountain region.


                             OTHER ROCKIES PROJECTS

         UINTA  BASIN.  In the Uinta  Basin,  the  Company  holds  interests  in
approximately  115,000  gross  (80,000  net)  acres.  During  1996,  the Company
participated in drilling only one non-operated well in the Basin as efforts were
focused on acquiring and analyzing 3-D seismic data and  implementing  two pilot
waterflood  projects in its Green River oil projects.  A pilot waterflood in the
Leland Bench Field was commenced during the third quarter, with initial response
expected to occur early in the second half of 1997.  Depending on the  response,
development should begin in the second half of 1997. A second pilot project,  in
the Horseshoe Bend Field, is awaiting regulatory approval and should commence in
mid-1997.  The ultimate  success of these  projects  will be  influenced  by the
response of the pilot  projects and the ability to select  locations and enhance
waterflood efforts through the use of 3-D seismic data. The  projects  are  also

                                        6

<PAGE>


sensitive to oil prices. During the last half of 1996, oil prices, which had had
historically been at a premium to West Texas Intermediate  prices,  deteriorated
and now trade at a  significant  discount  to such  prices.  As a  result,  1997
activities have been reduced, with plans to drill only five wells during 1997.

         During 1996, net production  from the Basin averaged 290 barrels of oil
and approximately 1,255 Mcf of gas per day, as compared to 325 barrels and 1,377
Mcf per day during 1995. At year end, the Company had interests in 127 producing
wells,  76 of which were  operated by the Company.  Proved  reserves at year end
were 1.2  million  barrels of oil and 3.9 Bcf of gas,  or 1.8  million  BOE,  as
compared to 1.6 million  barrels and 3.8 Bcf, or 2.2 million  BOE, at the end of
1995.  The decreases are primarily the result of production and sales during the
year, as there was no significant  development activity.  Gas reserves increased
primarily as the result of revisions  resulting from higher prices prevailing at
year end.

         NORTHERN WYOMING. The Company holds significant interests in two large,
mature oil fields in Northern Wyoming,  the Hamilton Dome and Salt Creek Fields.
In late 1996,  the Company  unitized the Hamilton  Dome Field to achieve  common
ownership of all producing horizons across the Field. Unitization resulted in an
immediate net  production  increase to the Company of 140 barrels of oil per day
and is expected to allow the current operator to decrease operating costs due to
efficiencies  and to proceed with an expansion  of the existing  waterflood  and
accelerate  recompletions.  At year end, proved reserves at these Fields totaled
12.2 million BOE,  including 12.1 million barrels of oil and 531 MMcf of gas, up
from 10.9  million BOE (10.8  million  barrels and 455 MMcf) at the end of 1995.
This  increase was the result of upward  revisions,  primarily  caused by higher
product prices as well as increases  resulting from the  unitization of Hamilton
Dome. 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.


                                 NORTH LOUISIANA

         The Company  owns over 300,000  gross  mineral  acres,  with leases and
lease option agreements covering an equivalent position,  in north Louisiana and
also owns overriding  royalty interests in approximately 95 producing wells. The
Company  also has access to a database  of more than 5,000  miles of 2-D seismic
data and in 1996 joined with two  partners to shoot a 48 square mile 3-D seismic
survey  covering a portion of its  acreage.  The results of this  survey,  which
targeted  potential  significant reef structures in the Cotton Valley formation,
were  encouraging,  and the partners have  commenced a 110 square mile survey to
the west of the  previous  survey.  The Company has  identified a number of reef
prospects  that will be imaged by the survey,  which should be completed  during
the second half of 1997. These surveys are being shot at no cost to the Company,
which will  retain a 25% to 50%  interest  in the  prospect  areas.  One well is
expected to be commenced by the end of 1997.

PATINA OIL & GAS CORPORATION

         During 1996 the Company implemented a significant  restructuring of its
Wattenberg  Field assets by creating  Patina.  The Company formed Patina to hold
its  properties in the  Wattenberg  Field and to facilitate  the  acquisition of
Gerrity Oil & Gas Corporation.  In May 1996, the consolidation was completed. At
year end, the Company owned 14 million,  or 74%, of Patina's common shares.  The
Company has thus  transformed its working interest in the Field to a controlling
interest in the largest producer in the Field. At December 31, 1996, Patina held
interests  in over  3,600  wells in  Wattenberg  with  net  proved  reserves  of
approximately 71.9 million BOE,  approximately 70% of which were attributable to
natural gas.  Based on unescalated  year end oil and gas prices,  these reserves
had a pretax PW 10% Value of $648.8 million.

         The Wattenberg Field is located  approximately 35 miles north of Denver
in the Denver-Julesburg Basin. One of the most attractive features of Wattenberg
is that there are several productive  formations.  Three of the formations,  the
Codell,  Niobrara  and  J-Sand,  are  "blanket"  zones in the  area of  Patina's
Wattenberg holdings,  while others, such as the D-Sand, Dakota and the shallower
Shannon and Sussex, are more localized. Drilling in Wattenberg is low risk

                                        7

<PAGE>


from the  perspective of encountering  hydrocarbons  with better than 95% of the
wells drilled being completed as producers.  Consequently,  the Field's economic
attractiveness   is  primarily   dependent  on  energy  prices,   the  reservoir
characteristics  of the  specific  area  of the  Field  being  drilled  and  the
operator's ability to minimize capital and operating costs.

         Over the past five years, Patina and its predecessors have drilled over
1,500 wells in Wattenberg.  Given Patina's experience in drilling and completing
wells of this type,  combined with an operating base encompassing  approximately
3,200  active  wells,  Patina  believes it can drill and operate its oil and gas
properties  in the  Field at a lower  cost  than its  competitors.  Furthermore,
because virtually all of the wells in which it holds an interest lie within a 40
mile  radius,  Patina  believes it has the  potential  to become one of the most
efficient oil and gas producers in the United States.

         As of December 31, 1996,  Patina had 728 proved  undeveloped  locations
and 605 proved  behind pipe  recompletion  opportunities.  While this  inventory
provides  the  ability to expand  development  activities  should  drilling  and
completion technologies improve or the recent recovery in Rocky Mountain natural
gas prices  continues,  a  significant  portion of Patina's  proved  undeveloped
locations  are  projected  to  provide  rates of return  below the level  judged
attractive by its  management  based on projected  commodity  prices and reserve
recoveries.

         During  1996,  Patina  focused  on  combining  the  operations  of  its
predecessors,  reducing costs and  identifying  attractive  projects for further
development.  Only $8.5  million  was  spent on  development  and  acquisitions,
allowing Patina to use the bulk of its cash flow to reduce senior debt (to $94.5
million  at year  end as  compared  to  $116.3  million  at June 30,  1996)  and
repurchase  securities.  In 1997,  Patina, at least for the present,  expects to
limit its capital  expenditures  on existing  properties  to  approximately  $14
million. As a result, management believes funds generated from operations should
permit a  continued  paydown of debt,  additional  security  repurchases  or the
pursuit of further consolidation or acquisition opportunities.

         As with all its investments and properties,  the Company  evaluates its
position in Patina from time to time and assesses alternatives to increase value
to the Company and its shareholders.  A number of alternatives concerning Patina
are available to the Company, including maintaining its investment,  selling all
or part of its investment, either in one transaction or gradually,  distributing
all or part of its  investment  to its  shareholders  or acquiring all of, or an
increased interest in, Patina. Any decision, when made, will be made in light of
strategic, financial and other factors deemed appropriate by management.


INTERNATIONAL ACTIVITIES

         The Company's strategy  internationally has been to develop a portfolio
of  projects  that  have  the  potential  to  make a major  contribution  to its
production  and reserves  while  limiting its financial  exposure and mitigating
political risk by seeking  industry  partners and investors to fund the majority
of  the  required  capital.  A  wholly-owned  subsidiary  of the  Company,  SOCO
International,  Inc.  ("SOCO  International"),  is the  holding  company for all
international  operations.  SOCO  International,   in  turn,  owns  90%  of  two
subsidiaries, SOCO International Holdings, Inc. ("Holdings"),  which owns shares
of  Cairn,  as  discussed  below,  and  SOCO  International   Operations,   Inc.
("Operations"),  which holds all other  international  investments.  In December
1996, Edward T. Story, the President of SOCO  International and a Vice President
and director of the Company,  exercised an option to acquire the  remaining  10%
interest in these companies.

         As the pace of international  activity is accelerating,  the Company is
pursuing  plans for an offering of  Operations  on a major  international  stock
exchange.  The  offering  is  intended  to  enhance  the  value  of  Operations'
international   projects  to  the  Company's  shareholders  by  establishing  an
independent  valuation in an appropriate market. If the necessary agreements can
be concluded, the offering could occur as early as the second quarter of 1997.

         CAIRN.   In  the  fourth  quarter  of  1996,  Cairn,  a  Scotland-based
exploration and production company traded on the London  Stock  Exchange, agreed
to acquire Command Petroleum Limited, an Australian company that was 32.6%

                                        8

<PAGE>


owned by SOCO  International,  in exchange  for Cairn stock.  As a result,  SOCO
International  tendered its shares in Command for 16.2  million  shares of Cairn
(approximately 9.6% of the outstanding shares), realizing a pretax gain of $65.5
million. Cairn holds oil and gas interests in several countries,  with a primary
focus in the Bay of Bengal offshore  Bangladesh,  where it recently  announced a
major  gas  discovery.  Cairn's  position  offshore  Bangladesh,  where  it  has
identified additional prospects with significant exploratory potential, together
with Command's interest in the Ravva Field offshore India, poise Cairn to make a
major contribution to the development of oil and gas resources in the developing
Indian  Subcontinent.  Although  the  potential  of  Cairn's  major  exploratory
prospects,  and thus the ultimate  value of the  Company's  investment in Cairn,
remains  unknown,  Cairn's  prospects have been well received,  resulting in the
value of the  Company's  investment  increasing  from $95  million  to over $130
million in February 1997.  During  February and March 1997, the Company sold 4.5
million  shares  of Cairn at an  average  price of $8.81  per  share,  realizing
proceeds of $39.2 million,  which was applied to repay SOCO International's debt
to the Company.  The remaining 11.7 million shares had a market value  exceeding
$100  million  on March 6,  1997.  The  Company  presently  intends  to remain a
significant  shareholder  in  Cairn,  although  it may  elect to  liquidate  its
holdings as Cairn's future potential is realized and market conditions warrant.

         RUSSIA.  Permtex is a joint  drilling  venture  formed in 1993  between
Permneft,  a Russian oil and gas  company,  and SOCO Perm  Russia,  Inc.  ("SOCO
Perm"),  a subsidiary  of SOCO  International.  The joint  venture was formed to
develop proven oil fields located in the Volga-Urals Basin of the Perm Region of
Russia,  approximately  800 miles east of Moscow.  Permtex holds exploration and
development  rights to over 300,000 acres in the Volga-Urals Basin in a contract
area  containing  four major and four minor fields,  as well as other  potential
prospects.  The Company  estimates that the four major fields  contained  proved
reserves of  approximately  52 million  barrels of oil at year end (8.6  million
barrels net to the Company), with significant additional reserves expected to be
ultimately  recovered if waterflood projects are successfully  implemented.  The
joint venture  utilizes  primarily  Russian  personnel and equipment and Western
technology under joint Russian/American management.

         The major fields were  delineated  prior to the  formation of the joint
venture through 45 previously drilled wells.  Twenty-one wells (10 of which were
drilled in 1996) have been placed on  production,  and are  currently  producing
from 3,500 to 4,000  barrels  per day,  up from a peak of 2,500 in 1995.  During
1996, the joint venture produced  approximately 776,000 barrels of oil, with all
production  (other than oil in  transit)  being  exported  and sold on the world
market.  Drilling  activity has been slower than anticipated due to difficulties
in securing drilling  contracts on commercially  reasonable terms.  During 1997,
the Company expects to drill 11 wells using Russian rigs.

         The Company has  continued to fund its share of capital  costs  through
sales of equity in SOCO Perm. In 1996, the Company  concluded the sale of 15% of
SOCO Perm's equity for $10 million.  This sale decreased the Company's  interest
in SOCO Perm to  approximately  35%.  This sale  required  SOCO Perm to list its
common shares on a securities  exchange no later than 1998 or the investors have
the right to require the Company to purchase  their  shares at a formula  price.
The  proposed  offering  of  Operations'  shares is  expected  to  satisfy  this
requirement.  The commitment from the Overseas Private  Investment  Company,  an
agency  of the  United  States  Government,  to  provide  up to $40  million  in
financing has been extended to mid-1997.


         MONGOLIA.  SOCO Tamtsag Mongolia,  Inc. ("SOCO  Tamtsag"),  a 42% owned
affiliate of SOCO International, holds over 10 million acres covering the entire
Tamtsag Basin of northeastern  Mongolia.  These  concessions are located between
the Hailar and Erlian  Basins of China.  The  Company  has also  acquired  2,700
kilometers of seismic data in the Basin. During 1996, two exploratory wells were
drilled and a second  discovery  was logged.  Although  production  from the two
discovery  wells is not expected to be  significant,  SOCO Tamtsag's  activities
established  the existence of productive  sands across broad areas of the Basin.
SOCO Tamtsag intends to drill four wells during 1997, including the SOTAMO 21-2,
which began drilling in January.

         Although the prospective potential of the previously unexplored Tamtsag
Basin  has long  been  recognized,  the lack of an  outlet  for  production  has
prevented  exploration  there.  In early  1995,  SOCO  Tamtsag  entered  into an
agreement with China National United Oil Corporation ("CNUOC") under which CNUOC
agreed to  purchase  crude oil  produced  by the  venture  at a  mutually-agreed
Mongolian/Chinese  border  point  at  world  market  prices, less $2 per barrel.

                                       9
<PAGE>

CNUOC is a joint  venture  between  China  National  Petroleum  Corporation  and
SINOCHEM,  both state-owned  entities.  In early 1997, SOCO Tamtsag exported its
first shipment of oil to China, successfully testing the marketing arrangements.

         THAILAND.  In 1995, SOCO International  acquired the 150,000 acre Block
B4/32 concession in the Gulf of Thailand.  During 1996, SOCO  International  was
awarded Block B8/38. In late 1996, SOCO International  reached an agreement with
a  Malaysian-based  international oil company which will fund the drilling of an
exploration well on Block B8/38. SOCO International will retain a 42.5% interest
in Blocks B8/38 and B4/32.  The initial well is scheduled to begin in the second
quarter of 1997,  and a second  well on Block B8/38 may be drilled by the end of
the year.

         VIETNAM.  In late  1994,  SOCO  International  signed a  Memorandum  of
Understanding  with  Petrovietnam  Exploration and Production  regarding a joint
exploration and development  program on a certain  concession  offshore Vietnam.
Since  that  time,   negotiations  regarding  a  joint  venture  structure  have
progressed  considerably  and have resulted in a formal bid being  submitted for
the  offshore  concession.  The  Company  expects  a  decision  on the  award in
mid-1997.

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,  1996.  Proved
reserves  of 8.6 million  BOE with a PW 10% value of $25.8  million  assigned to
SOCO International projects in Russia are not included in the table.
<TABLE>
<CAPTION>
                                                                               DECEMBER 31,
                                                               ------------------------------------------
                                                                 1994               1995           1996
                                                               --------           --------       --------
          <S>                                                    <C>               <C>            <C>  
          Crude oil and liquids (MBbl)
             Developed                                           26,104            21,637         31,869
             Undeveloped                                          8,873             2,610          8,628
                                                                -------           -------         ------
                Total                                            34,977            24,247         40,497
                                                                =======           =======         ======
          Natural gas (MMcf)
             Developed                                          353,930           330,524        443,441
             Undeveloped                                        157,321            65,194        162,195
                                                                -------          --------        -------
                Total                                           511,251           395,718        605,636
                                                                =======          ========        =======
          Total MBOE                                            120,186            90,200        141,436
                                                                =======          ========        =======
</TABLE>

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

<TABLE>
<CAPTION>
                                                               DECEMBER 31, 1996
                                           --------------------------------------------------------
          (In thousands)                    DEVELOPED            UNDEVELOPED(a)            TOTAL
                                           ----------            --------------          ----------
          <S>                              <C>                    <C>                    <C>       
          1997                             $  248,683             $ (20,275)             $  228,408
          1998                                207,527                31,034                 238,561
          1999                                164,789                38,767                 203,556
          Remainder                         1,049,753               409,368               1,459,121
                                           ----------              ---------             ----------
          Total                            $1,670,752              $458,894              $2,129,646
                                           ==========              =========             ==========
          Pretax PW 10% Value (b)          $1,023,125              $203,879              $1,227,004
                                           ==========              =========             ==========
<FN>
(a)  Net of estimated capital costs,  including estimated costs of $34.1 million
     during 1997.
(b)  The after tax PW 10% value of proved  reserves  totaled  $938.6  million at
     year end 1996.
</FN>
</TABLE>
                                       10

<PAGE>

         The  quantities  and values shown in the preceding  tables are based on
prices in effect at December  31, 1996,  averaging  $24.47 per barrel of oil and
$3.59 per Mcf of gas. Year end gas prices, although typically higher than prices
prevailing  through most of a calendar year,  were at or near all time highs and
significantly higher than prices prevailing  throughout most of 1996. Prices for
both  oil and gas have  fallen  since  year  end,  partially  as the  result  of
decreased demand associated with warm weather. 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 in
prices of oil or gas  could  have a  material  adverse  effect on the  Company's
financial condition and results of operations.

         Proved  developed  reserves are proved reserves that are expected to be
recovered  from existing  wells with existing  equipment and operating  methods.
Proved  undeveloped  reserves  are  proved  reserves  that  are  expected  to be
recovered  from new wells drilled to known  reservoirs on undrilled  acreage for
which the existence and  recoverability  of such reserves can be estimated  with
reasonable   certainty,   or  from  existing  wells  where  a  relatively  major
expenditure is required to establish production.

         Future prices received 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.

         The present  values shown should not be construed as the current market
value of the reserves.  The 10% discount factor used to calculate present value,
which is specified by the Securities  and Exchange  Commission  ("SEC"),  is not
necessarily  the most  appropriate  discount rate, and present value,  no matter
what discount rate is used, is materially  affected by  assumptions as to timing
of future production,  which may prove to be inaccurate. For properties operated
by the Company,  expenses  exclude the Company's share of overhead  charges.  In
addition,  the  calculation of estimated  future net revenues does not take into
account the effect of various  cash  outlays,  including,  among  other  things,
general and administrative costs and interest expense.

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

         Netherland, Sewell & Associates, Inc. ("NSAI") and Ryder Scott Company 
Petroleum Engineers ("Ryder Scott"), independent petroleum consultants, prepared
estimates of the Company's  proved reserves which  collectivelyrepresent  99% of
Pretax PW 10% Value as of December 31,  1996.  Approximately  85% was  estimated
independently  by NSAI and 14% by Ryder Scott.  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.

                                       11
<PAGE>

PRODUCTION, REVENUE AND PRICE HISTORY

         The following table sets forth information  regarding net production of
crude oil and 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, 1996.
<TABLE>
<CAPTION>

                                            1992            1993              1994           1995            1996
                                         ----------      ----------        ----------     ----------       ---------
                                         (Dollars in thousands, except prices and per barrel equivalent information)
<S>                                        <C>             <C>               <C>            <C>            <C>
Production
    Oil (MBbl)                                1,776           3,451             4,366          4,278          3,884

    Gas (MMcf)                               23,090          35,080            43,809         53,227         55,840
    MBOE (a)                                  5,989           9,297            11,668         13,149         13,191

Revenues
    Oil                                    $ 33,512        $ 53,174          $ 64,625       $ 72,550       $ 79,201
    Gas (b)                                  43,851          71,467            73,233         72,058        110,126
                                           --------        --------          --------       --------       --------
        Subtotal                             77,363         124,641           137,858        144,608        189,327
    Transportation, processing
        and marketing                        38,611          94,839           107,247         38,256         17,655
    Other                                     2,996           9,372            17,223         19,296         85,432
                                           --------        --------          --------       --------       --------
        Total                              $118,970        $228,852          $262,328       $202,160       $292,414
                                           --------        --------          --------       --------       --------

Operating expenses
    Production                             $ 28,057        $ 41,401          $ 46,267       $ 52,486       $ 49,638
    Transportation, processing
        and marketing                        30,469          85,640            94,177         29,374         15,020
    Exploration                               1,515           2,960             6,505          8,033          4,232
                                           --------        --------          --------       --------       --------
                                           $ 60,041        $130,001          $146,949       $ 89,893       $ 68,890
                                           --------        --------          --------       --------       --------

Direct operating margin                    $ 58,929        $ 98,851          $115,379       $112,267       $223,524
                                           ========        ========          ========       ========       ========

Production data
    Average sales price (c)
        Oil (Bbl)                          $  18.87        $  15.41          $  14.80       $  16.96        $ 20.39
        Gas (Mcf) (a) (b)                      1.74            1.94              1.67           1.35           1.97
        BOE (a)                               12.92           13.41             11.82          11.00          14.35
    Average production expense/BOE         $   4.68        $   4.45          $   3.97       $   3.99        $  3.76
    Average production margin/BOE          $   8.24        $   8.96          $   7.85       $   7.01        $ 10.59
<FN>
(a)  Gas  production  is converted to oil  equivalents  at the rate of 6 Mcf per
     barrel.  Prior to 1993 certain high-priced gas was converted based on price
     equivalency.  Average gas prices  exclude this high priced gas  production.
(b)  Sales of natural gas liquids are included in gas revenues.
(c)  The Company  estimates  that its composite net wellhead  prices at December
     31, 1996 were  approximately  $3.59 per Mcf of gas and $24.47 per barrel of
     oil.
</FN>
</TABLE>

                                       12
<PAGE>

PRODUCING WELLS

     The  following  table sets forth certain  information  at December 31, 1996
relating to the producing  wells in which the Company owned a working  interest.
The Company  also held  royalty  interests  in 277  producing  wells.  Wells are
classified as oil or gas wells according to their predominant production stream.

<TABLE>
<CAPTION>
                                                                                              AVERAGE
                PRINCIPLE                        GROSS                    NET                 WORKING
             PRODUCT STREAM                      WELLS                   WELLS               INTEREST
         ----------------------                  -----                   -----               --------
<S>                                              <C>                     <C>                    <C>
         Crude oil and liquids                   4,132                   2,924                  71%
         Natural gas                             1,044                     721                  69%
                                                 -----                  ------                  ---
               Total                             5,176                   3,645                  70%
                                                 =====                   =====                  ===
</TABLE>

ACREAGE

         The following table sets forth certain information at December 31, 1996
relating to acreage  held by the  Company.  Undeveloped  acreage is acreage held
under  lease,  permit,  contract or option  that is not in a spacing  unit for a
producing  well,  including  leasehold  interests  identified for development or
exploratory drilling.

<TABLE>
<CAPTION>
                                                               GROSS                      NET
                                                             ----------                ----------
         <S>                                                 <C>                       <C>  
         Domestic
           Developed (a)                                        359,000                   236,000
           Undeveloped (b)                                    1,322,000                   937,000
                                                              ---------                 ---------
               Total                                          1,681,000                 1,173,000
                                                              =========                 =========
         International
           Undeveloped
             Russia                                             306,000                    53,000
             Mongolia                                        10,796,000                 4,534,000
             Thailand                                         2,520,000                 1,071,000
                                                             ----------                 ---------
                Total                                        13,622,000                 5,658,000
                                                             ==========                 =========
<FN>
(a)  Developed  acreage is acreage  assigned to producing wells.
(b)  The Company also held 225,000 net  undeveloped acres  under option in North
     Louisiana.
</FN>
</TABLE>

                                       13


<PAGE>

DRILLING RESULTS

      The following table sets forth  information with respect to domestic 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>

                                                           1994             1995              1996
                                                          ------           ------            -----
                  <S>                                     <C>              <C>               <C>
                  Development wells
                    Productive
                       Gross                              466.0            223.0             69.0
                       Net                                390.6            133.1             38.9
                    Dry
                       Gross                               12.0              5.0              2.0
                       Net                                 11.1              3.8               .5

                  Exploratory wells
                    Productive
                       Gross                                  -                -              3.0
                       Net                                    -                -               .5
                    Dry
                       Gross                               13.0                -              2.0
                       Net                                 10.5                -              1.6
</TABLE>

         On December 31, 1996,  the Company had 17 gross (13.1 net)  development
wells and 2 gross (1.0 net) exploratory wells in progress.  Between year end and
February 28, 1997,  the Company  spudded 19 wells.  At that date, 18 gross (14.7
net) wells, including wells in progress at year end, had been completed,  and 14
gross (9.8 net) development wells were in progress.

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 1994 and 1995, Amoco Production  Company  accounted for
approximately 11% and 10% of revenues,  respectively. In 1996, Pan Energy, which
purchases  a  significant  portion of Patina's  gas  production,  accounted  for
approximately  11% 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 effort is currently  exclusively focused on
the sale of  production  from its  properties.  Third  party gas  marketing  was
discontinued  in 1994.  During 1996,  the volume of the Company's gas production
marketed  by the  Company  averaged  approximately  136  MMcf  per  day.  Market
conditions  in 1995 and early  1996  highlighted  the need to create  new market
outlets for Rocky  Mountain  gas. As part of a program to diversify  the markets
for its gas production,  the Company has pursued  transactions  that effectively
transfer the price that it receives  for a portion of its Rocky  Mountain gas to
the Gulf Coast market.  See Note 2 to the Consolidated  Financial  Statements of
the Company. As of year end 1996, 61% of the Company's production was sold under
arrangements  that are responsive to Rocky Mountain market  conditions,  and 39%
was  sold in the Gulf  Coast  market.  As  described  on page 6 under  "Domestic
Operations - Major Gas  Properties - Great Divide,"  effective  January 1, 1997,
the Company's Rocky Mountain gas production  (excluding Patina's  production) is
being  pooled  with that of other  producers  and  marketed by a  subsidiary  of
Coastal. By pooling gas supplies and using Coastal's expertise,  this venture is
expected to increase  opportunities  for  downstream  marketing of the Company's
Rocky Mountain gas.

                                       14


<PAGE>

COMPETITION

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

         Competitors in acquisitions,  exploration,  development,  marketing and
production  include the major oil companies in addition to numerous  independent
oil companies,  individual  proprietors,  drilling and acquisition  programs and
others.  Many of these  competitors  possess  financial and personnel  resources
substantially in excess of those available to the Company.  Such competitors may
be able to pay more for desirable leases and to evaluate, bid for and purchase a
greater  number of properties  than the financial or personnel  resources of the
Company  permit.  The ability of the Company to increase  reserves in the future
will be  dependent  on its  ability to select  and  acquire  suitable  producing
properties and prospects for future exploration and development.

TITLE TO PROPERTIES

         Title to the  properties  is subject to  royalty,  overriding  royalty,
carried and other similar  interests and contractual  arrangements  customary in
the oil and gas  industry,  to liens  incident to operating  agreements  and for
current taxes not yet due and other comparatively minor encumbrances.

         As is  customary  in the  oil  and  gas  industry,  only a  perfunctory
investigation  as to ownership is conducted at the time  undeveloped  properties
believed to be suitable for drilling are acquired.  Prior to the commencement of
drilling on a tract, a detailed title examination is conducted and curative work
is performed with respect to known significant title defects.

REGULATION

         REGULATION OF DRILLING AND  PRODUCTION.  The Company's  operations  are
affected by political  developments  and 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 SOCO'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.  Colorado, where all Patina's properties and a portion of the Company's
properties are located,  amended its statute  concerning oil and gas development
in  1994 to  provide  the  state's  Oil and  Gas  Conservation  Commission  with
additional  authority  to  regulate  oil and gas  activities  to protect  public
health,  safety and welfare,  as well as the  environment.  Several  rulemakings
pursuant  to  these  statutory  changes  have,  or will  be,  undertaken  by the
Commission to revise the regulation of groundwater  protection,  soil protection
and site reclamation and financial  assurance for industry  obligations in these
areas.  To date,  these rule  changes  have not  adversely  affected oil and gas
operations  of either the Company or Patina,  as the  Commission  is required to
enact cost-effective and technically feasible regulations. However, there can be
no  assurance  that,  in  the  aggregate,  these  regulatory  developments,   or
developments  in other states,  will not increase the cost of conducting oil and
gas operations.

                                       15

<PAGE>

         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.

         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
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 significant
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 wilful  misconduct,  or by the violation of an applicable  federal
safety, construction or operating regulation by the Responsible Party, its agent
or subcontractor.

         In addition,  OPA requires  certain vessels and offshore  facilities to
provide  evidence of financial  responsibility.  During 1996, OPA was amended to
reduce the required level of financial  responsibility  from $150 million to $35
million for offshore  facilities and $10 million for facilities located in state
waters.  OPA also  requires  offshore  facilities to prepare  facility  response
plans, which the Company has done, for responding to a "worst case discharge" of
oil. Failure to comply with these  requirements or failure to cooperate during a
spill event may  subject a  Responsible  Party to civil or criminal  enforcement
actions and penalties.

                                       16

<PAGE>


         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.

OFFICERS

         Listed below are the  officers  and a summary of their recent  business
experience.

 NAME                        POSITION

 John C. Snyder              Chairman and Director
 Charles A. Brown            Senior Vice President-Rocky Mountain Division
 Steven M. Burr              Vice President-Engineering and Planning
 Peter C. Forbes             Vice President-Offshore
 Peter E. Lorenzen           Vice President-General Counsel
 H. Richard Pate             Vice President-Major Gas Projects
 David M. Posner             Vice President-Gas Management
 James H. Shonsey            Vice President-Finance
 Edward T. Story             Vice President-International and Director
 Rodney L. Waller            Vice President-Special Projects
 Richard A. Wollin           Vice President-Southern Division and Acquisitions

         JOHN C. SNYDER (55), a director and  Chairman, 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. Mr.
Snyder was the first president of Canadian-American  Resources Fund, Inc., which
he founded in 1969. From 1964 to 1966, Mr. Snyder was employed by Humble Oil and
Refining Company (currently Exxon Co., USA) as a petroleum engineer.  Mr. Snyder
received  his  Bachelor  of Science  Degree in  Petroleum  Engineering  from the
University of Oklahoma and his Masters  Degree in Business  Administration  from
the Harvard University  Graduate School of Business  Administration.  Mr. Snyder
also serves as a director of Patina.

         CHARLES  A.  BROWN  (50),  Senior  Vice  President  -   Rocky  Mountain
Division,  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.

         STEVEN M. BURR (40), 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.

         PETER  C.  FORBES  (51),  Vice  President  -  Gulf of  Mexico,  who was
appointed  to that  position  in 1996,  joined  the  Company as  Executive  Vice
President of SOCO Offshore,  Inc., the Company's Gulf Coast subsidiary,  in July
1995 and has been President of that company since July 1996.  From 1994 to 1995,
he was President and Chief Executive Officer of SD Resources,  Inc., the general
partner of Sand Dollar  Resources  L.P., a  partnership  with Enron Gas Services
Corp.,  a  subsidiary  of Enron  Corp.  From 1992 to 1993,  Mr.  Forbes was Vice
President  in charge of the oil and gas property  acquisition  unit of Enron Gas
Services  Corp.  From 1988 to 1992,  he was President and a director of American
Exploration Company.  Prior thereto,  Mr. Forbes was Vice President,  Finance of
Browning-Ferris Industries, Inc. during 1988 and Senior Vice President and Chief
Financial Officer of Zapata  Corporation from 1985 to 1987. He served in several
positions, including Vice President and Treasurer, at Texas Eastern Transmission
Corporation  from 1975 to 1985. Mr. Forbes  received his Bachelor of Arts Degree
from Edinburgh University and is a Scottish Chartered Accountant.

                                     17

<PAGE>

         PETER  E.  LORENZEN  (47),   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 (43), Vice President -   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 (43),  Vice President -  Gas Management  Group,  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.

         JAMES H. SHONSEY (45), Vice President -  Finance, joined the Company in
1991.  From 1987 to 1991,  Mr. Shonsey  served in various  capacities  including
Director of Operations  Accounting for Apache Corporation.  From 1976 to 1987 he
held various positions with Deloitte & Touche,  Quantum  Resources  Corporation,
Flare Energy  Corporation and Mizel Petro  Resources,  Inc. Mr. Shonsey received
his  Bachelor of Science  Degree in  Accounting  from Regis  University  and his
Master of Science Degree in Accounting from the University of Denver.

         EDWARD T. STORY (53), a director and Vice President -  International of
the Company and  President of SOCO  International,  Inc.,  joined the Company in
1991. Mr. Story became a director of the Company in February 1996.  From 1990 to
1991, Mr. Story was Chairman of the Board of a  jointly-owned  Thai/US  company,
Thaitex Petroleum Company. Mr. Story was co-founder,  Vice Chairman of the Board
and Chief Financial Officer of Conquest  Exploration  Company from 1981 to 1990.
He served as Vice President, Finance and Chief Financial Officer of Superior Oil
Company from 1979 to 1981.  Mr.  Story held the  positions  of  Exploration  and
Production  Controller and Refining Controller with Exxon USA from 1975 to 1979.
He held various positions in Esso Standard's  international  companies from 1966
to 1975.  Mr. Story  received a Bachelor of Science  Degree in  Accounting  from
Trinity University,  San Antonio, Texas and a Masters of Business Administration
from the University of Texas in Austin.  Mr. Story serves as a director of First
BanksAmerica,   Inc.,  a  bank  holding  company,  Hi/Lo  Automotive,   Inc.,  a
distributor  of  automobile  parts,  Hallwood  Realty  Corporation,  the general
partner of Hallwood  Realty  Partners,  L.P., an American Stock  Exchange-listed
real estate limited  partnership,  and Seaunion Holdings Limited, an oil and gas
company listed on the Hong Kong Stock Exchange.

         RODNEY L. WALLER (47), Vice President -  Special Projects,  joined  the
Company in 1977.  Previously,  Mr. Waller was employed by Arthur  Andersen & Co.
Mr. Waller received his Bachelor of Arts Degree from Harding University.

         RICHARD A. WOLLIN (44),  Vice  President  -   Southern   Division   and
Acquisitions,  joined the Company in 1990.  From 1983 to 1989, Mr. Wollin served
in various management  capacities  including Executive Vice President of Quinoco
Petroleum,  Inc. with primary  responsibility  for acquisition,  divestiture and
corporate  finance  activities.  From 1976 to 1983,  he was  employed in various
capacities for The St. Paul Companies,  Inc., including Senior Vice President of
St. Paul Oil & Gas Corp. Mr. Wollin received his Bachelor of Science Degree from
St. Olaf College and his law degree from the University of Minnesota Law School.
Mr. Wollin is a member of the Minnesota Bar Association.


FORWARD-LOOKING INFORMATION

         Certain  information  included  and  incorporated  by reference in this
Annual Report,  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  Section  27A of  the  Securities  Act  of  1933,  as  amended  (the
"Securities  Act"),  and Section 21E of the Securities  Exchange Act of 1934, as
amended.  Such  forward-looking  statements  may be or may concern,  among other

                                       18

<PAGE>

things, capital expenditures,  drilling activity, acquisitions and dispositions,
and  conditions and  transactions  related  thereto,  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.

         All  forward-looking  information  is based upon  management's  current
plans,  expectations,  estimates and  assumptions  and is subject to a number of
uncertainties  and  risks  that  could   significantly   affect  current  plans,
anticipated  actions,  the timing of such  actions and the  Company's  financial
condition and results of operations. The risks and uncertainties associated with
such forward-looking  statements include generally the volatility of hydrocarbon
prices  and  hydrocarbon-based  financial  derivatives  prices;  basis  risk and
counterparty  credit  risk  in  executing   hydrocarbon  price  risk  management
activities;   economic,   political,   judicial  and  regulatory   developments;
developments in financial markets, both domestic and foreign; competition in the
industry,  as well as competition from other sources of energy; the economics of
producing certain reserves;  hydrocarbon  demand and supply; the ability to find
or acquire and develop reserves of natural gas and crude oil; and the actions of
customers  and  competitors.  As  a  consequence,   actual  results  may  differ
materially  from  expectations,   estimates  or  assumptions  expressed  in  any
forward-looking statements made by or on behalf of the Company.

ITEM 3. LEGAL PROCEEDINGS

         In August  1995,  the  Company was sued in the United  States  District
Court of Colorado by seven  plaintiffs  purporting to represent all persons who,
at any time since January 1, 1960,  have had agreements  providing for royalties
from gas  production  in Colorado  to be paid by the  Company  under a number of
various lease provisions.  In January 1997, the judge ordered that the class not
be certified. All remaining liability under this suit was assumed by Patina upon
its  formation.  In January  1996,  GOG was also sued in a similar but  separate
class action filed in stated court.  In both suits,  the plaintiffs  allege that
unspecified  "post-production"  costs  incurred  prior  to  calculating  royalty
payments were deducted in breach of the relevant lease  provisions and that this
fact was fraudulently  concealed.  The plaintiffs seek unspecified  compensatory
and  punitive  damages  and a  declaratory  judgment  prohibiting  deduction  of
post-production  costs prior to  calculating  royalties  paid to the class.  The
Company believes that  calculations of royalties by it and GOG are and have been
proper under the relevant lease provisions,  and intends to defend these and any
similar suits vigorously.

         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  and have  breached  their  duties  to
reasonably  develop the lease.  The plaintiffs  also claim damages for fraud and
trespass,  and demand actual and punitive  damages.  Although the complaint does
not specify the amount of damages  claimed,  an earlier  letter from  plaintiffs
claimed  damages in excess of $50  million.  The Company and the other  interest
owners  have filed an answer  denying  the claims and intend to contest the suit
vigorously.

         At this time,  the Company is unable to estimate the range of potential
loss, if any, from the foregoing  uncertainties.  However,  the Company believes
their  resolution  should not have a material  adverse effect upon the Company's
financial  position,  although an  unfavorable  outcome in any reporting  period
could have a material  impact on 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 A VOTE OF SECURITY HOLDERS

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

                                       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 trade
under the symbol "SNY".  The following table sets forth,  for 1995 and 1996, the
high and low  sales  prices  for the  Company's  securities  for New York  Stock
Exchange composite transactions, as reported by THE WALL STREET JOURNAL.
<TABLE>
<CAPTION>
                                                    1995                            1996
                                          -----------------------          -----------------------
                                            HIGH            LOW              HIGH            LOW
                                          -------         -------          -------         -------
<S>                                       <C>             <C>              <C>             <C>   
         First Quarter                    $15-1/4         $13-1/2          $12-1/8         $ 7-1/4
         Second Quarter                    15-3/8          11-7/8           10-1/4           7-5/8
         Third Quarter                     14              10-3/4           12               9-3/8
         Fourth Quarter                    12-3/4          10               17-3/4          11-3/4
</TABLE>

         On March 10, 1997,  the closing  price of the common stock was $17-3/8.
Quarterly  dividends  have been paid at the rate of $.065 per share  during 1995
and 1996. For federal income tax purposes,  100% of common dividends paid during
1995 and 1996  were a  non-taxable  return of  capital.  The  Company  currently
expects that  dividend  payments in 1997 will be 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,   dividend  requirements  on  preferred  stock,  capital
expenditures and other factors.  On December 31, 1996, there were  approximately
2,600 holders of record of the common stock and 31.2 million shares outstanding.

                                       20

<PAGE>

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,
1996.  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,
                                                    ------------------------------------------------------------
                                                       1992           1993        1994         1995       1996
                                                    ---------      ---------    ---------   ---------  ---------
<S>                                                 <C>            <C>          <C>         <C>        <C>  
INCOME STATEMENT
       Revenues                                     $ 118,970      $ 228,852    $ 262,328   $ 202,160  $ 292,414
       Income (loss) before extraordinary items        14,597         22,538       12,372     (39,831)    62,950
          Per share                                       .43            .58          .07       (1.53)      1.81
       Net income (loss)                               14,597         19,545       12,372     (39,831)    62,950
          Per share                                       .43            .45          .07       (1.53)      1.81
          Dividends per share                             .25 (a)        .22          .25         .26        .26
       Average shares outstanding                      22,722         23,096       23,704      30,186     31,308

CASH FLOW
       Net cash provided by operations             $   48,339      $  68,728    $  86,397   $  69,121  $ 101,730
       Net cash realized (used) by investing          (73,645)      (207,933)    (245,503)     32,421    (62,356)
       Net cash realized (used) by financing           21,079        129,633      169,926     (96,012)   (38,715)

BALANCE SHEET
       Working capital                             $    7,619      $     491    $     708   $   5,842  $   9,168
       Oil and gas properties, net                    241,804        316,406      472,239     435,217    635,387
       Total assets                                   331,638        453,301      673,259     555,493    879,459
       Senior debt                                     96,568        114,952      234,857     150,001    188,231 (b)
       Subordinated notes                              18,750          -           83,650      84,058    183,842 (c)
       Stockholders' equity                           168,866        274,734      274,086     235,368    294,668
<FN>
(a)  Due to revised timing,  five payments were made at a quarterly rate of $.05
     in 1992.
(b)  Includes  $93.7  million of SOCO  senior  debt and $94.5  million of Patina
     senior debt.
(c)  Includes $80.7 million of SOCO  convertible  subordinated  notes and $103.1
     million of Patina subordinated notes.
</FN>
</TABLE>
         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)                                                   1995
                                                                   ----------------------------------------------
                                                                    FIRST        SECOND      THIRD        FOURTH
                                                                   -------      -------     --------     --------
<S>                                                                <C>          <C>          <C>         <C>    
Revenues                                                           $53,017      $57,142      $50,839     $41,162
Depletion, depreciation and amortization and property impairments   19,986       20,675       22,540      40,589 (a)
Gross profit (deficit)                                               8,901       12,564        1,672     (14,660)
Net income (loss)                                                   (5,981)         525       (9,606)    (24,769)
  Per share                                                           (.25)        (.03)        (.37)       (.88)

(In thousands, except per share data)                                                   1996
                                                                   ----------------------------------------------
                                                                    FIRST        SECOND       THIRD      FOURTH
                                                                   -------      -------      -------    ---------
Revenues                                                           $41,719      $56,768      $62,475    $131,452
Depletion, depreciation and amortization and property impairments   16,771       22,745       24,673      23,111
Gross profit                                                         9,979        2,217       18,746      89,801
Net income (loss)                                                    1,777       (9,983)       5,560      65,596
  Per share                                                            .01         (.37)         .13        2.06

<FN>

(a)   Includes $24.1 million  of property impairments.
</FN>
</TABLE>

                                       21
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS


RESULTS OF OPERATIONS

         COMPARISON OF 1996 RESULTS TO 1995. Total revenues for 1996 were $292.4
million,  a $90.3 million  increase from 1995. The increase is in large part due
to a $67.2 million increase in gains on sales of investments  which is 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 Petroleum  Limited  ("Command"),
an  Australian  affiliate,  for stock in Cairn  Energy plc  ("Cairn"),  a United
Kingdom  based  company.  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
barrel of oil equivalent  ("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 Oil and Gas
Corporation  ("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  remaining  relatively constant from 1995 to 1996 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 which have occurred over the past two years and the reduction
of development drilling.  The Company focused the last two years on divesting of
marginal assets and acquiring  strategic  assets that allow for future growth of
the Company.  This process is  substantially  complete and the Company is now in
position for growth. The Company expects to increase its development schedule in
1997  which,  along  with two  acquisitions  in the Gulf of Mexico in the fourth
quarter  1996,  should result in an increase in  production  during 1997.  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.

         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 the Permtex  venture in Russia and the
Tamtsag  venture in Mongolia.  In January 1997,  the  Company's  interest in the
Tamtsag venture was further reduced.

                                       22
<PAGE>



         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  increased 50% or $2.4 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 acquisition of Gerrity Oil
& Gas Corporation ("GOG").

         Interest and other expense was $28.9 million  compared to $27.0 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.

         COMPARISON OF 1995 RESULTS TO 1994. Total revenues for 1995 were $202.2
million,  a $60.2 million decline from 1994. The revenue  decrease  included $56
million as a result of the  suspension  of low margin third party gas  marketing
activities  late in  1994  and a $13  million  decrease  due to the  sale of the
Company's  Wattenberg gas  facilities in 1995.  Oil and gas sales,  on the other
hand,  rose by 5% to $144.6 million as a result of a 13% growth in production of
barrels of oil equivalent.  The production increase was partially offset by a 7%
decrease in the  average  price  received  per BOE.  Natural gas prices  dropped
sharply by 19% in 1995 to an average of $1.35 per Mcf, the lowest  average price
received in the Company's history. Oil prices improved 15% to average $16.96 per
barrel during 1995.

         The net loss for 1995 was $39.8 million, compared to net income in 1994
of $12.4  million.  The 1995 loss was  primarily due to $27.4 million in noncash
property  impairment  charges  and almost $11 million in losses as a result of a
litigation settlement, losses on marketable securities, as well as severance and
restructuring  costs. The property  impairment  charges resulted from the fourth
quarter adoption of 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".  Prior to the fourth  quarter of 1995,  the Company
provided  impairments for  significant  proved and unproved oil and gas property
groups to the extent that net capitalized costs exceeded the undiscounted future
cash flows.  SFAS 121 requires the Company to assess the need for an  impairment
of capitalized costs of oil and gas properties on a property-by-property  basis.
If an impairment is indicated based on undiscounted  expected future cash flows,
then an impairment is recognized to the extent that net capitalized costs exceed
discounted expected future cash flows. The decline from the 1994 net income also
resulted from the decrease in natural gas prices and sharply increased financing
costs,  incurred prior to the reduction in outstanding debt accomplished  during
the latter half of 1995.

         Revenues from production  operations,  less direct operating  expenses,
for 1995 were $92.1 million, slightly greater than the 1994 net revenue. Average
daily production  during 1995 was 36,024 BOE, up 13% from 1994 levels,  although
the  average  product  price  received  decreased  by 7% to $11.00 per BOE.  The
production  increase  resulted  primarily  from newly  drilled  wells  placed on

                                       23
<PAGE>


production  late in 1994 and during early 1995. In 1995,  the Company placed 223
wells on sales, including 88 in the DJ Basin of Colorado, 24 in the Austin Chalk
area of  Texas,  16 in  the  Green  River  Basin  of  Wyoming  and  six  in  the
Piceance basin of western Colorado. Additionally, late in 1995, the Company sold
its minor  interest in a south Texas field where 70  nonoperated  wells had been
completed  earlier in the year. In the DJ Basin, the Company completed 360 wells
in 1994,  but reduced its drilling in 1995 in response to the dramatic  decrease
in natural gas prices in the region.  The Company  expects to maintain a reduced
development  schedule in 1996.  Total  operating  expenses for 1995 increased by
13%, in line with the  production  growth.  Operating  costs per BOE were $3.99,
essentially even with those of the prior year.

         Revenues  from gas  processing,  transportation,  and  marketing,  less
direct expenses, for 1995 were $8.9 million,  compared to $13.1 million in 1994.
The decrease  resulted  primarily from a reduction in processing  margins due to
the sale of the Company's  Wattenberg  processing  facilities.  During 1995, the
Company  realized almost $80 million in sales proceeds and recorded $8.7 million
in gains. In conjunction with the sales, the Company completed an agreement with
the primary  purchaser,  which, at current gas prices, is not expected to have a
material  adverse  effect on the wellhead net prices  compared to the  Company's
processing  arrangements  prior to the sale.  Gas  transportation  and gathering
margins from facilities  retained by the Company climbed 47% during 1995 to $3.4
million,  associated  with rising  production and system  expansions in southern
Wyoming and western  Colorado.  Gas marketing net revenues  declined by $797,000
between years, after the suspension of third party marketing  activities in late
1994.

         Gains on sales of properties  were $12.3  million in 1995,  compared to
$2.0 million in 1994.  The $8.7 million  gain from the DJ Basin  facility  sales
accounted  for the bulk of the increase.  The  remaining  gains were part of the
Company's ongoing program to dispose of nonstrategic assets at favorable prices.

         Other  income in 1995 was $7.0  million,  which was reduced  from $15.3
million in 1994, as the prior year included $6.6 million in gains on the sale of
a portion of the  Company's  interest in the  Permtex  venture in Russia and the
sale of equity securities by the Company's Australian  affiliate.  The remaining
decrease was  primarily  due to losses on the sale of  marketable  securities in
1995. The Company realized $13.1 million in proceeds from the securities  sales,
which was applied to further reduce the outstanding debt.

         Exploration  expenses for 1995 were $8.0 million,  up $1.5 million from
1994.  The  increase  resulted  primarily  from the  writeoff of $4.1 million of
certain acreage costs.

         General and administrative expenses, net of reimbursements,  were $17.7
million as  compared to $12.9  million in 1994.  The  increase  consists of $2.3
million associated with an increase of activities related to the Company's newer
development  projects,   $1.5  million  in  severance  and  restructuring  costs
primarily  related to the Wattenberg Area activities and $1.0 million related to
the expanding offshore operations.

         Interest  and other  expense was $27.0  million in 1995,  up from $12.5
million in 1994. The majority of the increase was due to higher outstanding debt
levels at higher average interest rates,  and to a lesser extent,  the writedown
of  certain  notes  receivable  to  their  realizable  value.  Senior  debt  was
significantly  reduced  during the last half of the year with the proceeds  from
the sale of the Wattenberg facilities and the west Texas oil and gas properties.

         Depletion,  depreciation and amortization  expense  increased 8% during
1995.  The  increase  resulted  from the 13%  growth in oil and gas  production,
offset  somewhat  by a  reduction  in the average  depletion,  depreciation  and
amortization rate per BOE to $5.00 in 1995 from $5.37 in 1994.

         The effective  income tax rate for 1995 was a benefit of three percent.
This  benefit was limited to the extent of the net  deferred  tax  liability  at
December 31, 1994 of $591,000  and the  realization  of a $779,000  deferred tax
asset that was previously  recorded to stockholders'  equity as required by SFAS
No. 115.

DEVELOPMENT, ACQUISITION AND EXPLORATION

         During  1996,   the  Company   incurred   $349.0   million  in  capital
expenditures,  including $297.7 million for property acquisitions, $43.1 million
for development, $4.6 million for exploration, $2.0 million for field and office
equipment and $1.6 million for gas facility expansion.

                                       24
<PAGE>

         The Company expended $297.7 million  relating to property  acquisitions
during 1996. Of this amount,  $273.1  million was for producing  properties  and
$24.6 million was for unevaluated properties. Of the $273.1 million expended for
producing properties,  $218.4 million related to the formation of Patina and the
subsequent May 1996 acquisition (the "Acquisition") of GOG. In 1996, the Company
acquired,  via three acquisitions,  incremental  interests in certain properties
located in the Gulf of Mexico for a net purchase  price of $72.1 million  ($22.4
million was classified as unevaluated properties).

         Of the total development  expenditures,  $12.8 million was concentrated
in the Gulf of Mexico  where  four  wells  were  placed on sales  with  three in
progress at year end. The Company expended $8.6 million in the Piceance Basin of
western  Colorado  to place 22 wells on sales with one in  progress at year end.
The Company expended $5.7 million in the East Washakie Basin of southern Wyoming
to place  twelve wells on sales with three in progress at year end. In the Green
River Basin of southern  Wyoming,  $2.9 million was incurred to place five wells
on sales with two in progress at year end.

         Exploration  costs in 1996 were $4.6 million primarily for seismic work
performed in and around the  Company's  major  drilling  projects and a dry hole
drilled in the Gulf of Mexico. In Russia,  ten additional wells were drilled and
completed resulting in that venture increasing  production to over 3,500 barrels
per day.  Drilling activity has been slower than anticipated due to difficulties
in securing drilling  contracts on commercially  reasonable terms.  During 1997,
the Company  expects to drill 11 wells.  In Mongolia,  the Mongolian  Parliament
ratified  the grant of two  additional  concessions  in the area to SOCO Tamtsag
Mongolia,  Inc.  bringing the total acreage position to approximately 10 million
acres. During 1996, two exploratory wells were drilled, one of which resulted in
a second  discovery.  SOCO Tamtsag  Mongolia,  Inc.  intends to drill four wells
during  1997.  In Thailand,  the Company was awarded  Block B8/38 in the Gulf of
Thailand.  The Company has entered into an agreement with an  international  oil
company  which will fund the  drilling  of an  exploration  well in this  block.
Drilling is expected to begin in the second quarter, with a second well possibly
being drilled by year end.

FINANCIAL CONDITION AND CAPITAL RESOURCES

         At December 31, 1996,  the Company had total assets of $879.5  million.
Total  capitalization  was  $675.8  million,  of which  44% was  represented  by
stockholder's  equity,  28% by senior debt, 27% by  subordinated  debt and 1% by
deferred taxes payable.  During 1996, net cash provided by operations was $101.7
million,  an  increase  of 47%  compared  to  1995.  As of  December  31,  1996,
commitments  for  capital   expenditures   totaled  $7.3  million.  The  Company
anticipates  that 1997  expenditures  for development  drilling will approximate
$112  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
and  existing  credit  facilities.  The  Company  is also  considering  a public
offering for a subsidiary  which holds  certain of the  Company's  international
investments.  The Company  expects the offering to be completed in 1997 with the
securities  being  listed on a major international stock exchange. In  addition,
joint ventures  or future public  offerings  of debt  or  equity securities  may
be utilized.

         As a result of the Acquisition,  the Company has realized increased net
cash provided by  operations.  For the  foreseeable  future,  cash  generated by
Patina will,  however,  be retained by Patina to fund its  development  program,
reduce  debt and pursue  acquisitions  in the DJ Basin or  elsewhere.  Moreover,
Patina's credit  facilities  currently  prohibit the payment of dividends on its
common stock.  Accordingly,  Patina's cash flow is intended to be used to reduce
debt  levels,  fund a limited  development  program and any future  acquisitions
which may be  consummated  and may not be available to fund the Company's  other
operations or to pay dividends to its stockholders.

         SOCO  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, 1996 was
$140  million.  Financial  covenants  limit debt,  require  maintenance  of $1.0
million in minimum  working  capital as defined and restrict  certain  payments,
including  stock  repurchases,  dividends   and  contributions  or  advances  to

                                       25
<PAGE>


unrestricted  subsidiaries.  Such  restricted  payments are limited by a formula
that includes  underwriting  proceeds,  cash flow and other items. Based on such
limitations,  more than $60 million was  available  for the payment of dividends
and other restricted payments as of December 31, 1996.

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

         The Patina  Facility is a  revolving  credit  facility in an  aggregate
amount  up to $102  million.  The  amount  available  for  borrowing  under  the
revolving credit facility will be limited to a semiannually  adjusted  borrowing
base that equaled $85 million at December 31, 1996. At December 31, 1996,  $67.5
million was outstanding  under the revolving credit facility.  Subsequent to the
Acquisition,  Patina has utilized  primarily cash flow from operations to reduce
the balance outstanding under the Patina Facility by more than $14 million.

         The GOG Facility is a revolving  credit facility in an aggregate amount
up to $51 million.  The amount  available for  borrowing  under the GOG Facility
will be limited to a  fluctuating  borrowing  base that  equaled  $35 million at
December 31, 1996. At December 31, 1996, $27.0 million was outstanding under the
GOG Facility.  The GOG Facility was used  primarily to refinance  GOG's previous
bank  credit  facility  and pay  for  costs  associated  with  the  Acquisition.
Subsequent  to the  Acquisition,  Patina has utilized  primarily  cash flow from
operations to reduce the balance outstanding under the GOG Facility by more than
$7 million.

         Patina's bank credit  agreement  contains certain  financial  covenants
including,  but not limited to, a maximum total debt to capitalization  ratio, a
maximum total debt to EBITDA ratio and a minimum current ratio.  The bank credit
agreement also contains certain negative covenants, including but not limited to
restrictions on indebtedness; certain liens; guarantees, speculative derivatives
and  other  similar  obligations;  asset  dispositions;   dividends,  loans  and
advances; creation of subsidiaries;  investments; leases; acquisitions; mergers;
changes in fiscal  year;  transactions  with  affiliates;  changes  in  business
conducted;  sale  and  leaseback  and  operating  lease  transactions;  sale  of
receivables;   prepayment  of  other   indebtedness;   amendments  to  principal
documents;  negative pledge clauses; issuance of securities; and non-speculative
commodity hedging.

         The Company from time to time enters into  arrangements to monetize its
Section  29 tax  credits.  These  arrangements  result in revenue  increases  of
approximately  $.40 per Mcf on  production  volumes  from  qualified  Section 29
properties. As a result of such arrangements,  the Company recognized additional
gas sales of $2.5 million in both years ended December 31, 1995 and 1996.  These
arrangements are expected to increase revenues through 2002.

         The Company seeks to diversify its exploration and development risks by
seeking  partners  for its  significant  development  projects  and  maintains a
program to divest marginal properties and assets which do not fit its long range
plans. During 1996, the Company received $73.6 million in proceeds from the sale
of oil and gas properties which were used to reduce debt and finance  additional
acquisitions in the Gulf of Mexico.  The most  significant  sales arose from the
addition of partners in two of the Company's  major  development  projects.  The
largest sale was the sale of a 45% interest in its Piceance Basin holdings for a
sale price of $22.4 million.  The Company  recognized a net gain of $2.4 million
as a result of this transaction. In addition, the Company sold a 50% interest in
its Green River Basin gas project for $16.9  million.  The Company  recognized a
net gain of $7.4 million as a result of this transaction. Proceeds from the sale
of nonstrategic properties totaled $34.3 million. The largest of these sales was
the sale in December  1996 of the Company's  interests in the Giddings  Field of
southeast  Texas for $11.8  million.  The Company  recognized a net loss of $3.3
million as a result of this transaction.

         In  November  1996,  the  Company  accepted an offer from Cairn for its
interest  in  Command.  The  Company  received  16.2  million  shares  of freely
marketable  Cairn common stock,  and recorded a gain of $65.5  million,  with no
associated  current tax  liability.  However,  a deferred tax  provision of $4.0
million  was  recorded  related to this  transaction.  Immediately  prior to the
acceptance of Cairn's  offer,  the Company  accrued for a transaction in which a
director of the Company  exchanged his option to purchase 10% of the outstanding
common  stock of SOCO  International,  Inc.  (through  which the  investment  in
Command was held) and issued  promissory notes to the Company totaling  $591,000
for  10%  of the  outstanding  common  stock  of two  SOCO  International,  Inc.

                                       26
<PAGE>


subsidiaries,   SOCO  International   Holdings,  Inc.  and   SOCO  International
Operations,  Inc.  As a result  of this  transaction,  the  Company  recorded  a
$260,000 loss on the exchange.  Additionally,  minority interest expense of $4.3
million was recorded  related to the director's 10% ownership as a result of the
Command gain. The actual  exchange  occurred in December 1996 and the promissory
notes remained outstanding at year end. Subsequent to year end, the Company sold
4.5  million  Cairn  shares at an  average  of $8.81 per share  realizing  $39.2
million in proceeds  which will be used  primarily to reduce senior debt.  These
transactions  are anticipated to result in a pretax gain of $11.7 million (after
minority interest expense of $1.3 million) in the first quarter of 1997.

         During the second quarter of 1996, the Board  authorized the repurchase
of up to $10 million of the  Company's  securities  and in the third  quarter of
1996,  authorized  an additional  $10 million for this purpose.  During the last
three quarters of 1996, the Company  repurchased  725,000 common shares for $7.0
million,  6,000 preferred  depository  shares for $142,000 and $3.8 million face
value convertible  subordinated notes for $3.5 million.  Additional  repurchases
have and may continue to be made at such times and at such prices as the Company
deems appropriate.

         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.

                                       27
<PAGE>

INFLATION AND CHANGES IN PRICES

         While  certain  of its  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. 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
1995 and 1996.  Average gas prices for 1995 and 1996 were  increased by $.06 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
                        ------
                          1992                           $  18.87           $  1.74         $  13.76
                          1993                              15.41              1.94            13.41
                          1994                              14.80              1.67            11.82
                          1995                              16.96              1.35            11.00
                          1996                              20.39              1.97            14.35

                       QUARTERLY
                       ---------

                         1995
                         ----
                         First                           $  16.40           $  1.31         $  10.66
                         Second                             17.52              1.29            10.95
                         Third                              17.05              1.30            10.81
                         Fourth                             16.84              1.55            11.69

                         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 1996, the Company  received an average of $22.19 per barrel
and $3.68 per Mcf for its production.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

         Reference is made to the Index to Consolidated  Financial Statements on
page 29 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, other than Schedule I, 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.

                                       28
<PAGE>



                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


                                                                          PAGE



Report of Independent Public Accountants....................................30

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

Consolidated Statements of Operations
     for the years ended December 31, 1994, 1995 and 1996...................32

Consolidated Statements of Changes in Stockholders' Equity
     for the years ended December 31, 1994, 1995 and 1996...................33

Consolidated Statements of Cash Flows
     for the years ended December 31, 1994, 1995 and 1996...................34

Notes to Consolidated Financial Statements..................................35

Schedules:

     Schedule I-Condensed Financial Information of Snyder Oil Corporation ..54

                                       29

<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,
1995 and 1996, and the related consolidated statements of operations, changes in
stockholders'  equity,  and cash flows for each of the three years in the period
ended December 31, 1996. These financial  statements are the  responsibility  of
the Company's  management.  Our responsibility is to express an opinion on these
financial statements based on our audits.

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

         In our opinion,  the  financial  statements  referred to above  present
fairly,  in  all  material  respects,  the  financial  position  of  Snyder  Oil
Corporation  and  subsidiaries as of December 31, 1995 and 1996, and the results
of their  operations  and their  cash  flows for each of the three  years in the
period ended December 31, 1996, 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.

         Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The supplementary schedules listed in the
index to the  consolidated  financial  statements  are presented for purposes of
complying  with the  Securities  and Exchange  Commission's  rules and are not a
required  part of the basic  financial  statements.  These  schedules  have been
subjected  to the  auditing  procedures  applied  in  our  audits  of the  basic
financial statements and, in our opinion,  fairly state in all material respects
the  financial  data  required to be set forth  therein in relation to the basic
financial statements taken as a whole.




                                         ARTHUR ANDERSEN LLP

Fort Worth, Texas,
February 17, 1997


                                        30
<PAGE>
<TABLE>
                                              SNYDER OIL CORPORATION

                                            CONSOLIDATED BALANCE SHEETS
                                                  (IN THOUSANDS)
<CAPTION>
                                                                                            DECEMBER 31,
                                                                                  --------------------------------
                                                                                       1995               1996
                                                                                  -------------      -------------
                                                      ASSETS
<S>                                                                                <C>                <C>
Current assets
     Cash and equivalents                                                          $    27,263        $    27,922
     Accounts receivable                                                                29,259             58,944
     Inventory and other                                                                11,769             11,212
                                                                                   -----------        -----------
                                                                                        68,291             98,078
                                                                                   -----------        -----------

Investments                                                                             33,220            129,681
                                                                                   -----------        -----------

Oil and gas properties, successful efforts method                                      675,961            887,721
     Accumulated depletion, depreciation and amortization                             (240,744)          (252,334)
                                                                                   -----------        -----------
                                                                                       435,217            635,387
                                                                                   -----------        -----------

Gas facilities and other                                                                30,506             28,111
     Accumulated depreciation and amortization                                         (11,741)           (11,798)
                                                                                   -----------        -----------
                                                                                        18,765             16,313
                                                                                   -----------        -----------
                                                                                   $   555,493        $   879,459
                                                                                   ===========        ===========

                                       LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
     Accounts payable                                                              $    36,353        $    51,867
     Accrued liabilities                                                                26,096             37,043
                                                                                   -----------        -----------
                                                                                        62,449             88,910
                                                                                   -----------        -----------

Senior debt                                                                            150,001            188,231
Subordinated notes                                                                      -                 103,094
Convertible subordinated notes                                                          84,058             80,748

Deferred taxes payable                                                                  -                   9,034
Other noncurrent liabilities                                                            20,016             28,064

Minority interest                                                                        3,601             86,710
Commitments and contingencies

Stockholders' equity
     Preferred stock,  $.01 par,  10,000,000 shares  authorized,
         6% Convertible preferred stock, 1,035,000 and 1,033,500
         shares issued and outstanding                                                      10                 10
     Common stock, $.01 par, 75,000,000 shares authorized,
         31,430,227 and 31,456,027 issued                                                  314                315
     Capital in excess of par value                                                    265,911            260,221
     Retained earnings (deficit)                                                       (29,001)            25,711
     Common stock held in treasury, 134,191 and 250,000 shares at cost                  (2,457)            (3,510)
     Unrealized foreign currency translation gain                                          380                -
     Unrealized gain on investments                                                        211             11,921
                                                                                   -----------        -----------
                                                                                       235,368            294,668
                                                                                   -----------        -----------
                                                                                   $   555,493        $   879,459
                                                                                   ===========        ===========

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

                                                         31

<PAGE>

<TABLE>

                                              SNYDER OIL CORPORATION

                                       CONSOLIDATED STATEMENTS OF OPERATIONS
                                       (IN THOUSANDS EXCEPT PER SHARE DATA)

<CAPTION>
                                                                                  YEAR ENDED DECEMBER 31,
                                                                      ---------------------------------------------
                                                                          1994             1995             1996
                                                                      -----------      -----------      -----------
<S>                                                                    <C>              <C>              <C>
Revenues
   Oil and gas sales                                                   $ 137,858        $ 144,608        $ 189,327
   Gas transportation, processing and marketing                          107,247           38,256           17,655
   Gains on sales of equity interests in investees                         9,747            2,183           69,343
   Gains on sales of properties                                            1,969           12,254            8,786
   Other                                                                   5,507            4,859            7,303
                                                                       ---------        ---------        ---------

                                                                         262,328          202,160          292,414
                                                                       ---------        ---------        ---------
Expenses
   Direct operating                                                       46,267           52,486           49,638
   Cost of gas and transportation                                         94,177           29,374           15,020
   Exploration                                                             6,505            8,033            4,232
   General and administrative                                             12,853           17,680           17,143
   Interest and other                                                     12,463           27,001           28,899
   Litigation settlement                                                   -                4,400            -
   Loss on sale of subsidiary interest                                     -                -               15,481
   Depletion, depreciation and amortization                               70,770           76,378           84,547
   Property impairments                                                    5,783           27,412            2,753
                                                                       ---------        ---------        ---------

Income (loss) before taxes and minority interest                          13,510          (40,604)          74,701
                                                                       ---------        ---------        ---------

Provision (benefit) for income taxes
   Current                                                                 -                   25               33
   Deferred                                                                  967           (1,370)           4,313
                                                                       ---------        ---------        ---------
                                                                             967           (1,345)           4,346
                                                                       ---------        ---------        ---------

Minority interest                                                           (171)            (572)          (7,405)
                                                                       ---------        ---------        ---------

Net income (loss)                                                      $  12,372        $ (39,831)       $  62,950
                                                                       =========        =========        =========

Net income (loss) per common share                                     $     .07        $   (1.53)       $    1.81
                                                                       =========        =========        =========

Weighted average shares outstanding                                       23,704           30,186           31,308
                                                                       =========        =========        =========


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

                                                        32

<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, 1993            2,221   $   22        23,260   $  233         $ 249,713      $  25,308    $    -

    Common stock grants and
       exercise of options              -        -             414        4             2,851            -        (2,288)

    Conversion of preferred
       to common                     (1,186)     (12)        6,535       65               (53)           -           -

    Issuance of warrants                -        -             -        -               3,450            -           -

    Dividends                           -        -             -        -                 -          (16,721)        -

    Net income                          -        -             -        -                 -           12,372         -
                                    -------   ------       -------    ------        ---------      ---------    --------

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)
                                    =======   ======      ========    ======        =========       ========    ========

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

                                                                 33

<PAGE>
<TABLE>



                                              SNYDER OIL CORPORATION
                                       CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                  (IN THOUSANDS)
<CAPTION>
                                                                                 YEAR ENDED DECEMBER 31,
                                                                     ----------------------------------------------
                                                                         1994             1995             1996
                                                                     ------------     ------------      -----------
<S>                                                                  <C>              <C>               <C>
Operating activities
   Net income (loss)                                                 $    12,372      $   (39,831)      $   62,950
   Adjustments to reconcile net income (loss) to net
      cash provided by operations
          Amortization of deferred credits                                (2,986)          (2,511)          (1,052)
          Gains on sales of investments                                   (9,747)            (809)         (68,343)
          Gains on sales of properties                                    (1,969)         (12,254)          (8,786)
          Equity in (earnings) losses of unconsolidated subsidiaries      (1,355)           1,319             (421)
          Exploration expense                                              6,505            8,033            4,232
          Loss on sale of subsidiary interest                               -                -              15,481
          Depletion, depreciation and amortization                        70,770           76,378           84,547
          Property impairments                                             5,783           27,412            2,753
          Deferred taxes                                                     967           (1,370)           4,313
          Minority interest                                                  171              572            7,405
          Changes in current and other assets and liabilities
            Decrease (increase) in
               Accounts receivable                                        11,024            7,142          (15,869)
               Inventory and other                                        (9,241)           3,617            5,175
            Increase (decrease) in
               Accounts payable                                            1,901           (8,521)           2,771
               Accrued liabilities                                         1,841            5,165             (316)
               Other liabilities                                             361            4,779            6,890
                                                                    ------------     ------------      -----------
          Net cash provided by operations                                 86,397           69,121          101,730
                                                                    ------------     ------------      -----------

Investing activities
   Acquisition, development and exploration                             (237,879)         (92,353)        (128,598)
   Purchase of controlling interest in subsidiary                         (6,645)            -               -
   Proceeds from investments                                               5,019           14,786            1,635
   Outlays for investments                                                (8,804)            -              (9,013)
   Proceeds from sales of properties                                       2,806          109,988           73,620
                                                                    ------------     ------------      -----------
          Net cash realized (used) by investing                         (245,503)          32,421          (62,356)
                                                                    ------------     ------------      -----------

Financing activities
   Issuance of common                                                      1,157              688            1,523
   Increase (decrease) in indebtedness                                   187,138          (86,193)         (13,289)
   Debt issuance costs                                                    (2,855)            -               -
   Dividends                                                             (16,721)         (14,056)         (14,411)
   Deferred credits                                                        2,356            3,549             (120)
   Repurchase of stock                                                    (1,149)            -              (7,186)
   Repurchase of subordinated notes                                         -                -              (5,232)
                                                                    ------------     ------------      -----------
          Net cash realized (used) by financing                          169,926          (96,012)         (38,715)
                                                                    ------------     ------------      -----------

Increase in cash                                                          10,820            5,530              659
Cash and equivalents, beginning of year                                   10,913           21,733           27,263
                                                                    ------------     ------------      -----------
Cash and equivalents, end of year                                   $     21,733     $     27,263      $    27,922
                                                                    ============     ============      ===========

Noncash investing and financing activities
   Gas plant capital lease                                          $     21,000             -                -
   Acquisition of properties and stock via stock issuances                  -         $    13,032      $     3,693
   Acquisition of properties recorded as senior debt                        -                -         $    31,730
   Acquisition via subsidiary stock issuance                                -                -         $   115,067

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

                                                         34

<PAGE>



                             SNYDER OIL CORPORATION

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)       ORGANIZATION AND NATURE OF BUSINESS

          Snyder Oil  Corporation  (the  "Company") is primarily  engaged in the
acquisition,  exploration and development of oil and gas properties  principally
in the Rocky  Mountain and Gulf Coast regions of the United  States.  To a minor
extent,  the Company  gathers,  transports and markets  natural gas generally in
proximity to its principal producing properties.  The Company is also engaged in
international  acquisition,   exploration  and  development,  primarily  through
affiliates.  The Company, a Delaware corporation,  is the successor to a company
formed in 1978.

(2)       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

          The consolidated  financial  statements include the accounts of Snyder
Oil Corporation  ("SOCO") and its  subsidiaries  (collectively,  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 being accounted for in this manner
include Patina Oil & Gas Corporation  ("Patina"),  SOCO International  Holdings,
Inc. ("Holdings") and SOCO International Operations, Inc. ("Operations"). DelMar
Petroleum,  Inc.,  whose name was  subsequently  changed to SOCO Offshore,  Inc.
("SOCO Offshore"), was accounted for in this manner until all remaining minority
interests  were  acquired in June 1996.  Affiliates  in which the  Company  owns
between 20% and 50% are accounted for under the equity method.  Affiliates being
accounted for in this manner include SOCO Perm Russia,  Inc.  ("SOCO  Perm"),  a
Russian affiliate, and SOCO Tamtsag Mongolia, Inc. ("SOCO Tamtsag"), a Mongolian
affiliate.  Command Petroleum Limited ("Command"),  an Australian affiliate, was
accounted  for in this manner until the Company  disposed of this  investment in
November 1996.  Affiliates in which the Company owns less than 20% are accounted
for under the cost method. Affiliates being accounted for in this manner include
Cairn  Energy plc  ("Cairn").  The Company  accounts  for its  interest in joint
ventures and partnerships using the proportionate  consolidation method, whereby
its share of assets, liabilities, revenues and expenses are consolidated.

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 the
year ended December 31, 1996, the Company provided unproved property impairments
of $2.8 million.  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.

          Prior to 1995, the Company provided impairments for significant proved
oil and gas property  groups to the extent that net  capitalized  costs exceeded
the undiscounted  future cash flows.  During 1995, the Company adopted 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 on a property-by-property  basis. If
an impairment is indicated  based on  undiscounted  expected  future cash flows,
then it is recognized to the extent that net capitalized costs exceed discounted
expected future cash flows. Accordingly,  in 1995 the Company provided for $27.4
million of such  impairments.  During  the year ended  December  31,  1996,  the
Company did not provide for any such impairments.


                                        35
<PAGE>



Unrealized Foreign Currency Translation Gain

          The company follows SFAS 52,  "Foreign  Currency  Translation",  which
requires that business transactions and foreign operations recorded in a foreign
currency must be restated in U.S.  dollars.  Gains or losses  resulting from the
translation  process  increases or decreases the book value of  investments  and
must be accumulated in a separate component of stockholders'  equity.  Command's
functional  currency is the Australian dollar. The foreign currency  translation
gain reported in the balance sheet as of December 31, 1995 was the result of the
translation of the Australian dollar balance sheet into United States dollars at
then current exchange rates.

Section 29 Tax Credits

          The Company from time to time enters into arrangements to monetize its
Section  29 tax  credits.  These  arrangements  result in revenue  increases  of
approximately  $.40 per Mcf on  production  volumes  from  qualified  Section 29
properties. As a result of such arrangements,  the Company recognized additional
gas  revenues  of $2.5  million in both 1995 and 1996.  These  arrangements  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 year end 1995 and 1996
were insignificant.

Financial Instruments

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

                                                                   DECEMBER 31,              DECEMBER  31,
                                                                       1995                      1996
                                                              ----------------------     ----------------------
                                                                BOOK         FAIR          BOOK         FAIR
                                                                VALUE        VALUE         VALUE        VALUE
                                                              ---------    ---------     ---------    ---------
          <S>                                                 <C>          <C>           <C>          <C>
          Cash and equivalents                                $  27,263    $  27,263     $  27,922    $  27,922
          Investments                                            33,220       52,203       129,681      163,477
          Senior debt                                          (150,001)    (150,001)     (188,231)    (188,231)
          Subordinated notes                                       -            -         (103,094)    (105,650)
          Convertible subordinated notes                        (84,058)     (79,997)      (80,748)     (82,866)
          Long-term commodity contracts                            -          11,623          -           5,040
          Interest rate swap                                       -             107          -             (19)
</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, 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 revenue 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 per day through
2004. In December  1996,  that volume  represented  approximately  43% of SOCO's
Rocky  Mountain  gas  production  and 17% of the  Company's  consolidated  Rocky
Mountain gas production.  The fair value of the contract was based on the market
price quoted for a similar instrument.



                                       36

<PAGE>



          In September  1995,  the Company  entered  into an interest  rate swap
covering  $50  million of its bank debt.  The  agreement  requires  payment to a
counterparty  based on a fixed rate of 5.585% and requires the  counterparty  to
pay the  Company  interest  at the then  current  30 day  LIBOR  rate.  Accounts
receivable  or payable  under this  agreement  are  recorded as  adjustments  to
interest  expense and are settled on a monthly basis.  The agreement  matures in
September  1997,  with the  counterparty  having the option to extend it for two
years.  At December 31, 1996,  the fair value of the  agreement was estimated at
the net present value discounted at 10%.

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 currently  produces over 70% of its natural gas, have traditionally been
particularly  volatile.  Prices are significantly impacted by the local weather,
production  in the  area,  seasonal  variations  in  local  demand  and  limited
transportation  capacity to other regions of the country.  Until recently,  mild
weather and increased  production in the region contributed to depressed prices.
At December 31, 1996, prices in the region had rebounded sharply, although it is
uncertain  if this  trend  will  continue.  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 Company's  strategy  internationally  is to develop a portfolio of
projects that have the potential to make a major  contribution to its production
and reserves while limiting its financial exposure and mitigating political risk
by seeking industry  partners and investors to fund the majority of the required
capital.  Such  projects  are  subject  to a number of  political  and  economic
uncertainties,  in addition to the typical risks and volatility  associated with
the oil and gas industry. There is no assurance that the Company's international
operations will reach a level reasonably required to fully exploit the projects,
nor is there any assurance of economic success should such a level be reached.

          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.

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 and domestic  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, 1995             DECEMBER 31, 1996
                                                           -----------------------       ------------------------
                                                                              (IN THOUSANDS)

                                                             BOOK           FAIR           BOOK           FAIR
                                                             VALUE          VALUE          VALUE          VALUE
                                                           ---------      ---------      ---------      ---------
<S>                                                        <C>            <C>            <C>            <C>
          Equity method investments                        $  30,901      $  49,884      $   8,789      $  42,585
          Marketable securities                                  652            652        115,558        115,558
          Long-term notes receivable                           1,667          1,667          5,334          5,334
                                                           ---------      ---------      ---------      ---------

                                                           $  33,220      $  52,203      $ 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

                                       37

<PAGE>

securities accounted for on the cost method and long-term notes receivable  must
be adjusted to their market value with a  corresponding  increase or decrease to
stockholders'  equity. The pronouncement does not apply to investments accounted
for by the equity method.

Command Petroleum Limited

          From May 1993 to  November  1996,  the Company  had an  investment  in
Command, an Australian oil company,  accounted for by the equity method. Command
was listed on the Australian  Stock Exchange.  In 1995, the Company  acquired an
additional  4.7  million  shares of  Command  common  stock in  exchange  for an
interest in the Fejaj Permit in Tunisia. As a result, the Company's ownership in
Command  increased to 30.0% and a $1.4 million gain was recognized  during 1995.
In June 1996,  the Company  purchased 8.5 million shares of Command common stock
for $3.6 million,  increasing its ownership to 32.6%.  In October 1996,  Command
announced that it had completed merger negotiations with Cairn, an international
independent  oil company based in Edinburgh,  Scotland with shares listed on the
London Stock Exchange.  In November 1996, the Company accepted Cairn's offer for
its interest in Command.  The Company  received  16.2  million  shares of freely
marketable  Cairn  common  stock,  and  recorded a gain of $65.5  million in the
fourth quarter of 1996. The Company's investment in Cairn is accounted for under
the cost method and is reflected as  marketable  securities  in the table above.
Immediately  prior to the acceptance of Cairn's offer, the Company accrued for a
transaction in which a director of the Company  exchanged his option to purchase
10% of the outstanding common stock of SOCO  International,  Inc. (through which
the investment in Command was held) and issued  promissory  notes to the Company
totaling  $591,000  for  10%  of  the  outstanding  common  stock  of  two  SOCO
International,  Inc. subsidiaries,  Holdings and Operations. As a result of this
transaction,  the   Company  recorded   a   $260,000   loss  on  the   exchange.
Additionally,  minority interest expense of $4.3 million was recorded related to
the director's 10%  ownership  as a  result  of the  Command  gain.  The  actual
exchange  occurred  in   December  1996  and  the   promissory   notes  remained
outstanding at year end.

SOCO Perm Russia, Inc.

          In 1993,  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.  To finance a
portion of its  planned  development  expenditures,  SOCO Perm  closed a private
placement of its equity securities with three industry  participants in 1994. As
a result,  the  Company's  investment  was reduced from 75% to 41.25% and a $3.5
million net gain was recorded. In 1995, the three industry participants paid the
final  installments  of their  contributions  to SOCO Perm and as a result,  the
Company recognized an additional gain of $1.1 million.  In April 1996, SOCO Perm
closed a private  placement  which reduced the Company's  interest to 34.91% and
indicated a market value of $22.7 million for the Company's  remaining position.
The Company  recognized a gain in the second quarter of $2.6 million as a result
of this transaction.  The private placement agreement requires SOCO Perm to list
its common  shares on a securities  exchange no later than 1998. If such listing
does not occur,  the new  shareholders  have the right to require the Company to
purchase their share at a formula price.  The Company's  investment in SOCO Perm
is held through Operations. The Company is currently considering the possibility
of listing Operations on a major international  Stock Exchange.  If such listing
was to occur,  it is expected  to meet the  requirement  to list SOCO Perm.  The
Company's  investment  in SOCO Perm had a carrying  cost at December 31, 1996 of
$7.0 million.

SOCO Tamtsag Mongolia, Inc.

          In 1994,  the Company formed a consortium to explore the Tamtsag Basin
of eastern  Mongolia,  then sold a portion  of its  interest  to three  industry
participants.  One participant  committed to fund the drilling of two wells, the
second  purchased  its  interest for cash and a third  participant  assigned its
exploration  rights in the basin to the consortium.  Accordingly,  the Company's
investment  in SOCO Tamtsag was reduced from 100% to 49% and a $1.5 million gain
was recognized.  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.  In  August  1996,  the  Mongolian
Parliament ratified the grant of two additional  concessions in the area to SOCO
Tamtsag,  bringing the total acreage position to approximately 10 million acres.
The Company's  investment in SOCO Tamtsag had a carrying cost of $1.8 million at
December 31, 1996 in addition to $4.7 million in  stockholder  loans,  which are
required  on a pro rata basis by all  stockholders,  to SOCO  Tamtsag  which are
included in notes  receivable in the table above.  In January 1997, SOCO Tamtsag
completed an equity sale  which reduced the  Company's  investment to  40.3% and

                                       38
<PAGE>

indicated a market value of $19.9 million for the Company's  remaining position.
The Company's investment in SOCO Tamtsag is held through Operations.

Marketable Securities

          The Company had  investments in equity  securities of publicly  traded
domestic energy companies accounted for on the cost method, with a total cost at
December 31, 1995 of $328,000.  The market value of these securities at December
31,  1995  approximated  $652,000.  In  1996,  the  Company  sold  all of  these
securities  for $968,000 and  recognized a  corresponding  gain of $640,000.  In
accordance  with SFAS 115 at December 31, 1995,  investments  were  increased by
$324,000 of gross unrealized holding gains,  stockholders'  equity was increased
by $211,000 and deferred taxes payable were  increased by $113,000.  The Company
had  investments  in equity  securities of one publicly  traded  foreign  energy
company, Cairn, accounted for on the cost method at December 31, 1996. Cairn has
a major  development  project  off the  coast  of  Bangladesh  as well as  major
producing  interests  in the  United  Kingdom  and  the  Dutch  North  Sea,  and
exploration  interests  in several  countries  including  Thailand,  Vietnam and
China.  The Company's  total cost basis in the Cairn shares was $95.2 million at
December 31, 1996.  The market  value of the Cairn  shares  approximated  $115.6
million at December 31, 1996. In accordance with SFAS 115, at December 31, 1996,
investments  were  increased by a $20.4 million gross  unrealized  holding gain,
stockholders' equity was increased by $11.9 million, minority interest liability
was increased by $1.3 million and deferred  taxes payable were increased by $7.2
million. Subsequent to year end, the Company sold 4.5 million Cairn shares at an
average of $8.81 per share  realizing  $39.2  million in proceeds  which will be
used  primarily to reduce senior debt.  These  transactions  are  anticipated to
result in a pretax gain of $11.7 million  (after  minority  interest  expense of
$1.3 million) in the first quarter of 1997.

Notes Receivable

          The Company holds  long-term  notes  receivable due from SOCO Tamtsag,
other  privately  held  corporations  and a director,  with a book value of $1.7
million and $5.3 million at December 31, 1995 and 1996. SOCO Tamtsag shareholder
loans,  which bear interest at the three month LIBOR rate plus two percent,  are
to be repaid from the gross receipts of SOCO Tamtsag under certain circumstances
(i.e.,  excess cash reserves).  Any remaining balances mature December 31, 2009.
The notes from other privately held  corporations are secured by certain assets,
including  stock and oil and gas  properties.  The notes from a director,  which
originated  in  connection  with an  option  to  purchase  10% of the  Company's
international affiliates,  are unsecured and are due April 10, 1998. The Company
believes  that,  based on existing  market  conditions,  the  December  31, 1996
balances will be recovered in the long term. At December 31, 1995 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.

(4)       OIL AND GAS PROPERTIES AND GAS FACILITIES

          The  cost of oil and gas  properties  at  December  31,  1995 and 1996
includes  $24.2  million  and  $32.7  million,   respectively,   of  unevaluated
leasehold.  Such properties are held for exploration,  development or resale and
are excluded from  amortization.  The following  table sets forth costs incurred
related  to oil  and  gas  properties  and  gas  processing  and  transportation
facilities:
 <TABLE>
<CAPTION>
                                                               1994                1995              1996
                                                            ----------          ----------        ----------
                                                                              (IN THOUSANDS)
     <S>                                                    <C>                 <C>               <C>
     Proved acquisitions                                    $   44,684          $   13,675        $  273,088
     Acreage acquisitions                                       25,571               7,388            24,589
     Development                                               156,912              62,578            43,075
     Gas processing, transportation and other                   46,607               7,886             3,612
     Exploration                                                 5,514               8,214             4,588
                                                            ----------          ----------        ----------
                                                            $  279,288          $   99,741        $  348,952
                                                            ==========          ==========        ==========
</TABLE>
          During 1996, the Company  incurred  $273.1 million for domestic proved
acquisitions.  Of the total acquisition expenditures,  $218.4 million related to
the  formation  of  Patina  and  the  subsequent  May  1996   acquisition   (the
"Acquisition")  of  Gerrity  Oil & Gas  Corporation  ("GOG").  As a result,  the
Company initially retained 70% of the common stock of  Patina and the former GOG

                                      39

<PAGE>

shareholders received 30% of the common stock. The Company currently owns 74% of
Patina,  and it is consolidated  into the Company's  financial  statements.  The
Company  recognized a net loss of $15.5 million in the second quarter of 1996 as
a  result  of this  transaction.  In  1996,  the  Company  acquired,  via  three
acquisitions, incremental interests in certain properties located in the Gulf of
Mexico for a net purchase  price of $72.1  million  ($22.4  million of which was
classified as acreage acquisitions).

          Of the total development expenditures,  $12.8 million was concentrated
in the Gulf of Mexico  where  four  wells  were  placed on sales  with  three in
progress at year end. The Company expended $8.6 million in the Piceance Basin of
western  Colorado  to place 22 wells on sales with one in  progress at year end.
The Company expended $5.7 million in the East Washakie Basin of southern Wyoming
to place  twelve wells on sales with three in progress at year end. In the Green
River Basin of southern  Wyoming,  $2.9 million was incurred to place five wells
on sales with two in progress at year end.

          In May 1996,  the Company sold a 45%  interest in its  Piceance  Basin
holdings for $22.4 million. The Company recognized a net gain of $2.4 million as
a result of this  transaction.  In July 1996, the Company sold a 50% interest in
its Green River Basin gas project for $16.9  million.  The Company  recognized a
net gain of $7.4 million as a result of this transaction.  In December 1996, the
Company sold its  interests in the Giddings  Field of southeast  Texas for $11.8
million.  The Company  recognized a net loss of $3.3 million as a result of this
transaction.

          The following table  summarizes the unaudited pro forma effects on the
Company's   financial   statements   assuming   significant   acquisitions   and
divestitures consummated during 1996 had been consummated on January 1, 1995 and
1996.  Future  results may differ  substantially  from pro forma  results due to
changes in oil and gas prices, production declines and other factors. Therefore,
pro forma statements cannot be considered indicative of future operations.
<TABLE>
<CAPTION>
                                                                           1995                       1996
                                                                       -----------                 ----------
                                                                        (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                                                    <C>                         <C>
Oil and gas sales                                                      $   189,734                 $  221,368
Total revenues                                                         $   250,986                 $  324,127
Production direct operating margin                                     $   131,310                 $  170,612
Net income (loss)                                                      $   (43,638)                $   71,125
Net income (loss) per common share                                     $     (1.65)                $     2.07
Weighted average shares outstanding                                         30,186                     31,308
</TABLE>

(5)       INDEBTEDNESS

          The following indebtedness was outstanding on the respective dates:
<TABLE>
<CAPTION>
                                                                                           DECEMBER 31,
                                                                                 -------------------------------
                                                                                     1995                1996
                                                                                 -----------         -----------
                                                                                          (IN THOUSANDS)
          <S>                                                                    <C>                 <C>
          SOCO bank facility                                                     $   150,001         $    93,731
          Patina bank facilities                                                      -                   94,500
          Less current portion                                                        -                     -
                                                                                 -----------         -----------
                  Senior debt                                                    $   150,001         $   188,231
                                                                                 ===========         ===========

          Patina subordinated notes                                              $      -            $   103,094
                                                                                 ===========         ===========

          SOCO convertible subordinated notes                                    $    84,058         $    80,748
                                                                                 ===========         ===========
</TABLE>
                                       40
<PAGE>

          SOCO  maintains  a  $500  million  revolving  credit  facility  ("SOCO
Facility").  The facility is divided into a $400 million long-term portion and a
$100 million short-term portion. The borrowing base available under the facility
was $140 million at December 31, 1996. The majority of the borrowings  under the
facility currently bear interest at LIBOR plus .75% with the remainder at prime,
with an option to select 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 1996, the average  interest
rate under the  revolver  was 6.4%.  The Company  pays certain fees based on the
unused  portion of the  borrowing  base.  Among  other  requirements,  covenants
require  maintenance  of a current  working  capital ratio of 1 to 1 as defined,
limit the incurrence of debt and restrict dividends, stock repurchases,  certain
investments,   other  indebtedness  and  unrelated  business  activities.   Such
restricted  payments  are  limited  by  a  formula  that  includes  underwriting
proceeds,  cash flow and other items.  Based on such limitations,  more than $60
million was available for the payment of dividends and other restricted payments
at December 31, 1996.

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

          The Patina  Facility is a revolving  credit  facility in an  aggregate
amount up to $102 million.  The amount  available for borrowing under the Patina
Facility will be limited to a semiannually  adjusted borrowing base that equaled
$85 million at December  31,  1996.  At December  31,  1996,  $67.5  million was
outstanding under the Patina Facility.

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

          The borrowers may elect that all or a portion of the credit facilities
bear  interest  at a rate per annum  equal to:  (i) the higher of (a) prime rate
plus a margin  equal to .25% with  respect  to the GOG  Facility  and the Patina
Facility (the "Applicable Margin") and (b) the Federal Funds Effective Rate plus
 .5% plus the Applicable  Margin,  or (ii) the rate at which Eurodollar  deposits
for one, two, three or six months (as selected by the  applicable  borrower) are
offered in the interbank  Eurodollar  market in the  approximated  amount of the
requested  borrowing (the "Eurodollar Rate") plus 1.25%, with respect to the GOG
Facility and the Patina Facility (the  "Eurodollar  Margin").  During the period
subsequent to the Acquisition  through  December 31, 1996, the average  interest
rate under the facilities was 6.9%.

          Patina's bank credit agreement  contains certain financial  covenants,
including but not limited to a maximum  total debt to  capitalization  ratio,  a
maximum total debt to EBITDA ratio and a minimum current ratio.  The bank credit
agreement also contains certain negative covenants, including but not limited to
restrictions on indebtedness; certain liens; guaranties, speculative derivatives
and  other  similar  obligations;  asset  dispositions;   dividends,  loans  and
advances; creation of subsidiaries;  investments; leases; acquisitions; mergers;
changes in fiscal  year;  transactions  with  affiliates;  changes  in  business
conducted;  sale  and  leaseback  and  operating  lease  transactions;  sale  of
receivables;   prepayment  of  other   indebtedness;   amendments  to  principal
documents;  negative pledge clauses; issuance of securities; and non-speculative
commodity hedging.

                                      41
<PAGE>


          Simultaneously  with the Acquisition,  Patina recorded $100 million of
11.75%  Subordinated  Notes due July 15, 2004 issued by GOG on July 1, 1994.  In
connection with the  Acquisition,  Patina also  repurchased  $1.2 million of the
notes. As part of the purchase accounting, the remaining notes were reflected in
the  accompanying  financial  statements at a market value of $104.6  million or
105.875% of their principal amount. Subsequent to the Acquisition, an additional
$1.5 million of the notes were repurchased by the Company and retired.  Interest
is payable each January 15 and July 15. The Notes are  redeemable  at the option
of GOG, in whole or in part, at any time on or after July 15, 1999, initially at
105.875% of their principal amount, declining to 100% on or after July 15, 2001.
Upon the occurrence of a change of control,  as defined in the Notes,  GOG would
be obligated to make an offer to purchase  all  outstanding  Notes at a price of
101% of the  principal  amount  thereof.  In addition,  GOG would be  obligated,
subject to certain  conditions,  to make offers to  purchase  Notes with the net
cash proceeds of certain asset sales or other  dispositions of assets at a price
of 101% of the  principal  amount  thereof.  The  Notes  are  unsecured  general
obligations of GOG and are subordinated to all senior indebtedness of GOG and to
any existing and future indebtedness of GOG's subsidiaries.

          The Notes  contain  covenants  that,  among  other  things,  limit the
ability  of GOG to incur  additional  indebtedness,  pay  dividends,  engage  in
transactions with shareholders and affiliates, create liens, sell assets, engage
in mergers and consolidations and make investments in unrestricted subsidiaries.
Specifically,  the Notes restrict GOG from incurring indebtedness  (exclusive of
the Notes) in excess of approximately $51 million, if after giving effect to the
incurrence of such  additional  indebtedness  and the receipt and application of
the proceeds  therefrom,  GOG's  interest  coverage  ratio is less than 2.5:1 or
adjusted  consolidated  net tangible  assets are less than 150% of the aggregate
indebtedness of GOG.

          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 are
convertible into common stock at $22.57 per share. Given the terms of the notes,
common stock  dividends not paid out of retained  earnings reduce the conversion
price when paid.  The notes are  redeemable  at the option of the  Company on or
after May 15, 1997,  initially at 103.51% of principal,  and at prices declining
to 100% at May 15, 2000.  During 1996, the Company  repurchased  $3.8 million of
these notes in accordance with a repurchase program.

          Scheduled  maturities of indebtedness for the next five years are zero
for 1997 and  1998,  $94.5  million  in 1999,  $93.7  million  in 2000 and $82.5
million  in 2001.  The  long-term  portions  of the Patina  Facilities  and SOCO
Facility are scheduled to expire in 1999 and 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 $9.9  million,  $22.1
million and $21.9 million, respectively, for 1994, 1995 and 1996.

(6)       STOCKHOLDERS' EQUITY

          A total of 75 million common shares, $.01 par value, are authorized of
which 31.5 million  were issued at December  31, 1996.  The Company also has 2.1
million warrants outstanding.  The warrants are exercisable at a price of $21.04
per share. Under the terms of the warrants,  common stock dividends not paid out
of retained earnings reduce the exercise price when paid and increase the number
of warrants  outstanding.  Half of the warrants  expire in each of February 1998
and February  1999.  In 1995,  the Company  issued 1.2 million  shares of common
stock,  with 1.1  million  shares  issued  in  exchange  for  acquired  property
interests and 138,000 shares issued primarily for the exercise of stock options.
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 and
267,000 shares issued primarily for the exercise of stock options.  In 1996, the
Company repurchased  725,000 shares of common stock for $7.0 million.  Quarterly
dividends of $.065 per share were paid in 1995 and 1996. For book purposes,  for
the period between June 1995 and September 1996, the common stock dividends were
in excess of retained  earnings  and as such were  treated as  distributions  of
capital.

                                       42
<PAGE>


          A  total  of  10  million  preferred  shares,   $.01  par  value,  are
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. The stock is
convertible into common stock at $20.46 per share. Under the terms of the stock,
common stock  dividends not paid out of retained  earnings reduce the conversion
price when paid. The stock is  exchangeable  at the option of the Company for 6%
convertible  subordinated  debentures  on  any  dividend  payment  date.  The 6%
convertible  preferred  stock  is  currently  redeemable  at the  option  of the
Company. The liquidation preference is $25.00 per depositary share, plus accrued
and unpaid dividends.  At December 31, 1996, the redemption price was $26.05 per
depository  share.  The  redemption  price  declines $.15 per year to $25.00 per
depository share in 2003. During 1996, the Company  repurchased 6,000 depository
shares for  $142,000.  The Company paid $6.2 million  ($1.50 per 6%  convertible
depositary share per annum) in preferred dividends during both 1995 and 1996.

          Earnings per share are computed by dividing net income, less dividends
on preferred  stock, by weighted average common shares  outstanding.  Net income
available  (loss  applicable)  to common for the years ended  December 31, 1994,
1995  and  1996,   was  $1.6  million,   ($46.0)   million  and  $56.7  million,
respectively.  Differences  between primary and fully diluted earnings per share
were insignificant for all periods presented.

          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
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,  1996,  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
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>
                                                                                  1995               1996
                                                                               ---------          ---------
<S>                                                                            <C>                <C>
Net income (loss)                   As Reported                                $ (39,831)         $  62,950
                                    Pro forma                                  $ (40,567)         $  61,936

Income (loss) per share             As Reported                                  $ (1.53)            $ 1.81
                                    Pro forma                                    $ (1.55)            $ 1.78
</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 1995 and 1996,  respectively:  dividend yield of
1.9% and 2.8%;  expected  volatility of 46% and 44%; risk-free interest rates of
7.2% and 5.7%; and an expected life of 4.5 years.



                                       43

<PAGE>



         A summary of the status of the  Company's  two fixed stock option plans
as of December  31,  1994,  1995 and 1996 and changes  during the years ended on
those dates is presented below (shares are in thousands):
<TABLE>
<CAPTION>

                                          1994                      1995                       1996
                                  ---------------------     ---------------------      ---------------------
                                              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                         1,383        $5.66        1,484        $12.96        1,711       $13.21
Granted                              510        18.38          610         14.06          519         9.50
Exercised                           (407)        5.35         (124)         7.34         (255)        6.69
Forfeited                             (2)       16.14         (259)        16.62         (301)       14.71
                                  ------                    ------                     ------
Outstanding at end of year         1,484        12.96        1,711         13.21        1,674        12.72
                                  ======                    ======                     ======

Options exercisable at
   year end                          533                       743                        772

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

         The following table  summarizes  information  about fixed stock options
outstanding at December 31, 1996:
<TABLE>
<CAPTION>
                                       OPTIONS OUTSTANDING                            OPTIONS EXERCISABLE
                      ------------------------------------------------------    -------------------------------
                          NUMBER            WEIGHTED-                              NUMBER
       RANGE          OUTSTANDING AT         AVERAGE             WEIGHTED-      EXERCISABLE AT      WEIGHTED-
        OF             DECEMBER 31,         REMAINING             AVERAGE        DECEMBER 31,        AVERAGE
  EXERCISE PRICES         1996          CONTRACTUAL LIFE      EXERCISE PRICE         1996        EXERCISE PRICE
                                           (In years)
-------------------   --------------    ----------------      --------------    --------------   --------------
<C>                     <C>                   <C>                <C>                 <C>            <C>
$   6.00 to  8.88         163,000             0.9                $  6.09             163,000        $  6.09
    9.38 to 13.75         771,000             3.3                  10.85             260,000          13.02
   14.13 to 20.13         740,000             2.6                  16.14             349,000          16.98
                        ---------                                                    -------
$   6.00 to 20.13       1,674,000             2.7                  12.72             772,000          13.35
                        =========                                                    =======
</TABLE>

(7)      FEDERAL INCOME TAXES

         At December 31, 1996, 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 the years ended December 31, 1994,  1995 and 1996
follows:
 <TABLE>
<CAPTION>
                                                             1994                   1995                    1996
                                                           --------               --------                --------
<S>                                                            <C>                    <C>                    <C>
Federal statutory rate                                          35%                   (35%)                   35%
Loss in excess of net deferred tax liability                    -                      32%                    -
Net change in valuation allowance                              (27%)                   -                     (29%)
Alternative minimum taxes                                       (1%)                   -                      -
                                                            -------                -------                -------
Effective income tax rate                                        7%                    (3%)                    6%
                                                            =======                =======                =======
</TABLE>

                                       44

<PAGE>

         For  book  purposes,  the  components of the net deferred tax asset and
liability at December 31, 1995 and 1996, respectively, were:
<TABLE>
<CAPTION>

                                                                                  1995                    1996
                                                                               -----------            -----------
<S>                                                                            <C>                    <C>
Deferred tax assets
     NOL and capital loss carryforwards                                        $    53,010            $    65,126
     AMT credit carryforwards                                                        1,293                    644
     Production payment receivables                                                  -                     32,654
     Reserves and other                                                              1,977                  5,613
                                                                               -----------            -----------
                                                                                    56,280                104,037
                                                                               -----------            -----------

Deferred tax liabilities
     Depreciable and depletable property                                           (24,018)               (59,865)
     Investments and other                                                          (2,171)               (42,252)
     Unrealized investments gains                                                     (317)                (7,131)
                                                                               -----------            -----------
                                                                                   (26,506)              (109,248)
                                                                               -----------            -----------

Deferred asset (liability)                                                          29,774                 (5,211)
Valuation allowance                                                                (29,774)                (3,823)
                                                                               -----------            -----------

Net deferred tax liability                                                     $      -               $    (9,034)
                                                                               ===========            ===========
</TABLE>
         For tax purposes,  Patina is not included in the Company's consolidated
United States  federal income tax return.  The Company,  excluding  Patina,  had
regular net operating loss carryforwards of $112 million and alternative minimum
tax  loss   carryforwards   of  $28.9  million  at  December  31,  1996.   These
carryforwards  expire  between 1997 and 2010. At December 31, 1996, the Company,
excluding Patina, had long-term capital loss carryforwards of $3.9 million which
will expire in 2000. At December 31, 1996, the Company,  excluding Patina,  also
had alternative minimum tax credit carryforwards of $644,000 which are available
indefinitely.  Patina had  regular net  operating  loss  carryforwards  of $70.2
million and  alternative  minimum  tax loss  carryforwards  of $35.1  million at
December 31, 1996.  Utilization  of $31.9  million  regular net  operating  loss
carryforwards and $31.6 million  alternative minimum tax loss carryforwards will
be  limited  to $5.2  million  per year as a result  of the  Acquisition.  These
carryforwards  expire from 2006 through 2011.  At December 31, 1996,  Patina had
alternative  minimum tax credit  carryforwards  of $478,000  which are available
indefinitely.  Current  income taxes shown in the financial  statements  reflect
estimates of alternative minimum taxes.

(8)      MAJOR CUSTOMERS

         In 1994 and 1995, Amoco Production  Company accounted for approximately
11% and 10%,  respectively,  of  revenues.  In 1996,  Pan Energy  accounted  for
approximately  11%  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)      COMMITMENTS AND CONTINGENCIES

         The Company rents  offices at various  locations  under   noncancelable
operating  leases.  Minimum future payments under such leases  approximate  $2.5
million for 1997, $2.4 million for 1998, $2.6 million for 1999, $2.6 million for
2000 and $1.6 million for 2001.

         In August  1995,  the  Company was sued in the United  States  District
Court of Colorado by seven  plaintiffs  purporting to represent all persons who,
at any time since January 1, 1960,  have had agreements  providing for royalties
from gas  production  in Colorado  to be paid by the  Company  under a number of
various lease provisions.  In January 1997, the judge ordered that the class not
be certified. All remaining liability under this suit was assumed by Patina upon
its  formation.  In January  1996,  GOG was also sued in a similar but  separate
class action filed in stated court.  In both suits,  the plaintiffs  allege that
unspecified  "post-production"  costs  incurred  prior  to  calculating  royalty
payments were deducted in breach of the relevant lease  provisions and that this

                                       45

<PAGE>
fact was fraudulently concealed.  The plaintiffs seek  unspecified  compensatory
and  punitive  damages  and a  declaratory  judgment  prohibiting  deduction  of
post-production  costs prior to  calculating  royalties  paid to the class.  The
Company believes that  calculations of royalties by it and GOG are and have been
proper under the relevant lease provisions,  and intends to defend these and any
similar suits vigorously.

          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  and have  breached  their  duties  to
reasonably  develop the lease.  The plaintiffs  also claim damages for fraud and
trespass,  and demand actual and punitive  damages.  Although the complaint does
not specify the amount of damages  claimed,  an earlier  letter from  plaintiffs
claimed  damages in excess of $50  million.  The Company and the other  interest
owners  have filed an answer  denying  the claims and intend to contest the suit
vigorously.

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

         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 the first
quarter of 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.
However,  given the time period which may be involved in  resolving  the matter,
the full amount of the settlement was provided for in the financial statements.

         In the second  quarter of 1996,  the Company  received  $1.5 million in
proceeds which was reflected in other income  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.

(10)  UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

         Independent  petroleum consultants directly evaluated 58%, 81%, and 99%
of proved  reserves at  December  31,  1994,  1995 and 1996,  respectively,  and
performed a detailed  review of properties  which  comprised in excess of 80% of
proved  reserve value in 1994.  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.

         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

                                       46

<PAGE>

constant.  With respect to certain properties that historically have experienced
seasonal curtailment,  the reserve estimates assume that the seasonal pattern of
such  curtailment  will continue in the future.  There can be no assurance  that
actual  production  will equal the estimated  amounts used in the preparation of
reserve projections.

         There are numerous  uncertainties  inherent in estimating quantities of
proved  reserves  and in  projecting  future rates of  production  and timing of
development expenditures. The data in the tables below represent estimates only.
Oil and gas reserve  engineering  must be recognized as a subjective  process of
estimating  underground  accumulations of oil and gas that cannot be measured in
an exact way, and  estimates of other  engineers  might differ  materially  from
those shown  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.
<TABLE>
<CAPTION>

QUANTITIES OF PROVED RESERVES -                                                          CRUDE OIL      NATURAL GAS
                                                                                         ---------      -----------
                                                                                           (MBBL)          (MMCF)
<S>                                                                                        <C>            <C>   
Balance, December 31, 1993                                                                 31,930          430,089

          Revisions                                                                          (296)        (102,871)
          Extensions, discoveries and additions                                             3,981          136,583
          Production                                                                       (4,366)         (43,809)
          Purchases                                                                         3,866           93,334
          Sales                                                                              (138)          (2,075)
                                                                                         --------         --------

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
                                                                                         ========         ========
</TABLE>

          The table above includes reserves  attributable to minority  interests
of 18.6 million BOE at December 31, 1996.

          The  Company's  interest in the Russian  joint  venture  (Permtex)  is
accounted for under the equity method.  At December 31, 1994, 1995 and 1996, the
Company's equity in Permtex proved reserves was 8.0 million BOE, 7.8 million BOE
and 8.6  million  BOE,  respectively.  These  amounts  are not  included  in the
quantities above.



                                       47

<PAGE>

<TABLE>
<CAPTION>

PROVED DEVELOPED RESERVES -                                                               CRUDE           NATURAL
                                                                                           OIL              GAS
                                                                                        ---------        ---------
                                                                                         (MBBL)            (MMCF)
<S>                                                                                        <C>             <C>   
December 31, 1993                                                                          18,032          268,349
                                                                                        =========        =========

December 31, 1994                                                                          26,104          353,930
                                                                                        =========        =========

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

December 31, 1996                                                                          31,869          443,441
                                                                                        =========        =========
</TABLE>

<TABLE>
<CAPTION>

STANDARDIZED MEASURE -                                                                        DECEMBER 31,
                                                                                      ----------------------------
                                                                                          1995             1996
                                                                                      -----------      -----------
                                                                                             (IN THOUSANDS)
<S>                                                                                   <C>              <C>
Future cash inflows                                                                   $ 1,037,363      $ 3,144,813

Future costs:
          Production                                                                     (374,516)        (781,550)
          Development                                                                     (57,959)        (233,617)
                                                                                      -----------      -----------

Future net cash flows                                                                     604,888        2,129,646

Undiscounted income taxes                                                                 (63,248)        (540,520)
                                                                                      -----------      -----------

After tax net cash flows                                                                  541,640        1,589,126

10% discount factor                                                                      (210,534)        (650,534)
                                                                                      -----------      -----------

Standardized measure                                                                  $   331,106      $   938,592
                                                                                      ===========      ===========
</TABLE>


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

           At  December  31,  1995 and  1996,  the  Company's  equity in the net
present value of Permtex  proved  reserves was $10.6 million and $25.8  million.
These amounts are not included in the standardized measure above.

                                       48

<PAGE>
<TABLE>
<CAPTION>


CHANGES IN STANDARDIZED MEASURE -
                                                                            YEAR ENDED DECEMBER 31,
                                                               ------------------------------------------------
                                                                   1994                1995             1996
                                                               -----------         -----------      -----------
                                                                                  (IN THOUSANDS)
<S>                                                            <C>                 <C>              <C>
Standardized measure, beginning of year                        $   340,518         $   361,682      $   331,106

Revisions:
         Prices and costs                                          (73,330)             18,975          528,525
         Quantities                                                (42,260)            (30,495)          10,915
         Development costs                                         (12,995)             (2,806)         (13,027)
         Accretion of discount                                      34,052              36,168           46,045 (a)
         Income taxes                                                2,195              16,249         (242,536)
         Production rates and other                                 (9,506)            (29,991)          11,052
                                                               -----------         -----------      -----------

         Net revisions                                            (101,844)              8,100          340,974

Extensions, discoveries and additions                               68,002              18,171          111,797
Production                                                         (97,330)            (96,232)        (146,257)
Future development costs incurred                                   99,175              43,551           18,400
Purchases                                                           55,072              31,142          330,225 (a)
Sales                                                               (1,911)            (35,308)         (47,653)
                                                               -----------         -----------      -----------

Standardized measure, end of year                              $   361,682         $   331,106      $   938,592
                                                               ===========         ===========      ===========
<FN>

(a)      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.

</FN>
</TABLE>


                                       49

<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 28.

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

           3.  Exhibits.

   4.1.1   -   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)
 
   4.1.2   -   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).

   4.1.3   -
               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).

   4.1.4   -   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 Form 10-Q for the quarter-ended
               June 30, 1993 (File No. 1-10509).

   4.1.5   -   Indenture  dated as of May 1, 1994  between  the  Registrant  and
               Texas Commerce Bank National Association relating to Registrant's
               7% Convertible  Subordinated  Notes due 2001 --  incorporated  by
               reference  from Exhibit  4.1.5 to  Registrant's  Annual Report on
               Form  10-K  for the  year  ended  December  31,  1994  (File  No.
               1-10509).

   4.1.6   -   Certificate of Designations of the Registrant's $6.00 Convertible
               Exchangeable  Preferred  Stock --  incorporated by reference from
               Exhibit 3.1.5 to the Registrant's Form 10-Q for the quarter-ended
               June 30, 1993 (File No. 1-10509)

  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  Restated 1989 Stock Option Plan --  incorporated by
               reference  from  Exhibit  10.2.1  to the  Registrant's  Quarterly
               Report on Form 10-Q for the quarter-ended June 30, 1992 (File No.
               1- 10509).

  10.3     -   Registrant's  Deferred  Compensation  Plan for Select  Employees,
               adopted  effective June 1, 1994 -- incorporated by reference from
               Exhibit 10.3 to  Registrant's  Annual Report on Form 10-K for the
               year ended December 31, 1994 (File No. 1-10509)

  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).

                                       50
<PAGE>

  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.*

  10.9.1   -   Promissory  Note dated  December  30,  1996 from  Edward T. Story
               payable to the order of SOCO International Holdings, Inc.*

  10.9.2   -   Promissory  Note dated  December  30,  1996 from  Edward T. Story
               payable to the order of SOCO International Operations, Inc.*

  10.10    -   Warrant  dated  February  8, 1994 issued by  Registrant  to Union
               Pacific  Resources  Company --  incorporated  by  reference  from
               Exhibit 10.10 to the Registrant's  Annual Report on Form 10-K for
               the year ended December 31, 1993 (File No. 1-10509).

  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).

  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.*

  10.12    -   Severance  Agreement and Release dated  November 14, 1995 between
               Registrant and John A. Fanning --  incorporated by reference from
               Exhibit 10.12 to  Registrant's  Annual Report on Form 10-K of the
               year ended December 31, 1995 (File No. 1-10509).

                                       51
<PAGE>


  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).

  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.*

  23.1     -   Consent of Arthur Andersen LLP.*

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

  23.3     -   Consent of Ryder Scott Company Petroleum Engineers.*

  27       -   Financial Data Schedule.*

  99.1     -   Reserve letter from Netherland,  Sewell & Associates,  Inc. dated
               February  5, 1997 to the Snyder Oil  Corporation  interest  as of
               December 31, 1996*

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

  99.3     -   Reserve letter from Ryder Scott Company Petroleum Engineers dated
               February  5,  1997 to the  SOCO  Offshore,  Inc.  interest  as of
               December 31, 1996*

      (b)      No reports on Form 8-K in the fourth quarter of 1996.

      * Filed herewith.

                                       52
<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     March 10, 1997
------------------------  (Principal Executive Officer)
John C. Snyder          


/S/ ROGER W. BRITTAIN     Director                               March 10, 1997
------------------------
Roger W. Brittain


/S/ JOHN A. HILL          Director                               March 10, 1997
------------------------
John A. Hill


/S/ WILLIAM J. JOHNSON    Director                               March 10, 1997
------------------------
William J. Johnson


/S/ B. J. KELLENBERGER    Director                               March 10, 1997
------------------------
B. J. Kellenberger


/S/ JAMES E. MCCORMICK    Director                               March 10, 1997
------------------------
James E. McCormick

/S/ ALFRED M. MICALLEF    Director                               March 10, 1997
------------------------
Alfred M. Micallef


/S/ EDWARD T.  STORY      Director and                           March 10, 1997
------------------------  Vice President - International
Edward T.  Story


/S/ JAMES H. SHONSEY      Vice President - Finance               March 10, 1997
------------------------  (Principal Financial and
James H. Shonsey           Accounting Officer)

                                       53
<PAGE>

<TABLE>
                                                                                                      SCHEDULE I

                                      SNYDER OIL CORPORATION (PARENT COMPANY)
                                            CONSOLIDATED BALANCE SHEETS
                                                  (IN THOUSANDS)
<CAPTION>
                                                                                           DECEMBER 31,
                                                                                  -------------------------------
                                                                                      1995               1996
                                                                                  ------------       ------------
                                                      ASSETS
<S>                                                                               <C>                <C>
Current assets
     Cash and equivalents                                                         $     27,263       $     21,769
     Accounts receivable                                                                29,259             38,968
     Inventory and other                                                                11,769              9,755
                                                                                  ------------       ------------
                                                                                        68,291             70,492
                                                                                  ------------       ------------

Investments                                                                             33,220            245,610
                                                                                  ------------       ------------

Oil and gas properties, successful efforts method                                      675,961            328,649
     Accumulated depletion, depreciation and amortization                             (240,744)           (91,902)
                                                                                  ------------       ------------
                                                                                       435,217            236,747
                                                                                  ------------       ------------

Gas facilities and other                                                                30,506             16,558
     Accumulated depreciation and amortization                                         (11,741)            (4,251)
                                                                                  ------------       ------------
                                                                                        18,765             12,307
                                                                                  ------------       -------------
                                                                                  $    555,493       $    565,156
                                                                                  ============       ============

                                       LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
     Accounts payable                                                             $     36,353       $     36,804
     Accrued liabilities                                                                26,096             25,534
                                                                                  ------------       ------------
                                                                                        62,449             62,338
                                                                                  ------------       ------------

Senior debt                                                                            150,001             93,731
Convertible subordinated notes                                                          84,058             80,748

Deferred taxes payable                                                                  -                   9,034
Other noncurrent liabilities                                                            20,016             18,233

Minority interest                                                                        3,601              6,404
Commitments and contingencies

Stockholders' equity
     Preferred stock,  $.01 par,  10,000,000 shares  authorized,
         6% Convertible preferred stock, 1,035,000 and 1,033,500
         shares issued and outstanding                                                      10                 10
     Common stock, $.01 par, 75,000,000 shares authorized,
         31,430,227 and 31,456,027 issued                                                  314                315
     Capital in excess of par value                                                    265,911            260,221
     Retained earnings (deficit)                                                       (29,001)            25,711
     Common stock held in treasury, 134,191 and 250,000 shares at cost                  (2,457)            (3,510)
     Unrealized foreign currency translation gain                                          380             -
     Unrealized gain on investments                                                        211             11,921
                                                                                  ------------       ------------
                                                                                       235,368            294,668
                                                                                  ------------       ------------
                                                                                  $    555,493       $    565,156
                                                                                  ============       ============

                             See "Notes to Consolidated Financial Statements" of the 
                Snyder Oil Corporation Consolidated Financial Statements included in this report.
</TABLE>

                                       54
<PAGE>
<TABLE>
                                                                                                      SCHEDULE I

                                      SNYDER OIL CORPORATION (PARENT COMPANY)
                                       CONSOLIDATED STATEMENTS OF OPERATIONS
                                       (IN THOUSANDS EXCEPT PER SHARE DATA)
<CAPTION>

                                                                                  YEAR ENDED DECEMBER 31,
                                                                       --------------------------------------------
                                                                          1994             1995             1996
                                                                       ----------       ----------       ----------
<S>                                                                    <C>              <C>              <C>
Revenues
   Oil and gas sales                                                   $ 137,858        $ 144,608        $ 121,967
   Gas transportation, processing and marketing                          107,247           38,256           17,655
   Gains on sales of equity interests in investees                         9,747            2,183           69,343
   Gains on sales of properties                                            1,969           12,254            8,786
   Equity in earnings of Patina                                            -                -                1,554
   Other                                                                   5,507            4,859            6,320
                                                                       ---------        ---------        ---------

                                                                         262,328          202,160          225,625
                                                                       ---------        ---------        ---------
Expenses
   Direct operating                                                       46,267           52,486           37,736
   Cost of gas and transportation                                         94,177           29,374           15,020
   Exploration                                                             6,505            8,033            4,094
   General and administrative                                             12,853           17,680           13,129
   Interest and other                                                     12,463           27,001           16,218
   Litigation settlement                                                   -                4,400            -
   Loss on sale of subsidiary interest                                     -                -               15,481
   Depletion, depreciation and amortization                               70,770           76,378           49,032
   Property impairments                                                    5,783           27,412            2,753
                                                                       ---------        ---------        ---------

Income (loss) before taxes and minority interest                          13,510          (40,604)          72,162
                                                                       ---------        ---------        ---------

Provision (benefit) for income taxes
   Current                                                                 -                   25               33
   Deferred                                                                  967           (1,370)           4,313
                                                                       ---------        ---------        ---------
                                                                             967           (1,345)           4,346
                                                                       ---------        ---------        ---------

Minority interest                                                           (171)            (572)          (4,866)
                                                                       ---------        ---------        ---------

Net income (loss)                                                      $  12,372        $ (39,831)       $  62,950
                                                                       =========        =========        =========

Net income (loss) per common share                                     $     .07        $   (1.53)       $    1.81
                                                                       =========        =========        =========

Weighted average shares outstanding                                       23,704           30,186           31,308
                                                                       =========        =========        =========


                             See "Notes to Consolidated Financial Statements" of the
                Snyder Oil Corporation Consolidated Financial Statements included in this report.
</TABLE>
                                       55

<PAGE>
<TABLE>
                                                                                                       SCHEDULE I
                                      SNYDER OIL CORPORATION (PARENT COMPANY)
                                       CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                  (IN THOUSANDS)
<CAPTION>
                                                                                YEAR ENDED DECEMBER 31,
                                                                     ---------------------------------------------
                                                                         1994             1995             1996
                                                                     -----------      -----------      -----------
<S>                                                                  <C>              <C>               <C>
Operating activities
   Net income (loss)                                                 $    12,372      $   (39,831)       $   62,950
   Adjustments to reconcile net income (loss) to net
      cash provided by operations
          Amortization of deferred credits                                (2,986)          (2,511)            (966)
          Gains on sales of investments                                   (9,747)            (809)         (68,343)
          Gains on sales of properties                                    (1,969)         (12,254)          (8,786)
          Equity in (earnings) losses of unconsolidated subsidiaries      (1,355)           1,319           (1,975)
          Exploration expense                                              6,505            8,033            4,094
          Loss on sale of subsidiary interest                               -                -              15,481
          Depletion, depreciation and amortization                        70,770           76,378           49,032
          Property impairments                                             5,783           27,412            2,753
          Deferred taxes                                                     967           (1,370)           4,313
          Minority interest                                                  171              572            4,866
          Changes in current and other assets and liabilities
            Decrease (increase) in
               Accounts receivable                                        11,024            7,142          (12,025)
               Inventory and other                                        (9,241)           3,617            3,583
            Increase (decrease) in
               Accounts payable                                            1,901           (8,521)           4,502
               Accrued liabilities                                         1,841            5,165              (69)
               Other liabilities                                             361            4,779             (346)
                                                                     -----------      -----------      -----------
          Net cash provided by operations                                 86,397           69,121           59,064
                                                                     -----------      -----------      -----------

Investing activities
   Acquisition, development and exploration                             (237,879)         (92,353)         (93,368)
   Purchase of controlling interest in subsidiary                         (6,645)            -               -
   Proceeds from investments                                               5,019           14,786            1,635
   Outlays for investments                                                (8,804)            -              (9,013)
   Proceeds from sales of properties                                       2,806          109,988           72,510
                                                                     -----------      -----------      -----------
          Net cash realized (used) by investing                         (245,503)          32,421          (28,236)
                                                                     -----------      -----------      -----------

Financing activities
   Issuance of common                                                      1,157              688            1,523
   Increase (decrease) in indebtedness                                   187,138          (86,193)         (12,814)
   Debt issuance costs                                                    (2,855)            -               -
   Dividends                                                             (16,721)         (14,056)         (14,411)
   Deferred credits                                                        2,356            3,549               62
   Repurchase of stock                                                    (1,149)            -              (7,186)
   Repurchase of subordinated notes                                         -                -              (3,496)
                                                                     -----------      -----------      -----------
          Net cash realized (used) by financing                          169,926          (96,012)         (36,322)
                                                                     -----------      -----------      -----------

Increase in cash                                                          10,820            5,530           (5,494)
Cash and equivalents, beginning of year                                   10,913           21,733           27,263
                                                                     -----------      -----------      -----------
Cash and equivalents, end of year                                    $    21,733      $    27,263      $    21,769
                                                                     ===========      ===========      ===========

Noncash investing and financing activities
   Gas plant capital lease                                           $    21,000             -                -
   Acquisition of properties and stock via stock issuances                  -         $    13,032      $     3,693
   Acquisition of properties recorded as senior debt                        -                -         $    31,730
   Acquisition via subsidiary stock issuance                                -                -         $   115,067

                             See "Notes to Consolidated Financial Statements" of the 
                Snyder Oil Corporation Consolidated Financial Statements included in this report.
</TABLE>

                                       56