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


                                  UNITED STATES

                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                                   ----------
(Mark one)                         FORM 10-K/A
                                 Amendment No. 1

 [X]               ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 1998

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

                         Commission file number 1-10509
                                   ----------

                             SNYDER OIL CORPORATION
             (Exact name of registrant as specified in its charter)
          
            Delaware                                      75-2306158
(State or other jurisdiction of                          (IRS Employer
 incorporation or organization)                       Identification No.)
           
          

         777 Main Street                                      76102
        Fort Worth, Texas                                  (Zip Code)
(Address of principal executive offices)

        Registrant's telephone number, including area code (817) 338-4043

           Securities registered pursuant to Section 12(b) of the Act:
    
    

                                                   Name of each exchange
      Title of each class                           on which registered
 -------------------------------           -----------------------------------
         
         Common Stock                             New York Stock Exchange
 Preferred Stock Purchase Rights                  New York Stock Exchange
           

           Securities registered pursuant to Section 12(g) of the Act:
                                      None
                                (Title of class)
       
         Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days.
                                            Yes  X     No 
                                               -----     -----        
         Indicate by check mark if disclosure of delinquent  filers  pursuant to
Item 405 of Regulation S-K is not contained  herein,  and will not be contained,
to the best of  registrant's  knowledge,  in  definitive  proxy  or  information
statements  incorporated  by  reference  in Part  III of this  Form  10-K or any
amendment to this Form 10-K. [ ]

     Aggregate market value of the common stock held by non-affiliates 
      of the registrant as of February 26, 1999 ....................$321,653,346
     Number of shares of common stock outstanding
      as of February 26, 1999.........................................33,364,567

                       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,
1999.

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


<PAGE>   2


                                                    

                             SNYDER OIL CORPORATION

                           Annual Report on Form 10-K
                                December 31, 1998


                                     PART I


ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

GENERAL

         Snyder Oil  Corporation  is an  independent  oil and gas  company  with
principal  operations in domestic  natural gas exploration  and production.  The
Company's primary  properties are located in the Rocky Mountain region, the Gulf
of Mexico and northern Louisiana.

         The Company  develops  reserves  which it has  acquired  or  discovered
through its  exploration  program,  and sells the oil and gas which it produces.
The Company has  concentrated  its exploration and development  efforts over the
past year to emphasize  natural gas reserve  growth.  During 1998, 90 percent of
the  Company's  reserve  additions  were natural  gas.  This has  increased  the
percentage of natural gas reserves to 82 percent, versus 78 percent in 1997.

         During 1998, the Company generated  revenues of $141.1 million and cash
flows from operations of $75.2 million. Average daily production during 1998 was
83 percent gas or 154.0  million  cubic feet of gas and 5,231 barrels of oil per
day. At December  31,  1998,  the Company had proved  reserves of 100.3  million
barrels  of oil  equivalent  with a  pretax  present  value of  $365.6  million,
assuming a ten percent discount rate with constant  pricing and costs.  Year end
reserves were 82 percent natural gas and 18 percent oil.

         In addition to its  domestic  operations,  the Company also owns common
stock in two international  exploration and production  companies,  Cairn Energy
plc and SOCO  International plc. Both companies' shares are listed on the London
Stock Exchange. Cairn shares trade under the symbol "CNE" and SOCO International
trades  under the  symbol  "SIA."  The  Company  owns  about six  percent of the
outstanding  shares of Cairn and about 16 percent of the  outstanding  shares of
SOCO  International.  The market value of these two securities was $24.0 million
at year end 1998 and $143.1 million at year end 1997.

         In October  1997,  the Company sold its 74 percent  equity  interest in
Patina Oil and Gas Corporation.  This transaction generated $127 million in cash
while  removing  approximately  $170  million of Patina debt from the  Company's
consolidated balance sheet.

         On January 13, 1999,  the Company and Santa Fe Energy  Resources,  Inc.
signed an agreement to merge the Company into Santa Fe Energy  Resources to form
a single  company  to be named  "Santa Fe  Snyder  Corporation."  The  merger is
subject to shareholder  approval at a special meeting expected to be held during
the second quarter of 1999. If the Company's shareholders approve the merger and
all other  conditions to the merger are met, each share of the Company's  common
stock would be converted  into 2.05 shares of Santa Fe Energy  Resources  stock.
Concurrently  with  signing  the  merger  agreement,  the  Company  amended  its
shareholder  rights  agreement  to  exempt  the  merger  from  the  scope of the
agreement.  As a result,  shareholders  of the Company will have no rights under
the shareholder  rights  agreement  relating to the merger.  In particular,  the
rights will not be distributed or become exercisable.

OPERATIONS

Overview

         The  Company's  operations  are focused in three core areas - the Rocky
Mountains,  the Gulf of Mexico and  northern  Louisiana.  The  Company  has been
active in the Rockies for more than 20 years and has developed several large gas

                                       2
                                      
<PAGE>  3

development  projects,  which  has  allowed  the  Company  to add  reserves  and
production at low development  costs. The Rocky Mountain  reserves  represent 78
percent of the  Company's  year end  reserves  and 63  percent of the  reserves'
pretax present value assuming a ten percent  discount rate with year end pricing
and costs ("Pretax PV10 Value"). The Pretax PV10 value is computed in accordance
with the method established by Statement of Financial  Accounting  Standards No.
69 for the standardized  measure of discounted future net cash flows relating to
proved oil and gas reserve  quantities,  with the exception of future income tax
expenses.  The Pretax PV10 values are before  consideration of future taxes. See
Note 14, Unaudited  Supplemental Oil and Gas Reserve  Information,  in this Form
10-K for the Company's  standardized measure of discounted future net cash flows
after tax.

         The Company began its activities in the Gulf of Mexico in 1994.  During
1995 and 1996,  the Company sold  portions of its gas  development  projects and
most of its  properties  outside of its core areas in order to  reinvest  in its
Gulf projects.  This  repositioning  process  allowed the Company to balance its
reserves and production  between the Rocky Mountains and the Gulf of Mexico. The
Company's Gulf of Mexico reserves  comprise 19 percent of the Company's year end
quantities and 33 percent of the reserves'  Pretax PV10 Value.  During 1998, the
Company's  production  was almost equal from the Rockies and Gulf of Mexico core
areas.

         The third  core area is in  northern  Louisiana,  where the  Company is
currently focused on a highly prospective exploration effort targeting potential
Troy Lime reef production.  This exploration play represents the first step in a
long-term  program in  northern  Louisiana  to exploit the  Company's  extensive
mineral position based on exclusive 3-D seismic data.

         During  1998,  the  Company  increased  its  reserves  by  30  percent,
replacing 382 percent of its 1998 production. Finding and development costs from
all  sources,  including  revisions,  were $4.44 per  barrel of oil  equivalent.
Production from core areas increased 26 percent in 1998 from 1997.

         Summary  information  at December  31,  1998  regarding  the  Company's
projects is set forth in the following table. (Abbreviated terms in the captions
are explained on page eight.)
<TABLE>
<CAPTION>
                                                           Proved Reserve Quantities    
                             Gross         Net        ------------------------------------     Pretax PV10 Value 
                           Producing   Undeveloped       Crude      Natural        Oil        --------------------        
                             Wells        Acres          Oil          Gas       Equivalent     Amount     Percent 
                           ---------   -----------    ---------    -------      ----------    ---------  ---------
                                                        (MBbl)      (MMcf)       (MBOE)         (000)
<S>                            <C>        <C>           <C>        <C>           <C>          <C>            <C>
Rocky Mountains:
   Washakie (WY)                 225       92,808        1,898     183,816        32,533      $ 115,254       31
   Wind River (WY)                98       61,182(a)     2,006     125,355        22,898         78,799       22
   Northern Wyoming              898         -          13,121         634        13,227         11,115        3
   Piceance (CO)  (b)             92       46,432          208      49,409         8,443         22,947        6
   Uinta (UT)                     97       68,947          168       3,769           796          2,475        1
   Big Horn (WY)                   1       82,239           18         520           105            481      -
   Deep Green River (WY)        -          54,258         -           -             -              -         - 
                            --------    ---------      -------     -------       -------      ---------   ------
   Rocky Mountain Region       1,411      405,866       17,419     363,503        78,002        231,071       63
                            --------    ---------      -------     -------       -------      ---------   ------

Gulf of Mexico:
   Main Pass Area                 21       10,111          765      96,968        16,927        112,967       31
   Other                          18       22,255          242      14,216         2,611          6,602        2
                            --------    ---------      -------     -------       -------      ---------   ------
   Total Gulf of Mexico           39       32,366        1,007     111,184        19,538        119,569       33

North Louisiana                   14(c)   373,873(d)        67      13,295         2,283         12,956        3
Other                             84        1,373           49       2,771           511          2,024        1
                            --------    ---------      -------     -------       -------      ---------   ------
   Southern Region               137      407,612        1,123     127,250        22,332        134,549       37
                            --------    ---------      -------     -------       -------      ---------   ------

   Total Company               1,548      813,478       18,542     490,753       100,334      $ 365,620      100    
                            ========    =========      =======     =======       =======      =========   ======
<FN>
(a)      Excludes 16,500 net acres under option.
(b)      Interests were sold subsequent to year end.
(c)      Excludes royalty interests in 101 wells.
(d)      Excludes 128,000 net acres under option.
</FN>
</TABLE>

                                       3
                                     
<PAGE>  4

ROCKY MOUNTAINS

         The Rocky Mountain region  represents 78 percent of the Company's total
year end  reserves  and 64  percent of Pretax  PV10  Value.  At year end,  Rocky
Mountain  proved  reserves  totaled  363.5  billion  cubic  feet of gas and 17.4
million  barrels of oil, a 38 percent  increase  from 1997.  The  Company has an
interest  in 1,411  total  wells,  417 of which  are  operated.  Rocky  Mountain
production  represented  49 percent  of the  Company's  total  1998  production.
Production  from this region  increased 15 percent in 1998 to an average of 66.0
million cubic feet of gas and 4.0 thousand barrels of oil per day.

         The Company  drilled 74 Rocky  Mountain wells in 1998, of which 71 were
development and three were  exploratory,  continuing the long-term growth of the
region.  The 1998 capital program in the Rocky Mountains  primarily was directed
to the Company's gas development projects in the Washakie and Wind River Basins.

Washakie Basin

         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,  have been one of the Company's most significant
assets since the  mid-1980s.  Production  from this  prolific  basin during 1998
averaged  35.0  million  cubic feet of gas and 400 barrels of oil per day, or 20
percent of the Company's 1998 production.

         The Company  currently  operates  184 wells in the  Washakie  Basin and
holds hundreds of potential drilling  locations.  The Company holds interests in
147,573  gross and  129,655  net acres in this area of which only 28 percent has
been developed.  In the currently  producing  wells,  the Company has an average
working  interest  of 71  percent  and an average  net  revenue  interest  of 58
percent.

         During 1998, the Company  continued to develop  Mesaverde  sands in the
Washakie Basin; 43 wells were put on sales in 1998,  seven of which were drilled
in late 1997.  These wells were completed at depths ranging from 8,000 to 11,500
feet.  Three  wells were in progress  at year end.  Significant  portions of the
Washakie area are restricted by a currently pending  Environmental  Impact Study
("EIS").  Therefore,  the 1998  development  program  was  focused on  locations
outside the EIS  restricted  area.  The Record of Decision  covering  the EIS is
expected to be issued in the second half of 1999.  The Company  expects to drill
25 to 35 wells in this area in 1999.

Wind River Basin

         The Company owns an interest in four contiguous areas in the Wind River
Basin: the Riverton Dome Field,  the Beaver Creek Unit, a 33,000-acre  option on
Tribal lands,  and a 64,000-acre  undeveloped  lease block. The Company has a 50
percent working interest in the option lands and in the lease block.

         Total production at year end from the Wind River Basin was 19.6 million
cubic feet of gas and 460 barrels of oil per day, or 12 percent of the Company's
year end production.

         The  Riverton  Dome  Field  primarily  produces  natural  gas  from the
Frontier,  Muddy and Phosphoria  formations and oil from the Tensleep formation.
The  Company  operates  all 34 wells in this  field and has an  average  working
interest  of 88 percent and net  revenue  interest  of 76 percent.  Sweet gas is
processed at a  Company-owned  plant in the field,  and sour gas is processed at
the  Company's  Beaver Creek plant,  which is located  immediately  south of the
field.

         The  Company  drilled  four Muddy wells in the  Riverton  Dome Field in
1998.  The Muddy  formation  is found at depths  between  10,000 to 11,000 feet.
Initial  production  rates from the Muddy generally  average three million cubic
feet of gas per day. The Company expects to drill five  additional  wells in the
Muddy in 1999. If the results are  consistent  with the Company's 3-D imaging of
the Muddy, the number of wells drilled could increase.

         The Beaver Creek Unit is  contiguous  with the  southern  border of the
Riverton  Dome Field.  In May,  1998,  the Company  acquired 75 percent of Amoco
Production  Company's  ("Amoco")  interest  in the  Beaver  Creek  Unit  and two
associated gas plants.  This transaction  included an exchange for the Company's
interest in the Jonah Field,  which was part of the Company's  properties in the

                                       4

<PAGE>   5

Deep Green River Basin project.  The Company owns an average working interest of
67 percent in the two gas processing  facilities and 64 producing  wells with an
average net revenue  interest of 58 percent.  This field  produces  gas from the
Frontier/Dakota, Phosphoria and Cody formations while oil production is from the
Tensleep and Madison formations. Three wells were spud in 1998. One well was put
on sales and two wells were in progress at year end 1998. The Company also began
a recompletion  and deepening  program in the  Frontier/Dakota  and a horizontal
drilling program in the Tensleep during 1998.

         The Company spud the North Alkali Butte 10-32 well in August 1998. This
exploratory well is the first test on the Tribal option acreage block and should
be completed in February 1999.  Three zones tested  productive and should be put
on sales in the first quarter of 1999.

Deep Green River Basin

         In May, the Company  exchanged  its interest in the Jonah Field,  which
represented  a  significant  portion of its Deep Green River Basin assets for 75
percent  of  Amoco's  assets in the Beaver  Creek  Unit.  Under the terms of the
agreement,  the Company also received  Amoco's  interest in the Deep Green River
Basin acreage  outside the Jonah Field.  The Company  holds  interests in 63,222
gross and  54,258  net  undeveloped  acres in this  project.  The  Company  also
retained  the deep rights  below the  currently  producing  horizon in the Jonah
Field.  These deep  rights  covering  23,568  gross and 10,625 net acres are not
included in the undeveloped acreage amounts.

         During the early part of the year, the Company continued development of
the fluvial  Lance  sands in the deep  portion of the Jonah  Field.  The Company
participated  in eight wells during 1998,  two of which were drilled in the last
half of the year on  acreage  remaining  after  the  trade.  The first  well,  a
six-mile step-out to the south of the Jonah Field, was drilled in July to test a
2-D seismic velocity anomaly in the Ericson  formation.  The Company decided not
to complete the well and turned  operations  over to a partner.  The second well
was drilled in November to test a seismic defined fault block and a low-velocity
anomaly to the west of the main Jonah Field.  The well is temporarily  abandoned
and will be plugged in 1999.

Piceance Basin

         The Company  operated the Hunter Mesa,  Grass Mesa and the Divide Creek
Units in the southeast  portion of the Piceance Basin through January 1999, when
the Company  finalized  the sale of its  interest in the Piceance  project.  The
$28.8 million sale included the Company's  remaining 55 percent interest and all
gathering  and   transportation   facilities  located  within  the  area.  Total
production  at year end from the Piceance  Basin was eight million cubic feet of
gas and 61 barrels of oil per day.

         During 1998,  the Company  participated  in eleven new wells to develop
and further  delineate  the fields;  13 wells,  including two in progress at the
beginning of 1998 were put on sales.  At year end 1998,  there were 92 producing
wells, 87 of which were operated by the Company.

Big Horn Basin

         The  Company  has  assembled  a  158,964  gross  and  82,239  net  acre
undeveloped   lease  block  which  is  prospective  for  Frontier,   Muddy,  and
Lance/Mesaverde formations. Two Frontier wells are planned in 1999.

Uinta Basin

         In the Uinta Basin,  the Company  holds  interests in 105,991 gross and
77,358 net acres. During 1998, the Company participated in drilling one operated
well in the Horseshoe Bend area. The well, drilled to test the Green River zone,
was  unproductive.  During  the  last  half of 1996,  local  oil  prices,  which
historically  had been at a premium to West Texas  Intermediate  ("WTI")  posted
prices, deteriorated and Uinta Basin production currently sells at a discount to
WTI  prices.  With  little  improvement  expected  in the near term,  additional
development drilling was curtailed until oil prices in the area improve. At year
end, the Company had interests in 97 producing  wells, 47 of which were operated
by the Company.

                                       5

<PAGE>   6

Northern Wyoming

         The Company holds interests in two large, mature oil fields in northern
Wyoming - the Hamilton Dome and Salt Creek  Fields.  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.  These two fields comprise 71
percent of the  Company's  oil  reserves  at year end 1998 and 58 percent of the
Company's  oil  production  in 1998.  At year  end,  the oil price  received  at
Hamilton Dome was $1.20 less than the WTI  reference  price and the oil price at
Salt Creek was $1.44 more than the WTI reference price.

Gulf of Mexico

         At year end,  total  proved  reserves  in the Gulf of Mexico were 111.2
billion  cubic  feet  of gas  and  1.0  million  barrels  of  oil,  representing
approximately  19 percent of total  year end  reserves  and 33 percent of Pretax
PV10 Value.  The Company has an interest in 39 wells,  36 of which are operated.
Production in 1998  increased 40 percent over 1997 to an average of 82.8 million
cubic  feet  of gas and  1,140  barrels  of oil  per  day.  The  Gulf of  Mexico
production  represented  48 percent of the Company's 1998 total  production,  of
which 89 percent was concentrated in the Main Pass area.

         During  1998,  the  Company  drilled 14 wells in the Gulf of Mexico and
achieved  a 50 percent  exploratory  success  rate and a 75 percent  development
success rate.  Two  hurricanes and two tropical  storms  substantially  impacted
operations in the Gulf during  September and October,  including a direct hit by
Hurricane  Georges  to the Main Pass  area.  Although  the  Company's  platforms
suffered no structural  harm,  repairs to damaged  engines and  compressors  and
pipeline disruptions continued into the fourth quarter.

         During  1998,  two  objectives  of the  capital  program in the Gulf of
Mexico were to develop  internal  exploration and  development  prospects and to
expand  operations beyond the continental shelf into deeper water. To accomplish
the first  objective,  the Company  invested $8.7 million  acquiring 25,000 line
miles of 2-D and 2,000 square miles of 3-D seismic  coverage  over 203 blocks in
the Gulf. The Company also leased three blocks at Federal lease sales during the
year.  Currently,  the Company is working on six leads and has 12  prospects  in
inventory.

         The Company had mixed results in its effort to expand  operations  into
deeper waters. The Company participated in drilling seven deepwater wells during
the year and found hydrocarbons in economic quantities at three locations in its
Specter and Leo  prospects.  At East Breaks 208,  Garden  Banks 269 and 625, and
Green  Canyon  179,  the  Company  reported  four  dry  holes at a cost of $26.8
million.  Although  the costs of these  four  wells  were only 14 percent of the
Company's 1998 capital program, the dry hole expense accounted for 70 percent of
the Company's reported loss for 1998.

         In 1999, the Company will continue focusing  acquisition efforts in the
Gulf  and  evaluating   existing   properties  for  additional   exploratory  or
development potential.

Busch and Pabst Fields, Main Pass 255/259

         The Busch  (Main Pass 255) and Pabst (Main Pass 259) Fields are located
in the Main Pass/Viosca  Knoll area offshore  Louisiana and Alabama.  Production
during 1998  averaged  56.7 million cubic feet per day of gas and 460 barrels of
oil per day, representing 32 percent of the Company's 1998 production.  In 1998,
the Company  continued  development and exploration work around this key area by
drilling one successful development well and one exploratory well. The discovery
well in Main Pass 260 tested 26 million  cubic feet of gas and 2,745  barrels of
oil per day from a  mid-Miocene  Tex W sand  series.  The well is expected to be
subsea completed and tied back to the Pabst platform in 1999.

         The  Company's  interest in the Busch and Pabst leases was subject to a
reversionary interest upon payout of the original drilling program expenditures.
As a result of program  payout in 1998,  the Company's  interest in these fields
was reduced  from a 61.8  percent  working  interest to a 52.4  percent  working
interest,  and the net revenue  interest  was reduced  from 43.3 percent to 36.8
percent.

                                       6

<PAGE>   7

Ingrid Field, Main Pass 261

         The  Company  has a 50 percent  working  interest  and a 37 percent net
revenue  interest in the Ingrid Field,  where proved reserves were discovered in
1996 in several Tex W sands at approximately 11,000 to 13,000 feet.

         Most of the Company's  development program in the first quarter of 1998
focused  on  setting  the  platform  at the Ingrid  Field and  bringing  the two
discovery wells on production.  In the second quarter,  one exploratory well was
successfully  drilled and  completed  in a  shallower  horizon.  Two  additional
development wells were drilled and brought on production,  although the reserves
from one well depleted rapidly.

         Initial  production  from  the  Main  Pass  261  platform  began  after
production  facilities were completed in March, with initial volumes transported
on the Viosca Knoll Gathering System.  In August,  the connection of the 24-inch
Transcontinental Gas Pipeline ("Transco") to the Main Pass 259 and 261 platforms
gave the Company  additional  transportation  capacity and access to  additional
markets for its gas. Average Main Pass natural gas price realizations  increased
an  estimated  25 to 30  cents  per Mcf in the  fourth  quarter  because  of the
improved markets provided by the Transco pipeline.  The Company expects that the
price  realizations  in the future will be four to five cents more  favorable on
Transco than Viosca Knoll.

         The  Ingrid  Field  accounted  for 15 percent  of the  Company's  total
production   during  the  third  quarter.   Production   subsequently   declined
significantly  and the Company concluded that the lower reservoirs in two of the
wells were smaller than originally estimated. The Company plans to produce these
lower  reservoirs  until they are  depleted and then  recomplete  to the larger,
primary reservoirs uphole. It is anticipated that the recompletions may not take
place  until  2000.  At year end,  the  reserves  associated  with  these  lower
secondary  reservoirs  represent  less than one percent of the  Company's  total
reserves  but will  limit  future  production  rates  until  the  upper  primary
reservoirs are recompleted.

Specter Prospect, Viosca Knoll 779/780/823/824

         The  Company  participated  with a 12  percent  working  interest,  ten
percent  net  revenue  interest,  in the  Specter  Prospect,  operated  by Shell
Offshore,  Inc.  The first well,  Viosca  Knoll 780 #4 was drilled to a measured
depth of  15,170  feet and  discovered  hydrocarbons  in a  middle  Miocene  age
reservoir.  The well was sidetracked,  as planned,  to a separate middle Miocene
age target in Viosca  Knoll block 824.  The Viosca Knoll 824 #1 was drilled to a
measured depth of 14,200 feet and also discovered hydrocarbon bearing sands. Two
development  wells are  scheduled  in 1999 to be redrilled  from Shell's  Spirit
platform in block 780.

Leo Prospect, Mississippi Canyon 502/503/546/547

         The Company  participated  in the Leo prospect in block 546 with a 12.5
percent  working  interest,  10.4  percent  net  revenue  interest,  operated by
British-Borneo  Exploration,  Inc.  The  initial  well in  2,500  feet of  water
penetrated  multiple Miocene age hydrocarbon  sands at depths between 11,500 and
17,500 feet with approximately 200 feet of net pay.  Additional seismic analysis
in 1999 and appraisal  drilling in 2000 will determine the ultimate scope of the
development.

Other Gulf of Mexico

         The Company has  interests  and operates in several  other areas in the
Gulf of Mexico,  with working  interests ranging from 14 percent to 100 percent.
During 1999,  the Company will continue to evaluate  these blocks for additional
exploratory or development potential using its 3-D seismic data.

NORTH LOUISIANA AND OTHER

         At year end,  proved reserves in North Louisiana and other areas in the
Southern Region totaled 16.1 billion cubic feet of gas and 116 thousand  barrels
of oil.  The  Company  has  working  interests  in 98 total  wells  and  royalty
interests in 101 wells.  The Company has  interests  in 602,353  gross acres and
394,209  net acres  with  options  to lease an  additional  128,000  net  acres.
Included in the total acreage amounts are 488,132 gross and 331,267 net acres in

                                       7

<PAGE>  8

northern  Louisiana  and  southern  Arkansas  where  the  Company  owns  mineral
interests  which  are not  subject  to  lease  expirations.  Production  in 1998
averaged  5.2 million  cubic feet of gas and 80 barrels of oil per day, or three
percent of the Company's 1998 production. During 1998, the Company drilled eight
wells in North Louisiana and four wells in Webb County Texas.

         The North  Louisiana core area is highly  prospective  and represents a
principal  exploration play for the Company. The Company has spent the last five
years  acquiring and leasing  acreage and developing an  exploration  program to
identify and test reefs in the Jurassic Troy Lime  formation.  This  exploration
play appears to share similar  characteristics with the East Texas Cotton Valley
reef play.  The Company also  initiated a  redevelopment  program in the Hosston
formation in the Cotton Plant Field and a Gray Sand play in northwest  Louisiana
during 1998.  The North  Louisiana area will continue to be a focus area for the
Company in 1999.

Troy Lime Reef Play

         The  Company's  primary  objective in 1998 was to begin  testing the 40
different reef anomalies  identified from its proprietary  166-square-mile,  3-D
seismic  program  conducted in 1996 and 1997. The Company formed a joint venture
with two  companies  in 1996 to  evaluate a portion of its  mineral  and acreage
positions in northern  Louisiana which was  prospective for reef anomalies.  The
two  companies  agreed to pay for 100 percent of the  seismic  costs in order to
earn  two-thirds  of the Company's  rights  within each seismic area.  Where the
Company owns mineral  interests  within the seismic area, the two companies have
the right to lease two-thirds of the minerals for a  fixed-price-per-acre  lease
bonus, with the Company retaining a royalty interest.

         The Company  drilled its first Troy Lime reef test in 1998. The Bozeman
#1 found an apparently  gas-saturated reef buildup with measurable  porosity and
permeability from logs and core analysis.  Mechanical problems during completion
operations prevented a production test of the 800-foot interval of interest. The
well was subsequently sidetracked and successfully drilled back to the objective
and is  currently  undergoing  testing  operations.  The  Bozeman  has  provided
indications  from well  logs,  core  samples  and gas shows of a  potential  gas
discovery.  However, extensive testing will be required to prove or disprove the
productivity of this complex rock  formation.  Testing has just begun and actual
results may not be known for several months.

         A second  reef  test,  the  Frazier  #1,  was spud in  December  and is
currently  drilling to a projected total depth of 16,500 feet. The Company holds
a 100  percent  working  interest in the Bozeman  sidetrack  and a 33.3  percent
working interest in the Frazier well.

         The Blake #1 well was drilled in 1998 as a development  well updip of a
Troy Lime, non-pinnacle reef producer. The test well found a tight reservoir and
is being plugged and abandoned.  The Company had a 33.3 percent working interest
in this well.

Certain Definitions

         As used in the tables below, these terms have the following meanings:

                           "Bbl" means barrel.
                           "MBbl" means thousand barrels.
                           "MMBbl" means million barrels.
                           "Mcf" means thousand cubic feet.
                           "MMcf" means million cubic feet.
                           "Bcf" means billion cubic feet.
                           "MMBtu" means million British thermal units.
                           "BOE" means barrel of oil equivalent.
                           "MBOE" means thousand barrels of oil equivalent.

         Natural gas volumes are  converted to barrels of oil  equivalent  using
the ratio of six Mcf of natural gas to one barrel of crude oil.

                                       8
<PAGE>   9

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,  1998 for the
Company, and for the Company,  excluding Patina, as of December 31, 1996. Patina
was sold in October 1997 and is not included in the 1998 and 1997 balances.
<TABLE>
<CAPTION>

                                                          Consolidated                   Excluding Patina
                                                          December 31,                     December 31,     
                                               -----------------------------------    ----------------------
                                                 1998         1997         1996                1996  
                                               --------     ---------    ---------           --------
<S>                                             <C>           <C>          <C>                <C>    
Crude oil and liquids (MBbl)
    Developed                                    17,383        16,101       31,869             16,070
    Undeveloped                                   1,159           659        8,628              1,952
                                               --------      --------     --------           --------
       Total                                     18,542        16,760       40,497             18,022
                                               ========      ========     ========           ========

Natural gas (MMcf)
    Developed                                   391,951       297,490      443,441            200,664
    Undeveloped                                  98,802        65,678      162,195            108,313
                                               --------      --------     --------           --------
       Total                                    490,753       363,168      605,636            308,977
                                               ========      ========     ========           ========

Total MBOE                                      100,334        77,288      141,436             69,518
                                               ========      ========     ========           ========
</TABLE>

         The following table sets forth the estimated pretax future net revenues
from the  production  of  proved  reserves  and the  Pretax  PV10  Value of such
revenues.
<TABLE>

                                                                      December 31, 1998                 
                                                     -------------------------------------------------                 
                                                     Developed         Undeveloped (a)         Total   
                                                     ---------         ---------------     -----------   
                                                                         (In thousands)

          <S>                                        <C>                 <C>                <C>                 
          1999                                       $  81,436           $ (14,007)         $  67,429
          2000                                          68,156              (1,036)            67,120
          2001                                          53,115               5,380             58,495
          Remainder                                    366,460             103,983            470,443
                                                     ---------           ---------          ---------
             Total                                   $ 569,167           $  94,320          $ 663,487
                                                     =========           =========          =========

          Pretax PV10 Value (b)                      $ 334,064           $  31,556          $ 365,620
                                                     =========           =========          =========
<FN>
(a) Net of estimated capital costs of $57.2 million,  including  estimated costs of $24.5 million during 1999.
(b) The after tax PV10 Value of proved  reserves totaled $322.2 million at year end 1998.
</FN>
</TABLE>

         The  quantities  and values shown in the preceding  tables are based on
realized  prices in effect at December 31, 1998,  of $9.56 per barrel of oil and
$1.94 per Mcf of gas. Reference prices as of December 31, 1998 were Koch WTI oil
of $9.50 per  barrel,  Henry Hub gas of $2.10 per Mcf and CIG index gas of $1.96
per Mcf.  Price  reductions  decrease  reserve values by lowering the future net
revenues  attributable  to the reserves and also by reducing the  quantities  of
reserves that are  recoverable on an economic  basis.  Price  increases have the
opposite  effect.  Any  significant  decline or increase in prices of oil or gas
could have a material effect on the Company's financial condition and results of
operations.

         Proved oil and gas reserves are the estimated  quantities of crude oil,
natural gas and  natural  gas liquids  which  geological  and  engineering  data
demonstrate  with  reasonable  certainty to be  recoverable in future years from
known  reservoirs  under  existing  economic and  operating  conditions.  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

                                       9

<PAGE>   10

developed  within the  periods  indicated  or that  prices and costs will remain
constant.  With respect to certain properties that historically have experienced
seasonal curtailment,  the reserve estimates assume that the seasonal pattern of
such  curtailment  will continue in the future.  There can be no assurance  that
actual  production  will equal the estimated  amounts used in the preparation of
reserve projections. See "Risk Factors and Investment Considerations."

         Netherland,   Sewell  &   Associates,   Inc.,   independent   petroleum
consultants,   prepared   estimates  of  the  Company's  proved  reserves  which
collectively  represent 84 percent of Pretax PV10 Value as of December 31, 1998.
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.

PRODUCTION, REVENUE AND PRICE HISTORY

         The following table sets forth information  regarding net production of
crude oil, liquids and natural gas,  revenues and expenses  attributable to such
production  and to natural gas  transportation,  processing  and  marketing  and
certain price and cost information for each of the years in the five year period
ended December 31, 1998 for the Company.

<TABLE>
<CAPTION>
                                                                Consolidated                           
                                    -------------------------------------------------------------------                           
                                       1998          1997           1996         1995          1994    
                                    ---------     ----------     ---------    ----------    -----------
                                       (Dollars in thousands, except prices and production information)
<S>                                 <C>           <C>           <C>           <C>            <C>
Production
     Oil (MBbl)                         1,909          3,490         3,884         4,278          4,366
     Gas (MMcf)                        56,203         61,638        55,840        53,227         43,809
     MBOE (a)                          11,277         13,763        13,191        13,149         11,668

Revenues
     Oil                            $  21,040     $   65,886    $   79,201    $   72,550     $   64,625
     Gas (b)                          112,164        141,330       110,126        72,058         73,233
                                    ---------     ----------    ----------    ----------     ----------
         Subtotal                     133,204        207,216       189,327       144,608        137,858
     Transportation,
         processing
         and marketing                  4,624          7,004        17,655        38,256        107,247
                                    ---------     ----------    ----------    ----------     ----------
                                    $ 137,828     $  214,220    $  206,982    $  182,864     $  245,105
                                    ---------     ----------    ----------    ----------     ----------

Operating expenses
     Production                     $  38,492     $   48,523    $   49,638    $   52,486     $   46,267
     Transportation,
         processing
         and marketing                  3,348          6,692        15,020        29,374         94,177
                                    ---------     ----------    ----------    ----------     ----------
                                    $  41,840     $   55,215    $   64,658    $   81,860     $  140,444
                                    ---------     ----------    ----------    ----------     ----------

Direct operating margin             $  95,988     $  159,005    $  142,324    $  101,004     $  104,661
                                    =========     ==========    ==========    ==========     ==========

Production data
     Average sales price (c)
         Oil (Bbl)                  $   11.02     $   18.88     $   20.39     $    16.96     $   14.80
         Gas (Mcf) (b)                   2.00          2.29          1.97           1.35          1.67
         BOE (a)                        11.81         15.06         14.35          11.00         11.82
     Average production
         expense/BOE                $    3.41     $    3.53     $    3.76     $     3.99     $    3.97
     Average production
         margin/BOE                 $    8.40     $   11.53     $   10.59     $     7.01     $    7.85
<FN>
(a)      Gas production is converted to oil equivalents at the rate of six Mcf per barrel.
(b)      Sales of natural gas liquids are included in gas revenues.
(c)      The Company estimates that its composite net wellhead prices at December 31, 1998 were approximately
         $1.94 per Mcf of gas and $9.56 per barrel of oil.
</FN>
</TABLE>
                                       10

<PAGE>   11

PRODUCING WELLS

             The following table sets forth certain  information at December 31,
1998  relating  to the  producing  wells in which  the  Company  owned a working
interest.  The Company also held royalty interests in 101 producing wells. Wells
are  classified as oil or gas wells  according to their  predominant  production
stream.
<TABLE>
<CAPTION>

               Predominant                   Gross                Net
             Product Stream                  Wells               Wells
             --------------                  -----               -----

               <S>                           <C>                  <C>
               Crude oil                     1,003                320
               Natural gas                     545                295
                                             -----              -----
                                             1,548                615
                                             =====              =====
</TABLE>

Acreage

         The following table sets forth certain information at December 31, 1998
relating to domestic acreage held by the Company.  Developed  acreage is acreage
assigned to  producing  wells.  For offshore  blocks in the Gulf of Mexico,  the
entire block is  classified  as  developed if a producing  well has been drilled
within its  boundaries.  Such blocks could  contain up to 5,000 gross acres.  In
most instances, the Company does not consider such blocks to be fully developed.
Undeveloped acreage is acreage held under lease, permit, contract or option that
is not in a spacing unit for a producing  well,  including  leasehold  interests
identified for development or exploratory drilling.
<TABLE>
<CAPTION>

                                              Developed                 Undeveloped                    Total           
                                         --------------------     ----------------------      ----------------------           
                                          Gross         Net         Gross          Net          Gross          Net       
                                         -------      -------     ----------     -------      ---------      -------       
<S>                                      <C>          <C>         <C>            <C>          <C>            <C>
Rocky Mountain Region
   Washakie (WY)                          42,695       36,847       104,878       92,808        147,573      129,655
   Wind River (WY) (a)                    10,508        9,180        96,564       61,182        107,072       70,362
   Northern Wyoming                        7,958        4,909           -            -            7,958        4,909
   Piceance (CO) (b)                       5,920        3,206        98,333       46,432        104,253       49,638
   Uinta (UT)                             15,361        8,411        90,630       68,947        105,991       77,358
   Big Horn (WY)                             320          160       158,964       82,239        159,284       82,399
   Deep Green River  (WY) (c)                480          369        63,222       54,258         63,702       54,627
                                       ---------    ---------     ---------     --------      ---------    ---------
     Rocky Mountain Region                83,242       63,082       612,591      405,866        695,833      468,948
                                       ---------    ---------     ---------     --------      ---------    ---------

Gulf of Mexico
   Main Pass Area                         33,185       16,949        14,763       10,111         47,948       27,060
   Other                                  44,813       19,056        66,420       22,255        111,233       41,311
                                       ---------    ---------     ---------     --------      ---------    ---------
     Total Gulf of Mexico                 77,998       36,005        81,183       32,366        159,181       68,371
                                       ---------    ---------     ---------     --------      ---------    ---------

North Louisiana
   Minerals                               21,606       13,399       466,526      317,868        488,132      331,267
   Leases (d)                              4,495        3,900        95,005       56,005         99,500       59,905
                                       ---------    ---------     ---------     --------      ---------    ---------
     Total North Louisiana                26,101       17,299       561,531      373,873        587,632      391,172
                                       ---------    ---------     ---------     --------      ---------    ---------

Other                                      8,311        1,664         6,410        1,373         14,721        3,037
                                       ---------    ---------     ---------     --------      ---------    ---------
     Southern Region                     112,410       54,968       649,124      407,612        761,534      462,580
                                       ---------    ---------     ---------     --------      ---------    ---------


   Total Company                         195,652      118,050     1,261,715      813,478      1,457,367      931,528
                                       =========    =========    ==========     ========     ==========    =========
<FN>
(a) The Company also holds 16,500 net undeveloped acres under option.
(b) The Company sold its interest subsequent to year end.
(c) The Company also holds the deep rights, below approximately 12,500 feet, in 10,625 net acres which are not included.
(d) The Company also holds 128,000 net undeveloped acres under option.
</FN>
</TABLE>
                                       11

<PAGE>    12


DRILLING RESULTS

         The  following  table  sets  forth  information  with  respect to wells
drilled during the past three years.  The  information  should not be considered
indicative  of future  performance,  nor  should  it be  assumed  that  there is
necessarily  any  correlation  between the number of productive  wells  drilled,
quantities of reserves found or economic value.  Productive wells are those that
produce  commercial  quantities  of  hydrocarbons  whether or not they produce a
reasonable rate of return.
<TABLE>
<CAPTION>

                                               1998         1997         1996
                                              ------       ------       ------
        <S>                                    <C>         <C>           <C>    
        Development wells
          Productive
            Gross                              64.0        102.0         79.0
            Net                                44.0         62.2         44.3
          Dry
            Gross                               3.0          4.0          3.0
            Net                                 1.7          1.5          1.5

        Exploratory wells
          Productive
            Gross                               -            5.0          5.0
            Net                                 -            2.2          1.5
          Dry
            Gross                               8.0          2.0          2.0
            Net                                 4.6          1.7          1.6
</TABLE>

         At December 31, 1998, the Company had nine gross (6.8 net)  development
wells in progress;  one drilling,  one awaiting pipeline connection and seven in
the  completion  phase.  Additionally,  at year end 1998,  nine  gross (5.2 net)
exploratory  wells  were  in  progress;  one  drilling,  one  awaiting  pipeline
connection,  and seven in the completion phase.  Wells in progress at the end of
1997 and 1996 are reflected in the appropriate category in the above table based
upon the well's final outcome.

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 1998, Sonat Marketing Company accounted for approximately
33 percent of revenues and Engage Energy accounted for  approximately 32 percent
of revenues.  In 1997, Sonat Marketing  Company  accounted for  approximately 17
percent of revenues,  Engage Energy accounted for approximately 14 percent,  and
Duke Power and Energy,  which  purchased a  significant  portion of Patina's gas
production,  accounted for  approximately  12 percent.  In 1996,  Duke Power and
Energy accounted for approximately 11 percent of revenues.  The marketing of oil
and gas by the Company  can be  affected by a number of factors  that are beyond
its control and whose future effect cannot be accurately predicted.  The Company
does not believe,  however,  that the loss of any of its customers  would have a
material adverse effect on its operations.

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

         In the Rocky Mountain  region,  essentially all of the Company's gas is
marketed through contracts with Engage Energy, a partnership between the Coastal
Corporation  and Westcoast  Energy,  Inc.  Under the  arrangements,  the Company
receives  market value for its gas as it is  delivered  into  mainline  pipeline
receipt points.  The Company also  participates in downstream  marketing margins
realized by Engage,  after  recovery of costs,  for a broad spectrum of Engage's
marketing  activities in Wyoming,  Colorado and Utah. The agreements with Engage
currently extend through March 2000 with an option to extend until March 2001.

                                       12

<PAGE>   13

         In 1997,  the  Company  pooled  its gas  transportation  facilities  in
Wyoming and Colorado with  facilities  owned by Coastal  Field  Services to form
Great Divide Gas  Services.  Great Divide was owned 73 percent by Coastal  Field
Services  and 27 percent by the  Company.  At the end of 1998,  the  Company and
Coastal Field  Services  elected to  discontinue  their  participation  in Great
Divide and to return the facilities  involved to their original owners under the
unwinding provisions of the Great Divide agreements.  In January,  subsequent to
this unwinding,  the Company sold its interest in the pipeline facilities in the
Piceance  Basin in  conjunction  with the sale of its oil and gas  properties in
this area.  The  Company  continues  to pursue  strategic  alternatives  for its
Wyoming pipeline facilities.

         Beginning  in  August  of  1998,  the  Company  commenced  transporting
substantially  all of its production from the East Main Pass area of the Gulf of
Mexico  through  Transcontinental  Gas Pipe Line  Corporation  for  delivery  to
markets accessible through Transco in the Mobile Bay area of Alabama. From March
through  August  of 1998,  the  Company  delivered  production  from the area to
markets  in  southeast  Louisiana  accessible  through  Viosca  Knoll  Gathering
Company.   The  Company   converted  to  Transco  to  alleviate  the  downstream
constraints  experienced in southeast Louisiana and to access additional markets
in which to sell  production  from the  area.  The  Company  amended  its  prior
arrangement with Viosca Knoll to allow for the  transportation of gas on Transco
and to provide for continuing back-up,  interruptible  transportation  rights on
Viosca Knoll.  As a result,  the Company has increased  transportation  capacity
from  the  area  and  expects  to  realize  an  increase  in  value  net  of all
transportation  fees payable to Transco and Viosca Knoll under the  arrangement.
To fully capitalize on the higher prices available through Transco,  the Company
is maximizing the amount of its Main Pass production marketed through Transco by
arranging for displaced  delivery  into Transco of  production  attributable  to
Company facilities in the area that are not currently connected to the system.

TITLE TO PROPERTIES

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

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

EMPLOYEES

         The Company had 306  employees as of December  31, 1998 with  principal
executive offices in Fort Worth, Texas and regional offices in Denver,  Colorado
and Houston,  Texas.  Field  offices are also  maintained in the areas where the
Company operates properties.

REGULATION

Regulation of Drilling and Production

         The Company's  operations  are affected by political  developments  and
federal and state laws and  regulations.  Oil and gas industry  legislation  and
administrative  regulations are periodically changed for a variety of political,
economic and other reasons.  Numerous departments and agencies,  federal, state,
local  and  Indian,  issue  rules  and  regulations  binding  on the oil and gas
industry,  some of which carry substantial  penalties for failure to comply. The
regulatory  burden on the oil and gas industry  increases the Company's  cost of
doing  business,  decreases  flexibility  in the  timing of  operations  and may
adversely affect the economics of capital projects.

         A  substantial  portion of the Company's oil and gas leases in the Gulf
of Mexico and in the Rocky Mountain area were granted by the U.S. Government and
are administered by two federal agencies,  the Bureau of Land Management ("BLM")
and the Minerals  Management  Service  ("MMS").  These leases are issued through
competitive  bidding,  contain relatively  standard terms and require compliance
with detailed BLM and MMS regulations and orders, which are subject to change by
the BLM and MMS. For offshore  operations,  lessees must obtain MMS approval for

                                       13

<PAGE>    14

exploration  plans and development and production  plans before  commencement of
operations.  In addition to permits  required from other  agencies  (such as the
Coast  Guard,  the Army  Corps of  Engineers  and the  Environmental  Protection
Agency),  lessees  must  obtain  a  permit  from  the  BLM or MMS  prior  to the
commencement of onshore or offshore drilling.

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

         In the past,  the federal  government has regulated the prices at which
oil and gas  could be sold.  Prices of oil and gas sold by the  Company  are not
currently regulated.  In recent years, the Federal Energy Regulatory  Commission
("FERC")  has  taken  significant  steps to  increase  competition  in the sale,
purchase,  storage and  transportation of natural gas. Under these orders,  FERC
has  caused  pipelines  to  open  up  access  to   transportation,   essentially
eliminating  pipelines  from the role of natural gas  merchant  and  "unbundled"
transportation  services  so that a buyer can  purchase  just those  services it
needs. FERC's regulatory programs generally allow more accurate and timely price
signals  from the consumer to the  producer  and, on the whole,  have helped gas
become more  responsive  to changing  market  conditions.  To date,  the Company
believes it has not  experienced  any material  adverse  effect as the result of
these programs.  Nonetheless,  increased competition in gas markets can and does
add to price volatility and inter-fuel competition, which increases the pressure
on the Company to manage its exposure to changing conditions and position itself
to take advantage of changing market forces.

Environmental Regulations

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

         The Company currently owns or leases numerous properties that have been
used for many  years for  natural  gas and crude oil  production.  Although  the
Company  believes that it and other previous owners have utilized  operating and
disposal practices that were standard in the industry at the time,  hydrocarbons
or other wastes may have been disposed of or released on or under the properties
owned or  leased  by the  Company.  In  connection  with  its  most  significant
acquisitions,  the Company has performed environmental  assessments and found no
material environmental noncompliance or clean-up liabilities requiring action in
the  near or  intermediate  future,  although  some  matters  identified  in the
environmental assessments are subject to ongoing review. The Company has assumed
responsibility  for  some  of the  matters  identified.  Some  of the  Company's
properties,  particularly  larger units that have been in operation  for several
decades, may require significant costs for reclamation and restoration when they
are divested or when operations eventually cease. Environmental assessments have
not been performed on all of the Company's properties. To date, expenditures for
environmental  control  facilities and for remediation have not been material to
the Company,  and the Company does not expect that,  under current  regulations,
future expenditures will have a material adverse impact on the Company.

         Under the Oil Pollution  Act of 1990  ("OPA"),  owners and operators of
onshore  facilities  and pipelines and lessees or permittees of an area in which
an offshore facility is located ("Responsible Parties") are strictly liable on a
joint and  several  basis for  removal  costs and  damages  that  result  from a
discharge  of oil into United  States  waters.  These  damages  include  natural
resource damages,  real and personal  property damages and economic losses.  OPA
limits the strict liability of Responsible Parties for removal costs and damages
that  result from a  discharge  of oil to $350.0  million in the case of onshore

                                       14

<PAGE>   15

facilities  and  $75.0  million  plus  removal  costs  in the  case of  offshore
facilities,  except that no limits  apply if the  discharge  was caused by gross
negligence or willful  misconduct,  or by the violation of an applicable federal
safety, construction or operating regulation by the Responsible Party, its agent
or subcontractor.

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

RISK FACTORS AND INVESTMENT CONSIDERATIONS

The Company's Income and Cash Flows are Largely Dependent Upon Gas Prices

         The Company  derives its revenue  principally  from the sale of natural
gas. The Company  sells the majority of its gas in the open market at prevailing
market  prices,  or under  market-price  contracts.  The market price for gas is
dictated by supply and demand,  and the  Company  cannot  predict or control the
price  it  receives  for  its  gas.   Moreover,   market  prices  for  gas  vary
significantly by region. For example,  natural gas in the Rocky Mountain region,
where  the  Company  produced  approximately  43  percent  of its  gas in  1998,
historically sells for less than gas in the Midwest and Northeast.

         Accordingly,  the  Company's  income  and cash  flows  will be  greatly
affected by changes in gas prices and by  regional  pricing  differentials.  The
Company will experience  reduced cash flows and may experience  operating losses
when gas prices are low.  Under extreme  circumstances,  the Company's gas sales
may not generate sufficient revenue to meet the Company's financial  obligations
and fund its planned capital expenditures. Moreover, significant price decreases
could  negatively  effect the Company's  reserves by reducing the  quantities of
reserves that are recoverable on an economic basis, necessitating write downs to
reflect the realizable value of the reserves in the low price environment.

The Company Must Replace Reserves to Sustain Production

         The Company  depletes  its reserves as it produces oil and gas for sale
into the market.  In order to sustain and  increase the  Company's  reserves and
production  levels,  the Company must replace the reserves it produces on a cost
effective basis through a combination of exploration for undiscovered  reserves,
enhanced  development of known reserves,  and acquisitions of new reserves.  The
Company's  future  production is highly  dependent  upon its level of success in
finding  or  acquiring  additional  reserves.  Replacing  produced  reserves  on
economic  terms will  become more and more  difficult  in the future as domestic
natural  resources  are  depleted.  As  a  result,  new  exploration  operations
increasingly require use of costly seismic and other geoscience technology while
yielding  discoveries  that are  generally  of smaller  size than those found in
years past. Likewise, the Company's cost of developing and producing reserves is
generally  increasing  as it is  forced  to invest  in  secondary  and  tertiary
recovery  technology  to exploit a shrinking  reserve  base.  The Company may be
unable to make the  necessary  capital  investment  to  maintain  or expand  its
reserves if cash flow from operations is reduced and external sources of capital
become  limited or  unavailable.  The Company  cannot assure you that its future
development,  acquisition and  exploration  activities will result in additional
proved reserves or that it will be able to drill  productive wells at acceptable
costs.

The Company's Drilling Program Involves Complicated Wells

         A large number of the wells in the Company's  drilling  program  target
carbonate  geological  formations  which involve  special  drilling  risks.  The
Company often targets very deep drilling objectives, frequently exceeding 15,000
feet,  involving very high subsurface  pressures and extreme heat. Many of these
wells encounter  hydrogen sulfide gas or other substances which are corrosive or
otherwise harmful to humans and equipment. These wells create a greater risk for
personal  injury or  property  damage from  blowout,  cratering,  well fire,  or
similar catastrophe than risks related to less complicated  drilling operations.

                                       15

<PAGE>   16

The Company's  Operations  Are Subject to  Interruption  From Severe Weather and
Other Factors

         The Company's operations are conducted principally in the offshore Gulf
Coast area and in the Rocky Mountain region.  The weather in both of these areas
can be extreme and can cause an  interruption  in the Company's  exploration and
production  operations.  The Company's Gulf Coast  operations are susceptible to
tropical  storms and  hurricanes.  While the Company's  offshore  facilities are
engineered  to  withstand   typical   hurricane   force  winds,   severe  storms
nevertheless  result  in  temporary  interruptions  due  to  the  evacuation  of
personnel for safety and the shut in of production.  Moreover, especially severe
weather  can  result  in  damage  to  facilities  entailing  longer  operational
interruptions and significant capital investment.  Likewise, the Company's Rocky
Mountain operations are subject to disruption from winter storms and severe cold
which can limit  operations  involving fluids and impair access to the Company's
facilities.

         In addition to weather,  other factors such as mechanical  break-downs,
workover  operations  and  gathering and  transportation  problems can result in
production interruptions.  The Company's exposure to production interruptions is
greatest  in the Gulf,  where the  Company's  production  is very  concentrated.
Almost 90 percent of the Company's  1998  production in the Gulf came from three
platforms  located in close  proximity in the East Main Pass area. This level of
concentration  creates a risk of production  interruption  from weather or other
local factors. An extended interruption in the Company's operations could have a
material  adverse effect on the Company's income and cash flows in the period in
which the interruption occurs.

The Company Invests Heavily in Exploration

         The  Company has  historically  invested a  significant  portion of its
capital budget in drilling  exploratory  wells in search of unproved oil and gas
reserves.  The Company  cannot be certain that the  exploratory  wells it drills
will  be  productive  or  that  it  will  recover  all  or  any  portion  of its
investments.  In order to  increase  the chances for  exploratory  success,  the
Company  often  invests  in  seismic  or other  geoscience  data to assist it in
identifying potential drilling objectives.  Additionally,  the cost of drilling,
completing and testing  exploratory  wells is often uncertain at the time of the
Company's  initial  investment.  Depending on  complications  encountered  while
drilling,  the final cost of the well may  significantly  exceed  that which the
Company originally estimated.  The Company expenses all direct costs of drilling
an unsuccessful  exploratory  well in the period in which the well is determined
not to be producible in commercial quantities.

Acquisitions  Could  Alter the  Company's Geographic  Focus  and  Financial Risk
Profile

         The  Company  continually  evaluates   acquisition   opportunities  and
frequently  engages in bidding and negotiating for  acquisitions,  many of which
are  substantial.  Although  the Company  generally  concentrates  on  acquiring
producing  properties with development and exploration  potential located in its
current areas of operation,  the Company occasionally  considers acquisitions in
other geographic regions. To finance a large acquisition,  the Company may alter
or increase  substantially its capitalization through the issuance of additional
debt or equity  securities,  the sale of production  payments or other financing
structures.  A large acquisition outside the Company's core operational areas or
involving a significant issuance of debt or equity could significantly alter its
financial  risk  profile  and the nature of its  operations  depending  upon the
character of the acquired properties and the structure of the financing.

The  Company's  Operations  Are  Subject  to  Strict   Environmental  and  Other
Governmental Regulation

         The Company must conduct its exploration  and production  operations in
compliance with a wide variety of federal, state and local laws, including those
relating  to the  discharge  of  materials  into the  environment  or  otherwise
relating to protection of the environment. Because many of the Company's Gulf of
Mexico and Rocky Mountain operations are located in environmentally sensitive or
other protected areas,  these operations are subject to special  regulations and
permitting  requirements.  The Company and its  personnel  could incur  material
fines and penalties, and in some cases, be subject to criminal prosecution if it
fails to comply with such regulations.

         The Company's  compliance with  increasingly  strict  environmental and
other  regulations  adds materially to the cost of the Company's  operations and
can  result  in  substantial  delays  in  new  projects.   The  Company  expends

                                       16

<PAGE>    17

significant  managerial  and financial  resources  complying  with  governmental
regulations  and  anticipates  these  costs will  increase in response to trends
toward greater  environmental  protection and stricter  governmental  oversight.
Likewise,   the  Company's   compliance  with  environmental  impact  assessment
regulations  on  federal  leases in the  Company's  Rocky  Mountain  region  can
significantly delay the commencement of operations in the area and can limit the
extent  to which  the  leases  may be  developed.  For  example,  delays  in the
environmental  impact  assessment  process for the Company's  expanded  drilling
program in the northern  Washakie Basin have resulted in the Company  postponing
commencement of a 30-well drilling program in the area.

The Company's Reserve Estimates and Future Net Revenues Are Based on Assumptions

         This annual report contains  estimates of reserves and estimated future
net revenues  from such  reserves.  These  estimates are based on reports of the
Company's  independent  petroleum  engineers.  These estimates fluctuate greatly
depending on the  underlying  assumptions  about  factors such as: 1) historical
production from analogous areas, 2) taxes and other governmental regulation,  3)
commodity  prices  and  operating  costs,  4) future  development  activity  and
investment,  and 5) the applicable discount rate. Actual future production,  oil
and gas prices, revenues,  taxes, development  expenditures,  operating expenses
and  quantities of  recoverable  oil and gas reserves most likely will vary from
those estimated.  Any significant variance could materially affect the estimated
quantities  and present  value of reserves set forth in this annual  report.  In
addition,  the  Company  may  adjust  estimates  of proved  reserves  to reflect
production history,  results of exploration and development,  prevailing oil and
gas prices and other  factors,  many of which are beyond its control.  For these
reasons,  estimates  of  reserves  and future net cash flows  should be used for
comparative  purposes  only and  should  not be viewed  as a  measure  of actual
production or revenues from the Company's reserves.

The Company Faces Competition for Labor and Services

         Oil and gas exploration and production  operations are largely regional
in nature.  Depending on economic  conditions,  seasonal drilling activity,  and
other factors beyond the Company's control,  the Company frequently faces strong
competition in procuring services in the geographic regions in which it operates
from a limited pool of laborers,  drilling  services  contractors  and equipment
vendors.  Moreover, many of the Company's competitors have substantially greater
financial and other resources than the Company.  Competition for labor, services
and equipment is especially intense during warm weather months when the level of
drilling operations  traditionally are at their peak. This competition sometimes
results in increased labor and drilling services costs or in operational delays.
Depending  on the  magnitude of any  resulting  cost  increases  or  operational
delays, the effects of this competition for labor,  services and equipment could
materially impact the Company's income and cash flows.


ITEM 3.  LEGAL PROCEEDINGS

         In September  1996, the Company and other interest owners in a lease in
southern  Texas were sued by the  royalty  owners in Texas state court in Brooks
County,  Texas. The Company's  working interest in the lease is approximately 20
percent.  The complaint  alleges,  among other things,  that the defendants have
failed to pay proper  royalties  under the  lease,  have  unlawfully  commingled
production  with  production from other leases and have breached their duties to
reasonably  develop  the lease.  The  plaintiffs  also claim  damages for fraud,
trespass and similar matters,  and demand actual and putative damages.  Although
the complaint does not specify the amount of damages  claimed,  plaintiffs  have
submitted  calculations  showing total  damages  against all owners in excess of
$175.0  million.  The Company and the other interest owners have filed an answer
denying  the claims and intend to contest the suit  vigorously.  Activity in the
case has been stayed pending  resolution of a variety of administrative  motions
in the matter.

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

                                       17

<PAGE>    18

         On January 15, 1999,  Phyllis  Freiman,  a stockholder  of the Company,
filed a putative class action  complaint in the Delaware Court of Chancery,  No.
16900-NC,  seeking  to enjoin  the  merger of the  Company  into Santa Fe Energy
Resources,  Inc.  ("Santa  Fe")  on the  proposed  terms  and  seeking  damages.
Defendants  named in the  complaint  are the Company,  each of its directors and
Santa Fe. The  plaintiff  alleges  numerous  breaches  of the duties of care and
loyalty  owed by the  Company  and  its  directors  to the  purported  class  in
connection with entering into the merger  agreement with Santa Fe. The plaintiff
further alleges that Santa Fe aided and abetted the Company and its directors in
their alleged  breaches of fiduciary duty. The defendants  believe the complaint
is without merit and intend to vigorously defend the action.

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


ITEM 4.  SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS

         No matters were  submitted  for a vote of security  holders  during the
fourth quarter of 1998.

                                       18
<PAGE>   19


                                     PART II

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

         The Company's stock is listed on the New York Stock Exchange and trades
under the symbol "SNY." The following  table sets forth,  for 1998 and 1997, the
high and low  closing  prices for the  Company's  securities  for New York Stock
Exchange composite transactions, as reported by The Wall Street Journal.
                                                ----------------------- 
<TABLE>
<CAPTION>

                                                   1998                             1997         
                                          ----------------------           ----------------------
                                             High          Low                High          Low  
                                          ---------     --------            --------     --------  

         <S>                              <C>           <C>                 <C>          <C>
         First Quarter                    $ 21-7/16     $     15            $ 19-1/8     $ 14-5/8
         Second Quarter                      22-1/2       17-3/8                  19       15-1/4
         Third Quarter                       21-1/4      14-9/16              23-5/8      18-3/16
         Fourth Quarter                     17-5/16       11-1/4              24-7/8       16-3/4
</TABLE>

         On February  26,  1999,  the closing  price of the common stock was $10
7/16.  Quarterly  dividends were paid at the rate of $.065 per share during 1998
and 1997. For federal income tax purposes, the common dividends paid during 1998
were a non-taxable  return of capital.  Shares of common stock receive dividends
as,  if and when  declared  by the  Board of  Directors.  The  amount  of future
dividends will depend on debt service  requirements,  capital  expenditures  and
other factors.  On December 31, 1998, there were approximately  2,100 holders of
record of the common stock and 33.4 million shares outstanding.

ITEM 6.  SELECTED FINANCIAL DATA

         The  following   table  presents   selected   financial  and  operating
information  for each of the years in the five year period  ended  December  31,
1998.  Share  and per  share  amounts  refer to  common  shares.  The  following
information  includes the results of Patina Oil and Gas  Corporation  ("Patina")
through the third  quarter of 1997 when the Company  sold its interest in Patina
and 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,        
                                                       ----------------------------------------------------------

                                                          1998         1997        1996        1995        1994 
                                                       ---------    ---------   ---------   ---------   ---------

<S>                                                    <C>          <C>         <C>         <C>         <C>    
Income Statement
       Revenues                                        $ 141,095    $ 255,728   $ 285,111   $ 197,301   $ 262,328
       Income (loss) before extraordinary items          (24,733)      35,465      62,950     (39,831)     12,372
          Per share                                         (.74)         .96        1.81       (1.53)        .07
          Per share - assuming dilution                     (.74)         .95        1.72       (1.53)        .07
       Net income (loss)                                 (24,733)      32,617      62,950     (39,831)     12,372
          Per share                                         (.74)         .87        1.81       (1.53)        .07
          Per share - assuming dilution                     (.74)         .86        1.72       (1.53)        .07
          Dividends per share                                .26          .26         .26         .26         .25
       Weighted average shares outstanding                33,416       30,588      31,308      30,186      23,704

Cash Flow
       Net cash provided by operations                 $  75,159    $ 122,041   $ 101,730   $  69,121   $  86,397
       Net cash realized (used) by investing            (188,267)      31,808     (62,356)     32,421    (245,503)
       Net cash realized (used) by financing              29,836      (92,328)    (38,715)    (96,012)    169,926

Balance Sheet
       Working capital                                 $ (37,713)   $  56,326   $   9,168   $   5,842   $     708
       Oil and gas properties, net                       352,983      274,304     635,387     435,217     472,239
       Total assets                                      433,937      546,088     879,459     555,493     673,259
       Senior debt                                        39,001            1     188,231(a)  150,001     234,857
       Subordinated notes                                173,787      173,635     183,842(b)   84,058      83,650
       Stockholders' equity                              128,454      263,756     294,668     235,368     274,086

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

                                       19
<PAGE>    20


         The following tables set forth unaudited summary financial results on a
quarterly basis for the two most recent years:
<TABLE>
<CAPTION>

(In thousands, except per share data)                                                  1998   
                                                               ------------------------------------------------
                                                                 First       Second        Third       Fourth 
                                                               ---------    ---------    ---------    --------- 

<S>                                                            <C>          <C>          <C>          <C>      
Oil and gas sales                                              $  32,822    $  34,581    $  32,636    $  33,165
Production margin                                                 24,374       25,241       22,050       23,047
Depletion, depreciation, amortization, and property impairments   11,762       13,925       13,987       19,773
Exploration expense                                                3,213        7,305       24,674       13,111
Income (loss) before extraordinary items                           1,838        (777)     (13,312)     (12,482)
    Per share                                                        .06        (.02)        (.40)        (.37)
    Per share - assuming dilution                                    .05        (.02)        (.40)        (.37)
Net income (loss)                                                  1,838        (777)     (13,312)     (12,482)
  Per share                                                          .06        (.02)        (.40)        (.37)
  Per share - assuming dilution                                      .05        (.02)        (.40)        (.37)
</TABLE>
<TABLE>
<CAPTION>

(In thousands, except per share data)                                                 1997   
                                                               ------------------------------------------------
                                                                 First       Second        Third       Fourth 
                                                               ---------    ---------    ---------    --------- 
<S>                                                            <C>          <C>          <C>          <C>      
Oil and gas sales                                              $  67,848    $  48,988    $  52,156    $  38,224
Production margin                                                 53,827       36,485       39,029       29,352
Depletion, depreciation, amortization, and property impairments   23,208       23,389       26,802       13,738
Exploration expense                                                1,700        3,690        7,212        4,444
Income before extraordinary items                                 19,926        5,992        3,633        5,914
    Per share                                                        .59          .15          .07          .14
    Per share - assuming dilution                                    .52          .15          .07          .14
Net income                                                        19,926        3,144        3,633        5,914
  Per share                                                          .59          .05          .07          .14
    Per share - assuming dilution                                    .52          .05          .07          .14
</TABLE>

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

Overview

         Snyder Oil  Corporation  (the  "Company") is an independent oil and gas
company  with  principal  operations  in domestic  natural gas  exploration  and
production.  The Company's primary  properties are located in the Rocky Mountain
region, Gulf of Mexico and northern Louisiana.

         The Company has  concentrated  its exploration and development  efforts
over the past years to emphasize  natural gas reserve  growth.  During 1998,  90
percent of the Company's  reserve additions were natural gas. This has increased
the percentage of natural gas reserves to 82 percent, versus 78 percent in 1997.
At December 31, 1998, the Company had proved  reserves of 100.3 million  barrels
of oil equivalent with a pretax present value of $365.6 million,  assuming a ten
percent discount rate with constant pricing and costs.

         Exploration expense in 1998 of $48.3 million significantly impacted the
Company's financial results from eight dry holes and significant acquisitions of
3-D seismic.  Even with the high  exploration  expense,  the  Company's  capital
program  replaced 382 percent of 1998  production with a finding and development
cost  from  all  sources,  including  revisions,  of  $4.44  per  barrel  of oil
equivalent, an improvement of 23 percent compared to 1997.

         In October 1997, the Company sold its 74 percent interest in Patina Oil
and Gas Corporation  ("Patina").  Net proceeds from the sale were  approximately
$127 million  resulting in a $2.8 million gain,  net of tax.  Excluding  Patina,
production  increased 26 percent in 1998 compared to 1997; however, a 21 percent
decrease in prices  caused oil and gas revenues to remain  constant.  Production
grew in all three core  operating  areas  reflecting  our  strategy  of balanced
growth.

         The Company also has investments in two  international  exploration and
production  companies,  Cairn Energy plc  ("Cairn") and SOCO  International  plc
("SOCI plc"),  both listed on the London Stock  Exchange.  In 1998,  the Company

                                       20

<PAGE>    21

experienced a decline of $119.1 million in the value of its investments in Cairn
and SOCI plc. The unrealized loss reflected in equity was $75.4 million,  net of
tax. The book and market value at December 31, 1998 was $24.0 million. The Cairn
shares  can be  sold  at  the  discretion  of the  Company.  Since  the  Company
contributed  assets to form SOCI plc in 1997, under London Stock Exchange rules,
the Company is not permitted to sell the SOCI plc shares prior to May 1999.

         On January 13, 1999, the Company  announced its agreement to merge with
Santa  Fe  Energy  Resources,   Inc.  ("Santa  Fe")  creating  Santa  Fe  Snyder
Corporation. The Board of Directors of each company has unanimously approved the
transaction  and  committed  to vote his or her  shares in favor of the  merger.
Snyder  shareholders  will receive 2.05 shares of Santa Fe common stock for each
share of Snyder resulting in Snyder shareholders owning approximately 40 percent
of the outstanding  shares after the merger. It is expected that the transaction
will be  accounted  for as a purchase.  John C.  Snyder will be the  Chairman of
Santa Fe Snyder  Corporation and James L. Payne,  currently the Chairman and CEO
of Santa Fe, will be the CEO of the new company. The eleven person board will be
composed of five members from Snyder's current  directors and six from Santa Fe.
The Form S-4 has been  filed  with the SEC and,  pending  shareholder  and other
required approvals, the merger is expected to be completed in the second quarter
of 1999.

         In January  1999,  the Company sold its interest in the Piceance  Basin
and the associated  gathering  facility for $28.8 million cash,  resulting in an
estimated gain of approximately $500,000.

FINANCIAL PERFORMANCE

         The Company  reported a net loss in 1998 of $24.7 million or ($.74) per
share  compared to net income,  excluding  Patina,  for 1997 of $28.2 million or
$.73 per share.  Excluding gains on sales of properties,  1998 resulted in a net
loss of $26.9  million  compared  to a net loss  applicable  to  common  of $4.1
million  in 1997,  excluding  Patina,  gains on sales  of  equity  interests  in
investees,  gains on sales of properties,  gain on sale of subsidiary  interest,
extraordinary item and minority interest.  Higher exploration  expense and lower
oil and natural gas prices offset the 36 percent increase in gas production from
1997, excluding Patina.

         Net cash  provided by operating  activities  decreased to $75.2 million
during 1998, compared to $122.0 million during 1997. This decrease is attributed
to the sale of Patina,  which  accounted  for $48.7  million of last year's cash
flow. Excluding Patina, the Company increased its net cash provided by operating
activities in spite of the decline in oil and natural gas prices  between years.
While exploration costs impact the Company's net income or loss, all exploratory
costs are  reclassified  from  operating  expenses to investing  activities  for
purposes of calculating  cash flow from  operations.  Exploratory  costs totaled
$48.3 million in 1998, $17.0 million in 1997 and $4.2 million in 1996.

FORWARD-LOOKING INFORMATION

         Certain  statements  contained  in this Annual  Report on Form 10-K and
other  materials  filed or to be filed by the Company  with the  Securities  and
Exchange Commission (as well as information included in oral statements or other
written statements made or to be made by the Company),  other than statements of
historical  fact,  are  forward-looking  statements  within  the  meaning of the
Private Securities Litigation Reform Act of 1995. Forward-looking statements may
relate to a variety  of  matters  not  currently  ascertainable,  such as future
capital   expenditures,   drilling  activity,   acquisitions  and  dispositions,
development  or  exploratory  activities,   cost  savings  efforts,   production
activities  and  volumes,  hydrocarbon  reserves,  hydrocarbon  prices,  hedging
activities  and the results  thereof,  financing  plans,  liquidity,  regulatory
matters,  competition and the Company's ability to realize  efficiencies related
to certain transactions or organizational changes.

         Forward-looking  statements  generally are accompanied by words such as
"anticipate,"  "believe,"  "estimate,"  "expect,"  "intend," "plan,"  "project,"
"potential"  or similar  statements.  Although  the  Company  believes  that the
expectations  reflected in such  forward-looking  statements are reasonable,  no
assurance can be given that such expectations  will prove correct.  Factors that
could  cause  the  Company's  results  to  differ  materially  from the  results
discussed in such  forward-looking  statements include the risks described under
"Risk Factors and Investment Considerations" in this Annual Report on Form 10-K,
such as the  fluctuations of the prices received or demand for the Company's oil

                                       21

<PAGE>     22

and gas,  the  ability  to  replace  depleting  reserves,  potential  additional
indebtedness,  the requirements for capital,  drilling risks, operating hazards,
the cost and availability of drilling rigs,  acquisition  risks, the uncertainty
of  reserve   estimates,   competition  and  the  effects  of  governmental  and
environmental regulation. All forward-looking statements are expressly qualified
in their entirety by the cautionary statements in this section.

RESULTS OF OPERATIONS

         COMPARISON OF 1998 RESULTS TO 1997

Oil and Gas Sales

         The following  table reflects  activities for the Company's oil and gas
properties  for 1998 and 1997.  Two  columns are  provided  for 1997 to show the
effect of the October 1997 disposition of Patina.  The discussion  following the
                                                   -----------------------------
tables will concentrate on differences between 1998 and 1997, excluding Patina.
-------------------------------------------------------------------------------
<TABLE>
<CAPTION>

                                                                Twelve Months Ended December 31,          
                                                     -----------------------------------------------------          
                                                                            Excluding
                                                                             Patina
                                                                           (Unaudited)
                                                          1998                1997               1997     
                                                     -------------       -------------       -------------
                                                            (In thousands, except production, average
                                                                  price and cost per BOE data)

<S>                                                  <C>                 <C>                 <C>          
Oil and gas sales                                    $     133,204       $     133,851       $     207,216
Direct operating costs                                     (38,492)            (35,016)            (48,523)
                                                     --------------      --------------      --------------
     Production margin                               $      94,712       $      98,835       $     158,693
                                                     =============       =============       =============

Average daily production:
Oil (Bbls)                                                   5,231               5,617               9,561
Gas (Mcf)                                                  153,982             113,361             168,873

Average oil price (per Bbl)                          $       11.02       $       18.24       $       18.88
Average gas price (per Mcf)                                   2.00                2.33                2.29
Direct operating costs (per BOE)
     Lease operating                                 $        2.61       $        2.74       $        2.41
     Production taxes                                          .66                 .89                 .94
     Workovers                                                 .14                 .28                 .18
                                                     -------------       -------------       -------------

         Total direct operating costs                $        3.41       $        3.91       $        3.53
                                                     =============       =============       =============

     Depletion, depreciation and amortization        $        4.78       $        4.87       $        5.80
                                                     =============       =============       =============
</TABLE>

         In 1998,  the increase in gas  production of 36 percent was offset by a
40 percent  decrease in the  average oil price and a 14 percent  decrease in the
average price of natural gas. The increase in gas production reflected growth in
all three core operating  areas.  Gas production in the Gulf of Mexico increased
50  percent  with the  commencement  of  production  from the new Main  Pass 261
platform  in March  1998,  along with  development  drilling  and an  additional
pipeline  connection in the third quarter of 1998.  Increased gas  production in
the Rocky  Mountain  Region was driven by the  acquisition  of  interests in the
Washakie and Beaver Creek areas  coupled with the region's  ongoing  development
drilling program. The decrease in oil production reflects the delay of workovers
and  drilling  where  feasible  on  oil  projects  due  to  the  low  oil  price
environment.

         The gas price  received at the wellhead  during 1998 was $1.87 per Mcf,
with downstream  activities  adding $.13 per Mcf to the reported price. In 1997,
the wellhead gas price,  excluding Patina, was $2.28, with downstream activities
adding $.05 to the reported price.  The oil price was $11.02 per barrel for 1998
with no downstream  activities.  This compares to $17.84 at the wellhead in 1997
with $.40 added from downstream activities.

                                       22

<PAGE>      23

Direct Operating Costs

         Direct operating  expenses  decreased $.50 per barrel of oil equivalent
from 1997, excluding Patina, due to the more equal balance in production between
the Rockies and the Gulf of Mexico  along with  ongoing  cost  cutting  efforts,
lower  workover  costs  and the  absence  of  production  taxes  on the  growing
production in the Gulf of Mexico.

Depletion, Depreciation and Amortization

         DD&A  expense  for the  year  increased  by $10.4  million  due to a 26
percent increase in production. DD&A per barrel of oil equivalent decreased $.09
reflecting the shift in the production mix to properties with lower costs.

Non-Recurring Gains and Losses

         Non-recurring  gains and losses  added $39.7  million to income  before
taxes,  minority interest and extraordinary  item in 1997 while they reduced the
1998 loss by $2.2  million.  Gains on sales of  equity  interests  in  investees
during 1997 included a $13.0 million gain on the sale of Cairn stock and a $19.8
million  gain  related to the  exchange of the  Company's  equity  interests  in
international  subsidiaries  for a 15.9 percent  ownership in the initial public
offering of SOCI plc.  Gains on sales of  properties of $3.3 million in 1998 and
$8.7  million in 1997 were the result of the  Company's  ongoing  plan to divest
non-strategic  assets.  The most  significant  items in 1998 were a $3.1 million
gain on the exchange of  non-strategic  South Texas properties for the expansion
of a core area in the Rocky Mountains and a $5.5 million  impairment of two Gulf
of Mexico properties.  In 1997, the most significant items were the sales of two
non-core  properties  in  the  Gulf  of  Mexico  for a  $5.1  million  gain  and
impairments of $7.3 million.  The impairments in 1998 related  primarily to well
performance  and 1997 were primarily  attributable  to the decline in oil prices
and only  impacted the  carrying  value of certain oil  properties.  The Company
utilizes the five year NYMEX strip prices for impairment tests.

Exploration Expense

         Exploration  expense of $48.3  million in 1998  represents  an increase
from $16.9 million in the prior year as 1998 includes $28.4 million for five dry
holes in the Gulf of Mexico and  increased  expenditures  for the  purchase  and
evaluation  of 3-D  seismic  of $17.8  million to support  our  exploration  and
development  efforts in the Gulf of  Mexico,  northern  Louisiana  and the Rocky
Mountains.  In 1998,  with our  continuing low risk  development  program in the
Rockies,  we elected to take a higher  risk  profile in the Gulf  attempting  to
capture  the  longer  reserve  life and  higher  production  rates  found in the
transition  zone  between the  continental  shelf and the  ultra-deep  projects.
Although  the five dry holes in the Gulf of Mexico  were only 15  percent of our
1998 capital program the expense constituted 75 percent of our reported loss for
1998.  In 1997,  the Company  invested  $8.9 million in 3-D seismic and incurred
$8.0 million for two exploratory dry holes in the Gulf of Mexico.

General and Administrative Expenses

         General and administrative  expenses, net  of  reimbursements, of $16.4
million  in 1998  were  relatively  consistent  with  the $16.6 million in 1997,
excluding Patina.

Financing Costs

         Interest expense, net of interest income, was $13.4 million compared to
$10.6  million in 1997.  The  increase  is due to the higher  principal  balance
outstanding  throughout  1998  and the  higher  effective  interest  rate on the
subordinated  notes  issued in June 1997.  Interest  income was $2.4 million for
both 1998 and 1997.

Minority Interest in Subsidiaries

          Minority interest recognized during 1997 related to the ten percent of
SOCO  International,  Inc.  which was owned by a Director of the Company and the
minority share of Patina.  In July 1997, SOCO  International,  Inc. acquired the
Director's ten percent ownership for shares of common stock of the Company.  The
Company's investment in Patina was sold in the fourth quarter of 1997.

                                       23
<PAGE>    24

Extraordinary Item

         The  extraordinary  item recorded in 1997 of $2.8 million,  net of tax,
related to the early  extinguishment of the Company's  convertible  subordinated
notes.

         COMPARISON OF 1997 RESULTS TO 1996

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

         The following  table sets forth certain  operating  information  of the
Company for the periods presented.  The discussion following the tables includes
consolidated results except as noted.
<TABLE>
<CAPTION>

                                         Excluding Patina                        Consolidated           
                                      ----------------------    Increase    ---------------------    Increase    
                                         1997         1996     (Decrease)      1997         1996    (Decrease)
                                      ---------    ---------                ---------   ---------     
<S>                                   <C>          <C>             <C>      <C>         <C>             <C>
Oil and gas sales (in thousands)      $ 133,851    $ 107,143       25%      $ 207,216   $ 189,327        9%
Production margin (in thousands)      $  98,835    $  72,025       37%      $ 158,693   $ 139,689       14%
Daily production:
     Oil (Bbls)                           5,617        6,000       (6%)         9,561      10,611      (10%)
     Gas (Mcf)                          113,361       87,139       30%        168,873     152,570       11%
     Equivalent barrels (BOE)            24,510       20,525       19%         37,707      36,040        5%
Average Prices:
     Oil ($/Bbl)                      $   18.24    $   20.34      (10%)     $   18.88   $   20.39       (7%)
     Gas ($/Mcf)                      $    2.33    $    1.96       19%      $    2.29   $    1.97       16%
     Equivalent barrel ($/BOE)        $   14.96    $   14.26        5%      $   15.06   $   14.35        5%
DD&A per BOE                          $    4.87    $    5.29      (10%)     $    5.80   $    6.41      (10%)
</TABLE>

         Oil and gas sales,  excluding  Patina,  increased  25 percent  due to a
significant increase in gas production along with higher gas prices.  Production
in the  Gulf  of  Mexico  more  than  doubled  due to two  fourth  quarter  1996
acquisitions and the Company's drilling efforts beginning to come on stream. The
Rocky Mountain  Region also increased  production due to successful  development
drilling  primarily in the second and third  quarters of 1997,  but the increase
was partially offset by sales of non-strategic properties during 1996.

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

         Gains on sales of  properties  of $8.7 million in 1997 and $8.8 million
in 1996 were a result of the Company's  ongoing plan to divest of  non-strategic
assets.  The most significant items in 1997, after the sale of Patina,  were the
sales of two non-core  properties in the Gulf of Mexico for a $5.1 million gain.
The most  significant  item during 1996 was a $7.4 million gain on the sale of a
50 percent interest in the Deep Green River Basin holdings.

         General and administrative  expenses,  net of reimbursements,  for 1997
were $20.4 million,  a $3.2 million increase  compared to 1996 as several of the
properties  sold during 1996,  while having high operating  costs and depletion,
depreciation  and  amortization   rates,   provided   significant   general  and
administrative expense reimbursements. Net general and administrative costs have
declined  three to six percent  each quarter  since the fourth  quarter of 1996.
There was a 16 percent  decrease in the fourth quarter of 1997  attributable  to
the disposition of Patina.

                                       24

<PAGE>     25

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

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

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

CAPITAL EXPENDITURES

Exploration and Development Activities

         During 1998, the Company  incurred  $167.4  million on exploration  and
development  activities  while placing 78 wells on  production  with 18 wells in
progress  at year end.  In the Gulf of  Mexico,  $33.9  million  of  development
activity  included a  production  platform at Main Pass 261,  three  development
wells,  one  recompletion  and one  development  well in  progress  at year end.
Exploration  activities included $19.1 million for four exploration  discoveries
and $28.4 million for five unsuccessful  tests.  Additionally,  $8.7 million was
invested in 3-D seismic acquisition and evaluation.

         The Company  continued its successful  drilling program in the Rockies.
Expenditures  for 1998,  totaled $52.8 million to place 65 development  wells on
production  with seven wells in progress at year end. One  exploration  well was
successful  totaling  $552,000 and two unsuccessful  tests totaled $1.0 million.
Additional  exploration  expense of $2.3  million was  incurred  for 3-D seismic
acquisition and evaluation.

         The Company spent $12.8 million  primarily in North  Louisiana to place
five  development  wells  on  production  with  one  development  well  and four
exploratory wells in progress at year end. One exploration well was unsuccessful
totaling $1.0 million.  An additional  $6.8 million of  exploration  expense was
incurred for the acquisition and evaluation of 3-D seismic in the area.

Acquisitions

         During  1998,  the  Company  spent $16.2  million to acquire  producing
properties  and $7.5 million on acreage  purchases  in and around the  Company's
operating  hubs.  Of the  producing  property  acquisitions,  $5.4  million  was
incurred  to  purchase  an  incremental  interest  in the Main  Pass  properties
operated  by the  Company in the Gulf of  Mexico.  The  Company  also spent $2.6
million in North Louisiana to purchase producing properties and a gas processing
facility and $7.2 million to purchase incremental interests in properties in the
Washakie Basin of southern Wyoming.

         The Company also completed a non-cash acquisition in the second quarter
of 1998. The Company acquired 75 percent of Amoco Production Company's ("Amoco")
interest  in the  Beaver  Creek Unit and two  associated  gas plants in the Wind
River Basin in Wyoming in exchange for the Jonah Field  portion of the Company's
properties in the Deep Green River Basin project in Wyoming.  Under terms of the
agreement,  the Company also received  Amoco's  interest in the Deep Green River

                                       25

<PAGE>    26

Basin acreage outside the Jonah Field area and retained the deep rights in Jonah
beneath the Mesaverde horizon at about 12,250 feet.

         During the third quarter of 1998, the Company exchanged its interest in
the Cage Ranch  Field in South Texas for CIG  Exploration's  interest in certain
producing and  non-producing  properties in the Washakie  Basin of Wyoming.  The
Company received approximately $1.5 million in cash as part of the exchange.

         Proved  acquisitions during 1996 included $218.4 million related to the
formation of Patina  including the acquisition of Gerrity Oil & Gas Corporation.
In October 1997, the Company sold its interest in Patina.  Net proceeds from the
sale were approximately $127.0 million.

Capital Commitments

         As of December 31, 1998,  commitments for capital  expenditures totaled
approximately $27.0 million.  The Company anticipates that 1999 expenditures for
exploration and  development  could be up to $75.0 million subject to total cash
flow for the year,  which is dependent on commodity  prices.  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.

Capital Resources and Liquidity

Capital Resources

         The Company's  primary needs for cash are for exploration,  development
and  acquisition of oil and gas  properties,  payment of interest on outstanding
indebtedness  and working  capital  obligations.  The Company's  primary capital
resources  are net  cash  provided  by  operating  activities,  existing  credit
facilities and proceeds from sales of marketable  securities  and  non-strategic
assets.  The Company expects that these resources will be sufficient to fund its
capital commitments in 1999.

         At December 31, 1998,  the Company had total assets of $433.9  million.
Total  capitalization was $341.2 million, of which 51 percent was represented by
subordinated  debt, 38 percent by  stockholders'  equity,  and eleven percent by
senior debt.

          At December 31, 1998,  the Company had  marketable  securities  with a
market value of $24.0 million for its shares of Cairn and SOCI plc. In 1998, the
Company  experienced a decline of $119.1 million in the value of its investments
in Cairn  and SOCI plc.  The  unrealized  loss  reflected  in  equity  was $75.4
million, net of tax.

         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.

         In the fourth quarter of 1998, the Company increased the borrowing base
under the existing  credit  facility to $150.0  million  from $100.0  million in
order to provide the flexibility to continue to pursue growth opportunities.  As
the  Company   continues  to  pursue  balanced   growth  through   exploitation,
exploration  and  acquisitions,  the Company may utilize  alternative  financing
sources, including the issuance of fixed rate long-term public debt, convertible
securities or preferred stock. The Company may also issue securities in exchange
for oil and gas  properties,  stock or  other  interests  in  other  oil and gas
companies or related assets.

         In June 1997,  the Company issued $175.0 million of 8.75 percent Senior
Subordinated Notes ("Notes") due June 15, 2007. The net proceeds of the offering
were  $168.3  million  which  were  used to  redeem  the  Company's  convertible
subordinated  notes due May 15, 2001, and reduce the balance  outstanding  under
its credit facility. Through the issuance of the new Notes and the redemption of
the old notes,  the Company has  effectively  extended its debt maturity by over
six years.  The Notes contain  covenants  that,  among other  things,  limit the
ability of the Company to incur additional indebtedness,  pay dividends,  engage
in transactions  with  shareholders and affiliates,  create liens,  sell assets,

                                       26

<PAGE>     27

engage in  mergers  and  consolidations  and make  investments  in  unrestricted
subsidiaries.  Such  restricted  payments are limited by a formula that includes
proceeds  from  certain  securities,  cash flow and other  items.  Based on such
limitations,  more than $70.0 million was available for the payment of dividends
and other  restricted  payments at December 31, 1998.  Upon the  occurrence of a
change of control,  as defined in the Notes,  the Company  would be obligated to
make an offer to purchase all outstanding Notes at a price of 101 percent of the
principal amount thereof. In addition,  the Company would be obligated,  subject
to certain  conditions,  to make offers to purchase  the Notes with the net cash
proceeds of certain  asset sales or other  dispositions  of assets at a price of
100 percent of the principal  amount thereof.  The proposed merger with Santa Fe
does not obligate the Company to make any offer to repurchase the Notes.

         The Company has deferred capital  expenditures on oil properties due to
low oil prices  unless  required  for lease  maintenance,  safety or  regulatory
compliance reasons.

         Marginal oil production that is currently shut-in due to low oil prices
would begin to be put back on production at NYMEX oil prices ranging from $14.00
to $15.00 per barrel.  There are approximately 18 wells shut-in with gross daily
production of 125 barrels of oil  equivalent per day. The Company has an average
working interest of approximately 70 percent in these wells.

         The Company  periodically reviews its oil and gas assets and identifies
that certain  properties are candidates for its ongoing  disposition  program to
rationalize the Company's asset base. The disposition  properties  typically are
mature fields or properties  with low  operating  margins,  limited or no future
growth  potential  or  ability to enhance  production,  may be  administratively
complex and are  considered  to be  non-strategic  with regard to the  Company's
future  activities.  The Company  received  $4.7  million  during 1998 and $10.7
million  during  1997 in  proceeds  from  sales of  properties  which  were used
primarily to fund development expenditures.  None of the sales were individually
significant.  Subsequent  to year end,  the  Company  sold its  interest  in the
Piceance  Basin  and  the  associated  gathering  facility  for  $28.8  million,
resulting in an estimated gain of $500,000.

         The Board has authorized, at management's discretion, the repurchase of
up to $70.0 million of the  Company's  securities.  From 1996 through 1998,  the
Company repurchased $61.5 million of its securities including 3.6 million common
shares for $57.0 million under this plan.  During 1997, the Company redeemed its
preferred  depositary  shares by issuing 3.6 million  shares of common stock and
paying $30.1 million in cash. As a result, a $1.0 million  redemption premium is
included  in  preferred   dividends  in  the  1997  consolidated   statement  of
operations.

Liquidity

         At December  31,  1998,  the Company had $6.1  million of cash and cash
equivalents on hand, $17.2 million unrestricted  marketable securities and $39.0
million of  outstanding  senior debt  compared to $89.4 million of cash and cash
equivalents on hand and $96.1 million of unrestricted  marketable  securities at
December 31, 1997. The Company's ratio of current assets to current  liabilities
was .49 at December  31,  1998,  down from 1.98 at December  31, 1997 due to the
redeployment of cash for exploration and development projects.

INFLATION AND CHANGES IN PRICES

         While certain of the Company's  costs are affected by the general level
of inflation,  factors  unique to the petroleum  industry  result in independent
price  fluctuations.  Over the past five years,  significant  fluctuations  have
occurred in oil and gas prices.  In addition,  changing prices often cause costs
of  equipment  and  supplies to vary as industry  activity  levels  increase and
decrease to reflect perceptions of future price levels. Although it is difficult
to estimate future prices of oil and gas, price  fluctuations have had, and will
continue to have, a material effect on the Company.

         The following  table  indicates the average oil and gas prices received
over the last five years and  highlights the price  fluctuations  by quarter for
1998 and 1997.  Average  gas prices were  increased  by $.13 per Mcf in 1998 and
$.05 per Mcf in 1997 by the benefit of the Company's hedging activities. Average
prices per equivalent barrel indicate the composite impact of changes in oil and

                                       27

<PAGE>    28

gas prices.  Natural gas production is converted to oil  equivalents at the rate
of six 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
                        ------
                          1998                           $  11.02           $  2.00         $  11.81
                          1997                              18.88              2.29            15.06
                          1996                              20.39              1.97            14.35
                          1995                              16.96              1.35            11.00
                          1994                              14.80              1.67            11.82

                        Quarterly
                        ---------
                         1998
                         ----
                         First                           $  13.07           $  2.19         $  13.13
                         Second                             11.10              2.02            11.97
                         Third                              10.31              1.89            11.14
                         Fourth                              9.65              1.92            11.21

                         1997
                         ----
                         First                            $ 21.18            $ 2.83          $ 18.10
                         Second                             18.33              1.85            13.09
                         Third                              18.09              1.97            13.38
                         Fourth                             16.86              2.65            16.09
</TABLE>

         At December 31, 1998, the Company was receiving an average of $9.56 per
barrel and $1.94 per Mcf for its production.

         While production levels are somewhat  controllable by the Company,  the
majority of the Company's  sales of oil and gas are made in the spot market,  or
pursuant to contracts based on spot market prices, and not pursuant to long-term
fixed-price contracts.  Accordingly,  the prices received by the Company for oil
and gas production are dependent upon numerous factors beyond the control of the
Company.  These factors  include,  but are not limited to, the level of seasonal
demand for oil and gas products,  governmental  regulations and taxes, the price
and  availability of alternative  fuels, the level of foreign imports of oil and
gas, and the overall economic environment.

YEAR 2000 MATTERS

         Historically,  certain  computer  systems,  as well as certain hardware
containing   embedded   chip   technology,    such   as   microcontrollers   and
microprocessors,   were   designed  to  utilize  a  two-digit   date  field  and
consequently, they may not be able to properly recognize dates in the Year 2000.
This could result in  significant  system  failures.  The Company  relies on its
computer-based  management  information systems, as well as embedded technology,
to  operate   instruments  and  equipment  in  conducting  its  normal  business
activities. Certain of these computer-based programs and embedded technology may
not have been designed to function  properly with respect to the  application of
dating systems relating to the Year 2000.

         In response, the Company has developed a "Year 2000 Plan" and, in 1997,
established an internal group to identify and assess potential areas of risk and
to make any required modifications to its computer systems and equipment used in
oil and gas exploration,  production,  gathering and gas processing  activities.
The Year  2000  Plan is  comprised  of  various  phases,  including  assessment,
remediation,  testing and  contingency  plan  development.  After the assessment
phase  has  been  completed  and  evaluated,   the   remediation,   testing  and
certification  phases will be implemented to ensure that the material facilities
and  business  activities  will  continue to operate  safely and  reliably,  and

                                       28

<PAGE>     29

without  interruption  after 1999.  Based upon the  results of these  activities
contingency plans will be developed to the extent deemed necessary.

         The   Company's   inventory  of  computer   hardware  and  software  is
substantially  Year  2000  compliant  except  for  two  software  packages.  The
programming  modifications  for these two  systems are  complete  and testing is
scheduled  for  the  first  quarter  1999  with  implementation  and  conversion
scheduled for the second quarter of 1999.

         The  Company  has monitor and  control  equipment  with  embedded  chip
technology which are utilized in production and gas processing  operations.  The
various  systems were reviewed in  conjunction  with the overall Year 2000 Plan.
Only one major system for gas plant  automation is currently being replaced,  at
an estimated  cost of $500,000,  with an expected  completion  date in the third
quarter of 1999.  The phone  systems  utilized  by the  Company  have or will be
upgraded  to ensure  Year 2000  compliance  at a total cost of  $110,000.  Other
systems with embedded chip technology are relatively new and should be Year 2000
compliant according to the manufacturers.

          The Company has also  undertaken to monitor the compliance  efforts of
suppliers,  contractors  and other third  parties with whom it does business and
whose computer-based systems and/or embedded technology equipment interface with
those of the Company to ensure that operations will not be adversely affected by
the Year  2000  compliance  problems  of  others.  The  Company  sent  Year 2000
readiness  questionnaires to its significant vendors,  suppliers and contractors
in the fourth  quarter of 1998 and sent second  requests in the first quarter of
1999. To date, the Company has received no responses to its questionnaires.  The
Company intends to continue to prompt its vendors, suppliers and contractors for
specific information on their Year 2000 readiness. Additionally, the Company has
taken steps to ascertain the readiness of its vendors, suppliers and contractors
through their public disclosures,  such as reports filed with the Securities and
Exchange  Commission.  According to these public disclosures,  the management of
all of the Company's significant vendors, suppliers and contractors expect to be
Year 2000 compliant prior to year end. There can be no assurance that there will
not be an adverse effect on the Company if vendors, suppliers,  customers, state
and federal  governmental  authorities  and other  third  parties do not convert
their respective systems in a timely manner and in a way that is compatible with
the Company's  information systems and embedded technology  equipment.  However,
management  believes  that  ongoing  communication  with and  assessment  of the
compliance efforts and status of these third parties will minimize these risks.

          The Company  believes that it can provide the  resources  necessary to
ensure Year 2000  compliance and expects to complete its Year 2000 Plan within a
time frame that will enable its computer-based  programs and embedded technology
equipment to function without  significant  disruption in the Year 2000. Through
1998, the Company has incurred third party costs of  approximately  $1.0 million
for software and  equipment  costs related to Year 2000  compliance  matters and
estimates  that the total  future  third party,  software  and  equipment  costs
related to Year 2000 compliance activities,  based upon information developed to
date, will be approximately $400,000,  which will be expensed as incurred. These
costs have been and will continue to be funded through  operating cash flows and
are not deemed to be material to the operations of the Company.  The cost of the
remediation  activities and the completion dates are based on management's  best
estimates and may be updated as additional  information  becomes available.  The
costs  incurred  to date and those  estimated  to be incurred in the future with
respect to Year 2000 issues do not include  internal costs. The Company does not
presently   separately  track  the  internal  costs  incurred  with  respect  to
implementation  of the Year 2000 Plan.  Such costs are  principally  the related
payroll  costs  for the  information  systems  and field  operations  personnel,
including  senior  management,  involved in the  compliance  program and related
travel and other out of pocket expenses.

          Although the Company  anticipates  minimal  business  disruption  will
occur as a result of Year 2000 issues,  in the event the computer based programs
and embedded technology  equipment of the Company, or that owned and operated by
third parties,  should fail to function properly,  possible consequences include
but are not limited to, loss of communications  links,  inability to produce and
process  natural gas, loss of electric  power,  and  inability to  automatically
process  commercial  transactions,  or engage in  similar  normal  automated  or
computerized business activities.

          To date,  the  Company has not  finalized  its  contingency  plans for
possible  Year 2000  issues.  As noted above,  in the event the  Company,  after
completion of the  assessment,  remediation  and testing phases of the Year 2000
Plan and review of the results of monitoring the  compliance  efforts and status
of third parties,  determines that contingency plans are necessary,  the Company

                                       29

<PAGE>   30

will finalize such  contingency  plans based on its assessment of outside risks.
The Company  anticipates that final contingency plans, as necessary,  will be in
place by third quarter 1999.

          The   discussion   of  the   Company's   efforts,   and   management's
expectations,   relating  to  Year  2000  compliance  contains   forward-looking
statements. Presently, the Company does not anticipate that the Year 2000 issues
will have a material  adverse effect on the operations or financial  performance
of the Company.  However,  there can be no assurance that the Year 2000 will not
adversely affect the Company and its business.


ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

         The Company utilizes  various  financial  instruments  which inherently
have some degree of market risk. The primary  sources of market risk include the
Company's  investments  in  foreign  marketable   securities,   fluctuations  in
commodity prices and interest rate fluctuations.

EQUITY PRICE RISK AND FOREIGN CURRENCY RISK

         The  Company  has  investments  in two  international  exploration  and
production  companies,  Cairn Energy plc  ("Cairn") and SOCO  International  plc
("SOCI plc"),  which are both listed on the London Stock Exchange.  The value of
these  investments is subject to the risk of  fluctuations in their stock prices
as well as fluctuations in the British pound,  the currency in which they trade.
The Company owns 11.7 million shares of Cairn and 7.8 million shares of SOCI plc
and the book and fair  market  value of the  investments  was $24.0  million  at
December 31, 1998.

PRICE FLUCTUATIONS

         The  Company's  results of  operations  are highly  dependent  upon the
prices  received  for oil and  natural  gas  production.  A program to hedge the
impact of  fluctuations  in oil and gas prices was  established  by the Board of
Directors and limits hedging activity to  non-speculative  contracts intended to
manage the risk associated with potential  future declines in commodity  prices.
At December 31, 1998,  the Company had swap contracts  outstanding  based on the
average  final  settlement  prices for a Henry Hub Natural Gas Futures  Contract
traded on the New York  Mercantile  Exchange  ("NYMEX") for 3.6 million  MMBtu's
with an average price of $2.22  expiring in October  1999.  The Company also had
collar  contracts for 3.6 million  MMBtu's based on NYMEX with an average cap of
$2.46 and an average  floor of $2.14  expiring in March 1999 and swap  contracts
based on the business days  relevant  price for  "Colorado  Interstate  Gas Co.,
Rocky  Mountains"  Index ("CIG") for 4.2 million  MMBtu's at an average price of
$2.22 expiring in March 1999.

         In 1994,  the Company  entered into a long-term  gas swap  agreement in
order to lock in the price differential between the Rocky Mountain and Henry Hub
prices on a portion of its Rocky Mountain gas  production.  The contract  covers
20,000  MMBtu's  per day  through  2004.  At  December  31,  1998,  that  volume
represented  approximately  30  percent  of the  Company's  Rocky  Mountain  gas
production.  The fair value of the contract based on the market price quoted for
a similar instrument was $576,000 at December 31, 1998.

INTEREST RATE RISK

         Total debt at December 31, 1998,  included $173.8 million of fixed debt
and $39.0  million of  floating-rate  debt  attributed  to bank credit  facility
borrowings.  As a  result,  the  Company's  annual  interest  cost in 1999  will
fluctuate based on short-term  interest rates. The impact on annual cash flow of
a ten percent change in the floating rate  (approximately 50 basis points) would
be approximately $200,000.

          At December 31, 1998,  the Company's  fixed-rate debt had a book value
of $173.8 million and a fair market value of $171.1 million. The fixed-rate debt
will mature June 15, 2007 and the  floating-rate  debt will mature  December 31,
2000.

                                       30
<PAGE>   31

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

         Reference is made to the Index to Consolidated  Financial Statements on
page 32 for the Company's  consolidated  financial statements and notes thereto.
Quarterly  financial  data for the Company is  presented on page 20 of this Form
10-K.  Supplementary schedules for the Company have been omitted as not required
or not applicable  because the information  required to be presented is included
in the financial statements and related notes.


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

         None



























                                       31

<PAGE>    32


                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



                                                                            Page
                                                                            ----
Report of Independent Public Accountants......................................33

Consolidated Balance Sheets as of December 31, 1998 and 1997..................34

Consolidated Statements of Operations
     for the years ended December 31, 1998, 1997 and 1996.....................35

Consolidated Statements of Changes in Stockholders' Equity
     for the years ended December 31, 1998, 1997 and 1996.....................36

Consolidated Statements of Cash Flows
     for the years ended December 31, 1998, 1997 and 1996.....................38

Notes to Consolidated Financial Statements....................................39















                                       32
<PAGE>    33


                    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,
1998 and 1997, and the related consolidated statements of operations, changes in
stockholders'  equity,  and cash flows for each of the three years in the period
ended December 31, 1998. 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, 1998 and 1997, and the results
of their  operations  and their  cash  flows for each of the three  years in the
period ended December 31, 1998, in conformity with generally accepted accounting
principles.




                                                   ARTHUR ANDERSEN LLP

Fort Worth, Texas,
February 10, 1999














                                       33
<PAGE>    34

<TABLE>
                                                     
                                              SNYDER OIL CORPORATION

                                            CONSOLIDATED BALANCE SHEETS
                                                  (In thousands)
<CAPTION>

                                                                                          December 31,          
                                                                                --------------------------------          
                                                                                   1998                  1997   
                                                                                ----------           -----------
                                                      ASSETS
<S>                                                                             <C>                  <C>   
Current assets
     Cash and equivalents                                                       $    6,171           $    89,443
     Accounts receivable                                                            27,572                21,521
     Inventory and other                                                             1,812                 2,911
                                                                                ----------           -----------
                                                                                    35,555               113,875
                                                                                ----------           -----------

Investments                                                                         23,983               143,066
                                                                                ----------           -----------

Oil and gas properties, successful efforts method                                  542,331               410,973
     Accumulated depletion, depreciation and amortization                         (189,348)             (136,669)
                                                                                -----------          -----------
                                                                                   352,983               274,304
                                                                                ----------           -----------

Gas facilities and other                                                            31,624                21,317
     Accumulated depreciation and amortization                                     (10,208)               (6,474)
                                                                                -----------          -----------
                                                                                    21,416                14,843
                                                                                ----------           -----------
                                                                                $  433,937           $   546,088
                                                                                ==========           ===========

                                       LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities
     Accounts payable                                                           $   21,399           $    23,278
     Accrued liabilities                                                            51,869                34,271
                                                                                ----------           -----------
                                                                                    73,268                57,549
                                                                                ----------           -----------

Senior debt                                                                         39,001                     1
Subordinated notes                                                                 173,787               173,635

Deferred taxes payable                                                               -                    31,649
Other noncurrent liabilities                                                        19,427                19,498

Stockholders' equity
     Common stock, $.01 par, 75,000,000 shares authorized,
         36,073,375 and 35,696,212 issued                                              361                   357
     Capital in excess of par value                                                238,736               234,118
     Retained earnings                                                              10,970                44,390
     Common stock held in treasury, 2,708,808 and 2,366,891 shares at cost         (46,207)              (40,461)
     Unrealized gain (loss) on investments                                         (75,406)               25,352
                                                                                -----------          -----------
                                                                                   128,454               263,756
                                                                                ----------           -----------
                                                                                $  433,937           $   546,088
                                                                                ==========           ===========

                         The accompanying notes are an integral part of these statements.
</TABLE>
                                                       34
<PAGE>     35
<TABLE>

                                              SNYDER OIL CORPORATION

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

                                                                                  Year Ended December 31,          
                                                                       --------------------------------------------          
                                                                          1998             1997            1996    
                                                                       -----------     -----------      -----------
<S>                                                                    <C>             <C>              <C>   
Revenues
   Oil and gas sales                                                   $  133,204      $   207,216      $   189,327
   Gas transportation, processing and marketing                             4,624            7,004           17,655
   Gains on sales of equity interests in investees                         -                32,800           69,343
   Gains on sales of properties                                             3,267            8,708            8,786
                                                                       ----------      -----------      -----------
                                                                          141,095          255,728          285,111
                                                                       ----------      -----------      -----------
Expenses
   Direct operating                                                        38,492           48,523           49,638
   Cost of gas and transportation                                           3,348            6,692           15,020
   Exploration                                                             48,303           17,046            4,232
   General and administrative                                              16,440           20,363           17,143
   Financing costs, net                                                    13,350           23,029           22,923
   Other expense (income)                                                    (235)             935           (1,327)
   (Gain) loss on sale of subsidiary interest                              -                (5,437)          15,481
   Depletion, depreciation and amortization                                53,950           79,862           84,547
   Property impairments                                                     5,497            7,275            2,753
                                                                       ----------      -----------      -----------

Income (loss) before income taxes, minority interest
   and extraordinary item                                                 (38,050)          57,440           74,701
                                                                       -----------     -----------      -----------

Provision (benefit) for income taxes
   Current                                                                 -                   975               33
   Deferred                                                               (13,317)          16,881            4,313
                                                                       -----------     -----------      -----------
                                                                          (13,317)          17,856            4,346
                                                                       -----------     -----------      -----------

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

Income (loss) before extraordinary item                                   (24,733)          35,465           62,950

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

Net income (loss)                                                         (24,733)          32,617           62,950
                                                                       -----------     -----------      -----------

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

Income (loss) applicable to common                                     $  (24,733)     $    26,639      $    56,740
                                                                       ===========     ===========      ===========

Income (loss) per common share before extraordinary item               $    (.74)      $       .96      $      1.81
                                                                       ==========      ===========      ===========

Net income (loss) per common share                                     $    (.74)      $       .87      $      1.81
                                                                       ==========      ===========      ===========

Income (loss) per common share before extraordinary
   item - assuming dilution                                            $    (.74)      $       .95      $      1.72
                                                                       ==========      ===========      ===========

Net income (loss) per common share - assuming dilution                 $    (.74)      $       .86      $      1.72
                                                                       ==========      ===========      ===========

Weighted average shares outstanding                                        33,416           30,588           31,308
                                                                       ==========      ===========      ===========
                         The accompanying notes are an integral part of these statements.
</TABLE>
                                                       35
<PAGE>    36

<TABLE>
                                              
                                               SNYDER OIL CORPORATION
                                        CONSOLIDATED STATEMENTS OF CHANGES IN
                                                STOCKHOLDERS' EQUITY
                                                  (In thousands)
<CAPTION>

                                     Total         Unrealized       Common                  Capital in
                                  Stockholders'  Gains (Losses)   Stock Held    Retained    Excess of    Common    Preferred
                                    Equity       on Investments   in Treasury   Earnings    Par Value    Stock       Stock        
                                 -------------   --------------   -----------   ---------   ----------   ------    ---------        

<S>                              <C>                <C>            <C>          <C>          <C>         <C>        <C>   
Balance, December 31, 1995       $  235,368         $    591       $  (2,457)   $(29,001)    $ 265,911   $  314     $   10

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

  Other comprehensive income,
    net of tax
    Unrealized gain on investments   11,330           11,330            -           -             -         -          -
                                  ----------
  Comprehensive income (1)           74,280
                                  ----------
  Issuance of 267,000 shares for
    common stock grants and
    exercise of stock options         2,924             -               (258)       -            3,179        3        -            

  Issuance of 399,000 shares
    of common                         3,693             -               -           -            3,689        4        -

  Repurchase of 640,000 shares
    of common                        (7,044)            -               (795)       -           (6,243)      (6)       -

  Repurchase of 1,000 shares
    of preferred                       (142)            -               -           -             (142)     -          -

  Dividends                         (14,411)            -               -         (8,238)       (6,173)     -          -    
                                  ---------        ---------       ---------    --------      --------   ------     ------

Balance, December 31, 1996          294,668           11,921          (3,510)     25,711       260,221      315         10

  Net income                         32,617             -               -         32,617          -         -          -
  
  Other comprehensive income,
    net of tax
    Unrealized gain on investments   13,431           13,431            -           -             -         -          -
                                   --------
  Comprehensive income (1)           46,048
                                   --------
  Issuance of 607,000 shares for
    common stock grants and
    exercise of stock options         2,957             -               -           -            2,951        6        -

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

  Issuance of 530,000 shares held
    in treasury                       8,655             -              8,655        -             -         -          -

  Repurchase of 2,647,000 shares
    of common                       (45,606)            -            (45,606)       -             -         -          -

  Repurchase of 291,000 shares
    of preferred                    (30,102)            -               -         (1,049)      (29,050)     -           (3)

  Conversion of 743,000 shares of
    preferred to 3,632,000 shares
    of common                          -                -               -           -              (29)       36        (7)

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

Balance, December 31, 1997          263,756           25,352         (40,461)     44,390       234,118       357      -

(Continued)
</TABLE>
                                                       36
<PAGE> 37
<TABLE>


                                              SNYDER OIL CORPORATION
                                        CONSOLIDATED STATEMENTS OF CHANGES IN
                                          STOCKHOLDERS' EQUITY (CONTINUED)
                                                  (In thousands)
<CAPTION>
                                          Total         Unrealized       Common                  Capital in
                                       Stockholders'  Gains (Losses)   Stock Held    Retained    Excess of    Common    Preferred
                                         Equity       on Investments   in Treasury   Earnings    Par Value    Stock       Stock     
                                      -------------   --------------   -----------   ---------   ----------   ------    ---------   
                                 

<S>                                   <C>            <C>            <C>           <C>            <C>          <C>        <C>    
Balance, December 31, 1997               263,756          25,352       (40,461)       44,390       234,118       357         -

  Net loss                               (24,733)           -             -          (24,733)         -          -           -

  Other comprehensive loss,
    net of tax
    Unrealized loss on investments       (77,405)       (77,405)          -             -             -          -           -
    Deferred tax valuation allowance     (23,353)       (23,353)          -             -             -          -           -
                                      ----------   
  Comprehensive loss (1)                (125,491)
                                      ----------
  Issuance of 377,162 shares for
    common stock grants and
    exercise of stock options              4,622           -              -             -           4,618          4         -

  Repurchase of 341,917 shares
    of common                             (5,746)          -            (5,746)         -             -          -           -

  Dividends                               (8,687)          -              -           (8,687)         -          -           -     
                                      ----------     ----------     ----------    ----------     ---------    ------     ------

Balance, December 31, 1998            $  128,454     $  (75,406)    $  (46,207)   $   10,970     $ 238,736    $  361     $   -     
                                      ==========     ==========     ==========    ==========     =========    ======     ======
<FN>
(1)      Represents total accumulated other comprehensive income or loss.
</FN>
</TABLE>
                                                       37

<PAGE>   38

<TABLE>

                                               SNYDER OIL CORPORATION
                                       CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
(In thousands)                                                                   Year Ended December 31,           
                                                                     ----------------------------------------------           
                                                                        1998              1997             1996    
                                                                     ------------     -----------       -----------
<S>                                                                  <C>              <C>               <C>   
Operating activities
   Net income (loss)                                                 $   (24,733)     $    32,617       $   62,950
   Adjustments to reconcile net income (loss) to net
      cash provided by operations
          Amortization of deferred credits                                -                -                (1,052)
          Gains on sales of investments                                   -               (32,800)         (68,343)
          Gains on sales of properties                                    (3,267)          (8,708)          (8,786)
          Exploration expense                                             48,303           17,046            4,232
          Equity in (earnings) losses of unconsolidated subsidiaries      -                  (760)            (421)
          (Gain) loss on sale of subsidiary interest                      -                (5,437)          15,481
          Depletion, depreciation and amortization                        53,950           79,862           84,547
          Property impairments                                             5,497            7,275            2,753
          Amortization of discount                                           144           -                -
          Deferred taxes                                                 (13,318)          15,348            4,313
          Minority interest                                               -                 4,119            7,405
          Loss on early extinguishment of debt                            -                 4,381           -
          Changes in current and other assets and liabilities
            Decrease (increase) in
               Accounts receivable                                        (4,598)          24,612          (15,869)
               Inventory and other                                           452              426            5,175
            Increase (decrease) in
               Accounts payable                                           (1,879)          (8,688)           2,771
               Accrued liabilities                                        16,386           (9,497)            (316)
               Other liabilities                                          (1,778)           2,245            6,890
                                                                     ------------     -----------       ----------
          Net cash provided by operations                                 75,159          122,041          101,730
                                                                     -----------      -----------       ----------

Investing activities
   Acquisition, development and exploration                             (192,995)        (135,901)        (128,598)
   Proceeds from sales of investments                                     -               156,969            1,635
   Outlays for investments                                                -                -                (9,013)
   Proceeds from sales of properties                                       4,728           10,740           73,620
                                                                     -----------      -----------       ----------
          Net cash realized (used) by investing                         (188,267)          31,808          (62,356)
                                                                     ------------     -----------       ----------

Financing activities
   Issuance of common                                                      4,622            2,982            1,523
   Issuance of subordinated notes                                         -               168,261           -
   Increase (decrease) in senior indebtedness                             39,000          (89,775)         (13,289)
   Early extinguishment of convertible subordinated notes                 -               (85,199)          -
   Dividends                                                              (8,687)         (12,889)         (14,411)
   Deferred credits                                                       -                -                  (120)
   Redemption of preferred                                                (5,099)         (30,102)          -
   Repurchase of stock                                                    -               (45,606)          (7,186)
   Repurchase of subordinated notes                                       -                -                (5,232)
                                                                     -----------      -----------       ----------
          Net cash realized (used) by financing                           29,836          (92,328)         (38,715)
                                                                     -----------      -----------       ----------

Increase (decrease) in cash                                              (83,272)          61,521              659
Cash and equivalents, beginning of year                                   89,443           27,922           27,263
                                                                     -----------      -----------       ----------
Cash and equivalents, end of year                                    $     6,171      $    89,443       $   27,922
                                                                     ===========      ===========       ==========

Noncash investing and financing activities
   Acquisition via subsidiary stock issuance                         $    -           $    -            $  115,067
   Acquisition of properties recorded as senior debt                      -                -                31,730
   Exchange of subsidiary stock for stock of investee                     -                30,923           -
   Acquisition of properties and stock via stock issuances                -                 8,655            3,693
   Exchange of common stock to retire notes receivable                       647           -                -
</TABLE>

                                                       38
<PAGE>   39

                             SNYDER OIL CORPORATION

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)      ORGANIZATION AND NATURE OF BUSINESS

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

     In October 1997, the Company sold its 74 percent interest in Patina Oil and
Gas Corporation  ("Patina").  Net proceeds from the sale were approximately $127
million resulting in a $2.8 million gain, net of tax.

(2)      SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

         The  consolidated  financial  statements  include  the  accounts of the
Company. Affiliates in which the Company owns more than 50 percent but less than
100 percent are fully  consolidated,  with the related  minority  interest being
deducted from subsidiary earnings and stockholders' equity.  Affiliates in which
the Company owns between 20 percent and 50 percent are  accounted  for using the
equity  method.  Affiliates  in which the Company  owns less than 20 percent are
accounted for using the cost method. At December 31, 1998,  affiliates accounted
for under the cost method included Cairn and SOCI plc.

Risks and Uncertainties

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

         The  preparation of financial  statements in conformity  with generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions  that  affect the  reported  amounts of assets and  liabilities  and
disclosure of  contingent  assets and  liabilities  at the date of the financial
statements  and the  reported  amounts  of  revenues  and  expenses  during  the
reporting period. Actual results could differ from those estimates.

Oil and Gas Operations

         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 1998,
the Company did not provide for any such impairments.  During 1997 and 1996, the
Company  provided  unproved  property  impairments of $700,000 and $2.8 million,
respectively.   Exploratory  expenses,   including  geological  and  geophysical
expenses  and delay  rentals,  are charged to expense as  incurred.  Exploratory
drilling costs are initially capitalized, but charged to expense if and when the
well is determined to be  unsuccessful.  All exploratory  costs are reclassified
from operating expenses to investing activities for purposes of calculating cash
flow from  operations.  Exploratory  costs totaled $48.3 million in 1998,  $17.0
million in 1997 and $4.2 million in 1996. For  exploratory  drilling costs where
management is assessing the appropriateness of significant capital expenditures,
amounts are capitalized  pending  finalization of spending plans. Other costs of
drilling exploratory wells are capitalized pending determination within one year
of whether they have discovered proved commercial reserves.  Costs of productive

                                       39

<PAGE>    40

wells,  unsuccessful  developmental  wells and productive leases are capitalized
and  amortized  on a  unit-of-production  basis  over the life of the  remaining
proved  or  proved  developed  reserves,  as  applicable.  Gas is  converted  to
equivalent  barrels  at the  rate  of six  Mcf to one  barrel.  Amortization  of
capitalized  costs  is  generally  provided  on  a  property-by-property  basis.
Estimated  future  abandonment  costs (net of  salvage  values)  are  accrued at
unit-of-production  rates and  taken  into  account  in  determining  depletion,
depreciation and amortization.

         The Company follows Statement of Financial Accounting Standards No. 121
("SFAS  121"),  "Accounting  for the  Impairment  of  Long-Lived  Assets and for
Long-Lived  Assets to be Disposed  Of." SFAS 121  requires the Company to assess
the need for an impairment of  capitalized  costs of oil and gas  properties and
other   assets.   Oil  and  gas   properties   are   generally   assessed  on  a
property-by-property  basis. If an impairment is indicated based on undiscounted
expected  future net cash flows,  then it is  recognized  to the extent that net
capitalized costs exceed discounted expected future net cash flows.  Accordingly
in 1998 and 1997,  the  Company  provided  for $5.5  million  and $6.6  million,
respectively, for such impairments. During 1996, the Company did not provide for
any such impairments.

Section 29 Tax Credits

         The Company from time to time enters into  arrangements to monetize its
Section  29 tax  credits.  These  arrangements  result in revenue  increases  of
approximately  $.40 per Mcf on  production  volumes  from  qualified  Section 29
properties. As a result of such arrangements,  the Company recognized additional
gas revenues of $933,000  during 1998, $2.4 million during 1997 and $2.5 million
during  1996.  Of these  amounts,  $1.3 million in 1997 and $1.5 million in 1996
were recognized by Patina.  These arrangements,  without Patina, are expected to
continue through 2002.

Revenue Recognition

         Revenues from the sale of crude oil and liquids  produced are generally
recognized  upon  the  passage  of  title,  net of  royalties  and  net  profits
interests.

         Revenues from natural gas production  are generally  recorded using the
sales  method,  net of royalties and net profits  interests.  Under this method,
revenue is recognized  based on the cash received rather than the  proportionate
share of gas  produced.  Gas  imbalances  at December 31, 1998 and 1997 were not
significant.

Financial Instruments

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

                                                                   December 31,               December  31,
                                                                       1998                       1997    
                                                            -------------------------    -----------------------
                                                                Book         Fair           Book         Fair
                                                                Value        Value          Value        Value
                                                            ------------  -----------    -----------  -----------

                                                                                (In thousands)

              <S>                                           <C>           <C>             <C>          <C>      
              Cash and equivalents                          $    6,171    $   6,171       $  89,443    $  89,443
              Investments                                       23,983       23,983         143,066      143,066
              Senior debt                                      (39,001)     (39,001)             (1)          (1)
              Subordinated notes                              (173,787)     171,063)       (173,635)    (178,063)
              Long-term commodity contracts                      -              576           -            7,318
</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 are
estimated based on their December 31, 1998 and 1997 closing market prices.

                                       40

<PAGE>    41

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

         In 1994, the Company  entered into a long-term gas swap  arrangement in
order to lock in the price differential between the Rocky Mountain and Henry Hub
prices on a portion of its Rocky Mountain gas  production.  The contract  covers
20,000  MMBtu's  per day  through  2004.  At  December  31,  1998,  that  volume
represented  approximately  30  percent  of the  Company's  Rocky  Mountain  gas
production.  The fair value of the contract was based on the market price quoted
for a similar instrument.

Comprehensive Income

         Effective  January 1, 1998, the Company adopted  Statement of Financial
Accounting  Standards No. 130 ("SFAS 130"),  "Reporting  Comprehensive  Income,"
which  establishes  standards for reporting and display of comprehensive  income
and its  components  in a full  set of  general  purpose  financial  statements.
Comprehensive  income includes net income and other comprehensive  income, which
includes,  but is not limited to, unrealized gains for marketable securities and
future contracts,  foreign currency translation  adjustments and minimum pension
liability  adjustments.  The accompanying  consolidated financial statements for
the Company reflect other comprehensive income consisting of unrealized gains or
losses  for  marketable  securities.  SFAS 130 did not have  any  effect  on the
Company's financial condition or operations.

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 holds marketable securities of two foreign energy companies
accounted for using the cost method.  The Company follows Statement of Financial
Accounting  Standards No. 115 ("SFAS 115"),  "Accounting for Certain Investments
in Debt and Equity Securities," which requires that such investments be adjusted
to their fair value with a corresponding  increase or decrease to  stockholders'
equity.  The following table sets forth the book/fair  values and carrying costs
of these investments (in thousands):
<TABLE>
<CAPTION>

                                            December 31, 1998                  December 31, 1997     
                                      ----------------------------       ----------------------------
                                       Book/Fair         Carrying         Book/Fair         Carrying
                                         Value             Cost             Value             Cost   
                                      -----------      -----------       -----------      -----------   

         <S>                          <C>              <C>               <C>              <C>        
         Cairn                        $    17,231      $    73,140       $    96,062      $    73,140
         SOCI plc                           6,752           30,923            47,004           30,923
                                      -----------      -----------       -----------      -----------
                                      $    23,983      $   104,063       $   143,066      $   104,063
                                      ===========      ===========       ===========      ===========
</TABLE>

Cairn

          In  November  1996,  the  Company  exchanged  its  interest in Command
Petroleum  Ltd. for 16.2  million  shares of freely  marketable  common stock of
Cairn, an  international  independent  oil company based in Edinburgh,  Scotland
whose shares are listed on the London Stock  Exchange.  In the first  quarter of
1997, the Company sold 4.5 million shares at an average price of $8.81 per share
realizing $39.2 million in proceeds and resulting in a gain of $13.0 million. In
accordance  with SFAS 115, at December 31, 1998,  investments  were decreased by
$55.9  million in gross  unrealized  holding  losses,  stockholders'  equity was
decreased by $36.3  million and deferred  taxes  payable was  decreased by $19.6
million.  At December 31, 1997,  investments  were increased by $22.9 million in
gross  unrealized  holding  gains,  stockholders'  equity was increased by $14.9
million and deferred taxes payable was increased by $8.0 million.

                                       41

<PAGE>     42

SOCI plc

          In May 1997, a newly  formed  entity,  SOCI plc,  completed an initial
public offering of its shares on the London Stock Exchange.  Simultaneously with
the offering, the Company exchanged its shares of SOCO International Operations,
Inc., which included the Company's interests in projects in Russia, Mongolia and
Thailand,  for 7.8 million  shares (15.9  percent of the total) of SOCI plc. The
offering raised  approximately  $75.0 million of new equity capital for SOCI plc
to fund its ongoing projects.  The Company recognized a gain of $19.8 million as
a result of this  exchange and is  restricted  from selling its shares until May
1999.  In  accordance  with SFAS 115, at December  31,  1998,  investments  were
decreased by $24.2 million in gross  unrealized  holding  losses,  stockholders'
equity was decreased by $15.7  million and deferred  taxes payable was decreased
by $8.5  million.  At December 31,  1997,  investments  were  increased by $16.1
million in gross unrealized holding gains, stockholders' equity was increased by
$10.5 million and deferred taxes payable was increased by $5.6 million.

          During 1999, the Company will continue to evaluate whether the decline
in market value of such investments is other than temporary.

Notes Receivable

          The Company held notes  receivable  of $647,000 due from a director at
December 31, 1997, which originated in connection with an option to purchase ten
percent of the Company's  international  affiliates due April 10, 1998. In March
1998, the director  tendered 31,000 shares of Company common stock with a market
value of $647,000 to retire such notes.

(4)       OIL AND GAS PROPERTIES AND GAS FACILITIES

         The  cost of oil and gas  properties  at  December  31,  1998  and 1997
includes  $17.2  million  and  $21.3  million,   respectively,   of  unevaluated
leasehold. Such properties are held for exploration,  development or resale. The
following table sets forth costs incurred  related to oil and gas properties and
gas processing and transportation facilities:
<TABLE>
<CAPTION>

                                                               1998               1997                 1996       
                                                            -----------       ------------         ------------
                                                                              (In thousands)

     <S>                                                    <C>               <C>                  <C>        
     Proved acquisitions                                    $    16,186       $      3,676         $   273,088
     Acreage acquisitions                                         7,481              5,609              24,589
     Development                                                119,130             85,998              43,075
     Exploration                                                 48,303             17,338               4,588
     Gas processing, transportation and other                    10,653              3,425               3,612
                                                            -----------       ------------         -----------
                                                            $   201,753       $    116,046         $   348,952
                                                            ===========       ============         ===========
</TABLE>

         During 1998, the Company  incurred  $167.4  million on exploration  and
development  activities  while placing 78 wells on  production  with 18 wells in
progress at year end. In the Gulf of Mexico, development activity included $33.9
million to complete the installation of a production  platform at Main Pass 261,
three  development  wells, one recompletion and one development well in progress
at year end. Exploration  activities included $19.1 million for four exploration
discoveries and $28.4 million for five unsuccessful  tests.  Additionally,  $8.7
million was invested in 3-D seismic acquisition and evaluation.

         The Company  continued its successful  drilling program in the Rockies.
Expenditures  for 1998,  totaled $52.8 million to place 65 development  wells on
production  with seven wells in progress at year end. One  exploration  well was
successful  totaling  $552,000 and two unsuccessful  tests totaled $1.0 million.
Additional  exploration  expense of $2.3  million was  incurred  for 3-D seismic
acquisition and evaluation.

         The  Company  spent  $12.8  million  in North  Louisiana  to place five
development  wells on production with one development  well and four exploratory
wells in progress at year end. One exploration  well was  unsuccessful  totaling
$1.0 million. An additional $6.8 million of exploration expense was incurred for
the acquisition and evaluation of 3-D seismic in the area.

                                       42

<PAGE>      43

Acquisitions

         During  1998,  the  Company  spent $16.2  million to acquire  producing
properties  and $7.5 million on acreage  purchases  in and around the  Company's
operating  hubs.  Of the  producing  property  acquisitions,  $5.4  million  was
incurred  to  purchase  an  incremental  interest  in the Main  Pass  properties
operated  by the  Company in the Gulf of  Mexico.  The  Company  also spent $2.6
million in North Louisiana to purchase producing properties and a gas processing
facility and $8.0 million to purchase incremental interests in properties in the
Piceance Basin of western Colorado and the Washakie Basin of southern Wyoming.

         The Company also completed a non-cash acquisition in the second quarter
of 1998. The Company acquired 75 percent of Amoco Production Company's ("Amoco")
interest  in the  Beaver  Creek Unit and two  associated  gas plants in the Wind
River Basin in Wyoming in exchange for the Jonah Field  portion of the Company's
properties in the Deep Green River Basin project in Wyoming.  Under terms of the
agreement,  Snyder also received  Amoco's interest in the Deep Green River Basin
project  outside  the Jonah  Field area and  retained  the deep  rights in Jonah
beneath the Mesaverde horizon at about 12,250 feet.

         During the third  quarter of 1998,  the Company  received  $3.0 million
cash for the exchange of its interest in the Cage Ranch Field in South Texas for
interests in certain  producing  and  non-producing  properties  in the Washakie
Basin of Wyoming and  purchased  a related  property  interest  from a different
third party for approximately $1.5 million,  generating net cash of $1.5 million
and resulting in a $3.1 million gain.

         Proved  acquisitions during 1996 included $218.4 million related to the
formation of Patina  including the acquisition of Gerrity Oil & Gas Corporation.
In October 1997, the Company sold its interest in Patina for approximately  $127
million in cash and the elimination of approximately $170 million in debt.

(5)       INDEBTEDNESS

          The following indebtedness was outstanding on the respective dates:

<TABLE>
                                                                       December 31,        December 31,
                                                                          1998                 1997       
                                                                      ------------         ------------
                                                                               (In thousands)

          <S>                                                          <C>                  <C>      
          Subordinated notes                                           $   173,787          $  173,635
          Bank facility                                                     39,001                   1
                                                                       -----------          ----------
                                                                       $   212,788          $  173,636
                                                                       ===========          ==========
</TABLE>

         Snyder maintains a revolving credit facility ("Snyder  Facility") under
which  credit  availability  is  adjusted  semiannually  to  reflect  changes in
reserves and asset values.  The borrowing base available  under the facility was
$150.0  million at December 31, 1998.  Borrowings  under the facility  generally
bear  interest at prime,  with an option to select  LIBOR plus .75 percent or CD
plus .75  percent.  The margin on LIBOR or CD  increases to one percent when the
Company's  consolidated  senior  debt  becomes  greater  than 80  percent of its
consolidated  tangible net worth, as defined.  During 1998, the average interest
rate under the facility was 6.1 percent.  The Company pays certain fees based on
the unused  portion of the  borrowing  base.  Covenants,  in  addition  to other
requirements,  require  maintenance of a current working capital ratio of one to
one as defined and adjusted for unused  portions of the Snyder  Facility,  limit
the incurrence of additional  debt and restrict  dividends,  stock  repurchases,
certain investments,  other indebtedness and unrelated business activities. Such
restricted payments are limited by a formula that includes proceeds from certain
securities,  cash flow and other  items.  Based on such  limitations,  more than
$175.0  million was available for the payment of dividends and other  restricted
payments at December 31, 1998.

         In June 1997,  Snyder  issued  $175.0  million of 8.75  percent  Senior
Subordinated  Notes  ("Notes")  due June 15,  2007.  The  Notes  were  sold at a
discount resulting in an 8.875 percent effective interest rate. The net proceeds
of the  offering  were  $168.3  million  which  were used to redeem  convertible
subordinated  notes  and pay down  the  balance  outstanding  under  the  credit
facility. The Notes are redeemable at the option of the Company on or after June

                                       43

<PAGE>    44

15, 2002, initially at 104.375 percent of principal,  and at prices declining to
100 percent of  principal on or after June 15, 2005.  Upon the  occurrence  of a
change of control, as defined in the Notes, Snyder would be obligated to make an
offer  to  purchase  all  outstanding  Notes at a price  of 101  percent  of the
principal  amount thereof.  In addition,  Snyder would be obligated,  subject to
certain  conditions,  to make  offers to  purchase  the Notes  with the net cash
proceeds of certain  asset sales or other  dispositions  of assets at a price of
100 percent of the principal  amount thereof.  The proposed merger with Santa Fe
Energy Resources,  Inc.  described in Note (11) does not obligate the Company to
make any  offer to  repurchase  the  Notes.  The  Notes  are  unsecured  general
obligations  of Snyder and are  subordinated  to the Snyder  Facility and to any
existing and future  indebtedness  of Snyder's  subsidiaries.  The Notes contain
covenants  that,  among  other  things,  limit  the  ability  of Snyder to incur
additional indebtedness, pay dividends, engage in transactions with shareholders
and affiliates,  create liens, sell assets, engage in mergers and consolidations
and make investments in unrestricted subsidiaries.  Such restricted payments are
limited by a formula that includes proceeds from certain  securities,  cash flow
and  other  items.  Based on such  limitations,  more  than  $70.0  million  was
available for the payment of dividends and other restricted payments at December
31, 1998. The Company's  international  subsidiaries are considered unrestricted
subsidiaries.  As such,  their  activities  and the proceeds  realized  from any
disposition of these interests are not restricted by the Note covenants.

         In 1994,  Snyder  issued  $86.3  million of seven  percent  convertible
subordinated  notes due May 15, 2001.  The notes were redeemed by the Company in
June 1997 at 103.51  percent of principal.  As a result of the note  redemption,
the Company incurred a loss of $4.4 million or $2.8 million net of tax ($.09 per
common  share)  which  has  been  recorded  as  an  extraordinary  item  in  the
accompanying financial statements.

         Maturities of indebtedness for the next five years are $39.0 million in
2000, with no amounts due in 1999, 2001, 2002 or 2003. The long-term  portion of
the  Snyder  Facility  is  scheduled  to  expire  December  31,  2000.  However,
management has the ability and intent to renew both the short-term and long-term
facilities and extend their maturities on a regular basis.

         Consolidated  cash  payments for  interest  were $15.5  million,  $28.6
million and $21.9 million, respectively, for 1998, 1997 and 1996.

(6)      FEDERAL INCOME TAXES

         At December 31, 1998, 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 1998, 1997 and 1996 follows:
<TABLE>
<CAPTION>

                                                                        1998            1997          1996               
                                                                     ---------       ---------      ----------   
     

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

         For book  purposes,  the  components  of the net deferred tax asset and
liability at December 31, 1998 and 1997, respectively, were:

<TABLE>
<CAPTION>
                                                                          1998                         1997   
                                                                       -----------                 -----------
                                                                                  (In thousands)
<S>                                                                    <C>                         <C>    
Deferred tax assets
     NOL and capital loss carryforwards                                $    35,769                 $    27,307
     AMT credit carryforwards                                                1,181                       1,401
     Production payment receivables                                          3,950                       5,557
     Reserves and other                                                      6,733                       6,031
     Unrealized investment losses                                              654                       -  
                                                                       -----------                 -----------
                                                                            48,287                      40,296
                                                                       -----------                 -----------
    (Continued)
</TABLE>
                                                        44
    
<PAGE>    45
<TABLE>
<CAPTION>


                                                                           1998                        1997   
                                                                       -----------                 -----------
                                                                                  (In thousands)


<S>                                                                    <C>                         <C> 
Deferred tax liabilities
     Depreciable and depletable property                                   (24,934)                    (30,964)
     Investments and other                                                  -                          (25,884)
     Unrealized investment gains (losses)                                   -                          (15,097)
                                                                       -----------                 -----------
                                                                           (24,934)                    (71,945)
                                                                       -----------                 -----------

Deferred tax asset (liability)                                              23,353                     (31,649)
Valuation allowance                                                        (23,353)                     -      
                                                                       -----------                 -----------

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

         The  Company had regular net  operating  loss  carryforwards  of $102.0
million at December 31, 1998. The majority of these carryforwards expire between
2007 and 2010 with a minimal amount expiring  between 2000 and 2005. At December
31, 1998, the Company also had alternative  minimum tax credit  carryforwards of
$1.2 million  which are available  indefinitely.  Cash payments for income taxes
were $500,000 in 1998 and 1997. No cash  payments were made for income  taxes in
1996.

         The  valuation  allowance  noted above relates to the tax effect of the
unrealized loss on marketable securities included in stockholders' equity.

(7)       STOCKHOLDERS' EQUITY

         A total of 75 million common shares,  $.01 par value, are authorized of
which 36.1 million were issued and 33.4 million were outstanding at December 31,
1998. In 1998, the Company  issued 377,162 shares  primarily for the exercise of
stock options and  repurchased  341,917 shares of common stock for $5.7 million.
In 1997,  the Company  issued a total of 4.2 million  shares of common  stock as
follows: 3.6 million for the conversion of preferred shares, 300,000 in exchange
for 2.1 million of outstanding  warrants and 308,000  primarily for the exercise
of stock  options.  The Company also issued  530,000 shares of treasury stock in
exchange for a director's ten percent interest in SOCO  International  Holdings,
Inc. During 1997, the Company repurchased 2.6 million shares of common stock for
$45.6 million.  In 1996, the Company issued 666,000 shares of common stock, with
399,000  shares issued in exchange for the remaining  outstanding  stock of SOCO
Offshore,  Inc.  (formerly  DelMar  Operating,  Inc.) and 267,000  shares issued
primarily for the exercise of stock options and  repurchased  725,000  shares of
common stock for $7.0 million.  Quarterly dividends of $.065 per share were paid
in 1998 and  1997.  For book  purposes,  for the  period  between  June 1995 and
September 1996,  common stock dividends were in excess of retained earnings and,
as such, were treated as distributions of capital.

         A total of ten million  preferred  shares,  $.01 par  value,  have been
authorized  none of which are  outstanding  at December 31, 1998.  In 1993,  4.1
million  depositary  shares (each  representing a quarter interest in a share of
$100 liquidation  value stock) of six percent  preferred stock were sold through
an underwriting.  The net proceeds were $99.3 million.  During 1996, the Company
repurchased  6,000  shares for  $142,000.  During 1997,  the Company  called the
preferred stock for redemption.  The preferred stock was convertible into common
stock  at  $20.46  per  share  or the  liquidation  preference  was  $25.00  per
depositary share, plus accrued and unpaid dividends. As a result of the call, 72
percent of the preferred shares were converted into 3.6 million shares of common
stock.  The remaining  preferred  shares were redeemed for $29.1 million  before
accrued  dividends and a redemption  premium.  The Company paid $5.0 million and
$6.2 million ($1.50 per six percent  convertible  depositary share per annum) in
preferred  dividends  during  1997  and  1996,  respectively.   A  $1.0  million
redemption  premium  for the  preferred  shares  is also  included  in the  1997
preferred dividend amount in the statement of operations.

         Effective December 31, 1997, the Company adopted Statement of Financial
Accounting Standards No. 128 ("SFAS 128"), "Earnings per Share" which prescribes
standards for computing and  presenting  earnings per share and  supersedes  APB
Opinion  No. 15,  "Earnings  per  Share." In  accordance  with SFAS 128,  income

                                       45

<PAGE>    46

applicable to common has been  calculated  based on the weighted  average shares
outstanding  during the year and income applicable to  common-assuming  dilution
has  been  calculated  assuming  the  exercise  or  conversion  of all  dilutive
securities  as of January  1, 1997 and 1996,  or as of the date of  issuance  if
later. The following tables illustrate the calculation of earnings per share for
income from continuing operations.
<TABLE>
<CAPTION>


                                       (In thousands except per share data)

                                                                 Income             Shares            Per-Share
                                                              ------------        -----------        -----------
       For the Year Ended December 31, 1998
       ------------------------------------
<S>                                                           <C>                      <C>           <C>        
Loss applicable to common shareholders                        $   (24,733)             33,416        $     (.74)
                                                              ============        ===========        ===========


       For the Year Ended December 31, 1997
       ------------------------------------  
Income before extraordinary item                              $    35,465
Preferred dividends                                                (5,978)
                                                              ------------

Income before extraordinary item
   available to common shareholders                           $    29,487              30,588        $       .96

Effect of Dilutive Securities
Stock options                                                                             513
                                                                                  -----------                            
Income before extraordinary item
   applicable to common-assuming dilution                     $    29,487              31,101        $       .95
                                                              ===========         ===========        ===========


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

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

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

Income applicable to common-assuming dilution                 $    62,950              36,513        $      1.72
                                                              ===========         ===========        ===========
</TABLE>

         As of December  31,  1998,  the only  potentially  dilutive  securities
outstanding  were stock  options  that have yet to be  exercised.  The  dilutive
effect of  outstanding  stock  options  would have been to  increase  the shares
outstanding by 213,000.

         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
percent, 60 percent, 100 percent) and expire five years from the date of grant.

                                       46
<PAGE>    47

          At  December  31,  1998,  the  Company  has  two  fixed  stock  option
compensation  plans,  which are described above. The Company applies APB Opinion
No. 25, "Accounting for Stock Issued to Employees," and related  Interpretations
in  accounting  for the  plans.  Accordingly,  no  compensation  cost  has  been
recognized  for these fixed stock option plans.  Had  compensation  cost for the
Company's fixed stock option compensation plans been determined  consistent with
the method established by SFAS 123,  "Accounting for Stock-Based  Compensation,"
the Company's net income (in  thousands)  and earnings per share would have been
reduced to the pro forma amounts indicated below:
<TABLE>
<CAPTION>

                                                                1998              1997             1996   
                                                              ---------         --------         ---------

<S>                                                           <C>               <C>               <C>     
Net income (loss)                   As Reported               $ (24,733)        $ 32,617          $ 62,950
                                    Pro forma                 $ (27,874)        $ 29,260          $ 61,936

Net income (loss) per common        As Reported                 $  (.74)          $  .87            $ 1.81
     share                          Pro forma                   $  (.83)          $  .76            $ 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 1998, 1997 and 1996, respectively: dividend yield
of 1.5 percent, 1.6 percent and 2.8 percent;  expected volatility of 43 percent,
41 percent and 44 percent;  risk-free interest rates of 5.4 percent, 6.1 percent
and 5.7 percent; and an expected life of 4.5 years.

         A summary of the status of the  Company's  two fixed stock option plans
as of December  31,  1998,  1997 and 1996 and changes  during the years ended on
those dates is presented below (shares are in thousands):
<TABLE>
<CAPTION>

                                          1998                      1997                      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                          2,327      $14.64           1,674     $12.72         1,711       $13.21
Granted                               881       17.72           1,013      16.82           519         9.50
Exercised                            (363)      18.71            (295)     11.27          (255)        6.69
Forfeited                            (261)      15.74             (65)     14.88          (301)       14.71
                                 ---------                  ----------                 --------
Outstanding at end of year          2,584       15.86           2,327      14.64         1,674        12.72
                                  ========                    ========                 ========

Options exercisable at
   year end                         1,181                       1,105                      772

Weighted-average fair
   value of options
   granted during
   the year                         $6.40                       $5.96                    $3.27
</TABLE>





                                                    47
<PAGE>   48


         The following table  summarizes  information  about fixed stock options
outstanding at December 31, 1998:
<TABLE>
<CAPTION>

                                      Options Outstanding                               Options Exercisable          
                       -------------------------------------------------------    -------------------------------          
                                              Weighted-
                            Number             Average                                Number
         Range          Outstanding at        Remaining            Weighted-      Exercisable at     Weighted-
          of             December 31,      Contractual Life         Average        December 31,       Average
    Exercise Prices          1998             (in years)        Exercise Price        1998         Exercise Price
  -------------------  ---------------     ----------------   ----------------    --------------   --------------

  <S>                       <C>                  <C>                <C>                <C>             <C>           
  $ 6.00 to    9.75           317,000            2.4                $ 8.94               225,000       $ 8.75
   10.63 to   14.25           428,000            2.1                 13.73               374,000        13.85
   16.06 to   17.31           802,000            3.4                 16.25               290,000        16.16
   17.69 to   18.40           705,000            3.1                 17.81               230,000        18.07
   18.63 to   23.81           332,000            3.9                 20.13                62,000        19.99
                        -------------                                              -------------
  $ 6.00 to   23.81         2,584,000            3.0                $15.86             1,181,000       $14.59
                        -------------                                              -------------
</TABLE>

(8)      DISCLOSURE OF SEGMENT FINANCIAL INFORMATION

         Effective December 31, 1998, the Company adopted Statement of Financial
Accounting  Standards No. 131,  "Disclosures about Segments of an Enterprise and
Related  Information,"  which requires  disclosure of certain  information about
operating segments and geographic areas of operation.

         The Company operates in three geographic areas: the Gulf of Mexico, the
Rocky  Mountains  and  northern  Louisiana.  All three  areas are engaged in the
production, development,  acquisition and exploration of oil and gas properties.
The accounting  policies of the divisions are the same as those described in the
summary  of  significant   accounting   policies.   The  Company  evaluates  the
performance of its geographic  segments based on profit or loss from  operations
before  income  taxes  and does not  allocate  financing  costs.  The  Company's
divisions are managed  separately  because of the different  strategies  used in
developing and producing oil and gas properties in different geographic regions.
The only assets  which  relate to specific  reporting  segments  are oil and gas
properties and gas facilities.  In addition to its three geographic segments, in
1997 the Company's  interest in Patina was managed as a discrete  entity and was
evaluated separately from all other operating segments. Patina incurred separate
financing  costs and was evaluated  based on net profit or loss from  operations
after financing costs.

         Revenues from one customer of the Rocky Mountain Division accounted for
32  percent  of the  Company's  consolidated  revenues,  and  revenues  from one
customer  of the  Gulf  of  Mexico  Division  accounted  for 33  percent  of the
Company's consolidated revenues.
<TABLE>
<CAPTION>

                                                               December 31, 1998 Segment Disclosure                
                                                    ----------------------------------------------------------                

                                                      Gulf of         Rocky          Northern         Total
                                                      Mexico        Mountains        Louisiana       Segments
                                                    ----------     -----------      ----------      ----------

<S>                                                 <C>            <C>              <C>             <C>       
Oil and gas revenues                                $   63,421     $    58,794      $    4,657      $  126,872
Other revenues                                             953           5,129           3,185           9,267
Depletion, depreciation and amortization                33,576          14,892           2,438          50,906
Property impairments                                     5,497          -               -                5,497
Exploration expense                                     37,150           3,353           7,800          48,303
Segment profit/(loss)                                  (23,023)         17,210          (3,059)         (8,872)

Oil & gas properties and gas facilities, net           135,057         198,477          30,027         363,561
Capital expenditures                                    60,370          68,420          18,266         147,056

</TABLE>
                                                        48

<PAGE>    49
<TABLE>
<CAPTION>

                                                               December 31, 1997 Segment Disclosure      
                                                 -----------------------------------------------------------------      
                                                    Gulf of       Rocky       Northern                     Total
                                                    Mexico      Mountains     Louisiana     Patina       Segments
                                                 ----------    ----------    ----------   ----------    ----------

<S>                                              <C>           <C>           <C>          <C>           <C>       
Oil and gas revenues                             $   62,080    $   66,300    $    4,588   $   73,365    $  206,333
Other revenues                                        5,265         9,555         3,624          679        19,123
Depletion, depreciation and amortization             24,377        15,426         1,664       36,263        77,730
Property impairments                                  2,150         5,125        -            -              7,275
Exploration expense                                  12,470         2,191         2,264          121        17,046
Net financing costs                                  -             -             -            12,473        12,473
Segment profit                                       17,679        20,759         1,651        7,883        47,972

Oil & gas properties and gas facilities, net        113,832       149,679        17,805       -            281,316
Capital expenditures                                 40,568        39,092         4,866       11,989        96,515
</TABLE>

         The following  tables  reconcile  segment  information to  consolidated
totals:
<TABLE>
<CAPTION>
                                                                                          December 31,          
                                                                                --------------------------------          
                                                                                   1998                  1997   
                                                                                ----------           -----------
<S>                                                                             <C>                  <C>   
Revenues
     Total revenues for reportable segments                                     $  126,872           $   206,333
     Revenue from marketing agreements,
        hedging and other                                                            6,332                   883
                                                                                ----------           -----------
     Total consolidated revenues                                                $  133,204           $   207,216
                                                                                ==========           ===========

Profit or (loss)
     Total segment profit/(loss)                                                $   (8,872)          $    47,972
     Other revenues                                                                  6,332                   883
     General and administrative expenses                                           (17,987)              (15,716)
     Net financing costs                                                           (13,350)              (10,556)
     Depletion, depreciation and amortization                                       (3,044)               (2,133)
     Gains on sales of investments                                                  -                     32,800
     Gain on sale of subsidiary interest                                            -                      5,437
     Other corporate expenses                                                       (1,129)               (1,247)
                                                                                -----------          ------------
     Income/(loss) before income taxes, minority
        interest and extraordinary item                                         $  (38,050)          $    57,440
                                                                                ===========          ===========

Assets
     Total assets for reportable segments                                       $  363,561           $   281,316
     Current assets                                                                 35,555               113,875
     Investments                                                                    23,983               143,066
     Other assets                                                                   10,838                 7,831
                                                                                ----------           -----------
     Total assets                                                               $  433,937           $   546,088
                                                                                ==========           ===========

Capital expenditures
     Total segment capital expenditures                                         $  147,056           $    96,515
     Corporate capital expenditures                                                  6,394                 2,193
                                                                                ----------           -----------
     Total consolidated capital expenditures                                    $  153,450           $    98,708
                                                                                ==========           ===========
</TABLE>
(9)      RECENTLY ISSUED STATEMENTS OF FINANCIAL ACCOUNTING STANDARDS

         In June 1998,  Statement  of  Financial  Accounting  Standards  No. 133
("SFAS 133"),  "Accounting for Derivative  Instruments and Hedging  Activities,"
was released.  The statement establishes  accounting and reporting standards for
derivative  instruments and hedging activities.  It requires that derivatives be
recognized as assets or liabilities  and measured at their fair value.  SFAS 133
will be adopted  in 2000 and is not  expected  to have a material  effect on the
Company's financial condition or operations.

                                                       49

<PAGE>   50

(10)     EMPLOYEE RETIREMENT PLAN

         The Company has a defined  contribution plan pursuant to Section 401(k)
of the  Internal  Revenue  Code.  Substantially  all  employees  are eligible to
participate after the completion of four months of service and may contribute up
to 15  percent  of  their  compensation.  The  Board  of  Directors  elected  to
contribute an amount equal to at least seven percent of each  employee's  pretax
salary for the years ended  December 31, 1998,  1997 and 1996 resulting in total
Company contributions of $942,000, $766,000 and $1.2 million, respectively.

(11)      SUBSEQUENT EVENTS

         On January 13, 1999, the Company  announced its agreement to merge with
Santa  Fe  Energy  Resources,   Inc.  ("Santa  Fe")  creating  Santa  Fe  Snyder
Corporation. The Board of Directors of each company has unanimously approved the
transaction  and  committed  to vote his or her  shares in favor of the  merger.
Snyder  shareholders  will receive 2.05 shares of Santa Fe common stock for each
share of Snyder resulting in Snyder shareholders owning approximately 40 percent
of the outstanding  shares after the merger. It is expected that the transaction
will be  accounted  for as a purchase.  John C.  Snyder will be the  Chairman of
Santa Fe Snyder  Corporation and James L. Payne,  currently the Chairman and CEO
of Santa Fe, will be the CEO of the new company. The eleven person board will be
composed of five members from Snyder's current  directors and six from Santa Fe.
The Form S-4 has been  filed  with the SEC and,  pending  shareholder  and other
required approvals, the merger is expected to be completed in the second quarter
of 1999.

         In January 1999 the Company sold its interest in the Piceance Basin and
the  associated  gathering  facility  for $28.8  million  cash,  resulting in an
estimated gain of approximately $500,000.

(12)     GUARANTOR CONDENSED CONSOLIDATING FINANCIAL INFORMATION

         Pursuant to the Notes,  all of the Company's  subsidiaries  except SOCO
International,  Inc. (the "Unrestricted  Subsidiary") would be guarantors of the
Notes  (the  "Restricted   Group").   The  condensed   consolidating   financial
information  below  shows the  impact  of the  guarantors  and the  Unrestricted
Subsidiary to the Company's  consolidated  position as of and for the year ended
December 31, 1998. In the aggregate, the Unrestricted Subsidiary holds less than
ten  percent  of the total  assets and  revenues  included  in the  consolidated
totals.
<TABLE>
<CAPTION>

                                      CONDENSED CONSOLIDATING BALANCE SHEETS
                                                 December 31, 1998
                                                  (In thousands)

                                                   Restricted          Unrestricted
                                                      Group             Subsidiary        Consolidated
                                                   -----------         ------------       ------------

<S>                                                <C>                 <C>                <C>        
Current assets                                     $    31,183         $     4,372        $    35,555
Investments                                                  1              23,982             23,983
Oil and gas properties, net                            352,983             -                  352,983
Gas facilities and other, net                           21,416             -                   21,416
                                                   -----------         -----------        -----------
     Total assets                                  $   405,583         $    28,354        $   433,937
                                                   ===========         ===========        ===========

Current liabilities                                $    73,268         $   -              $    73,268
Senior debt                                             39,001             -                   39,001
Subordinated notes                                     173,787             -                  173,787
Deferred taxes payable                                  (5,802)              5,802             -
Other noncurrent liabilities                            19,427             -                   19,427
Total stockholders' equity                             105,902              22,552            128,454
                                                   -----------         -----------        -----------
     Liabilities and stockholders'
         equity                                    $   405,583         $    28,354        $   433,937
                                                   ===========         ===========        ===========
</TABLE>
                                                        50


<PAGE>    51
<TABLE>

                                 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
                                           Year Ended December 31, 1998
                                                  (In thousands)
<CAPTION>
                                                   Restricted          Unrestricted
                                                      Group             Subsidiary           Consolidated
                                                   ----------          ------------          ------------
<S>                                                <C>                   <C>                  <C>      
Revenues                                           $ 141,082             $      13            $ 141,095
Expenses                                             179,143                     2              179,145
                                                   ---------             ---------            ---------
Income (loss) before taxes, minority interest
     and extraordinary item                          (38,061)                   11              (38,050)
Income taxes                                          13,317                 -                   13,317
                                                   ---------             ---------            ---------
Net income (loss)                                  $ (24,744)            $      11            $ (24,733)
                                                   =========             =========            =========
</TABLE>

 (13)    COMMITMENTS AND CONTINGENCIES

         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
percent.  The complaint  alleges,  among other things,  that the defendants have
failed to pay proper  royalties  under the  lease,  have  unlawfully  commingled
production  with  production from other leases and have breached their duties to
reasonably  develop  the lease.  The  plaintiffs  also claim  damages for fraud,
trespass and similar matters,  and demand actual and putative damages.  Although
the complaint does not specify the amount of damages  claimed,  plaintiffs  have
submitted  calculations  showing total  damages  against all owners in excess of
$175.0  million.  The Company and the other interest owners have filed an answer
denying  the claims and intend to contest the suit  vigorously.  Activity in the
case has been stayed pending  resolution of a variety of administrative  motions
in the matter.

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

         On January 15,  1999,  a  stockholder  of the Company  filed a putative
class action complaint in the Delaware Court of Chancery, No. 16900-NC,  seeking
to enjoin the merger of the Company into Santa Fe Energy Resources,  Inc. on the
proposed terms and seeking  damages.  Defendants  named in the complaint are the
Company,  each of its  directors and Santa Fe. The  plaintiff  alleges  numerous
breaches of the duties of care and loyalty owed by the Company and its directors
to the  purported  class in connection  with entering into the merger  agreement
with Santa Fe. The plaintiff further alleges that Santa Fe aided and abetted the
Company and its  directors  in their  alleged  breaches of fiduciary  duty.  The
defendants  believe  the  complaint  is without  merit and intend to  vigorously
defend the action.

         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.

         The Company has firm  transportation  commitments in the Gulf of Mexico
which may exceed the  Company's  production  capacity  in the area over the next
several  years.  The Company may incur demand  charges in the $1.0 million range
for the unused  transportation  commitments,  however,  the amount of production
shortfall,  if any,  is subject to prices,  weather,  timing of  operations  and
availability of equipment and services.

         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.

                                       51

<PAGE>   52

         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.

(14)     UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION

         Independent  petroleum  consultants  directly evaluated 84 percent,  87
percent,  and 99 percent of proved reserves at December 31, 1998, 1997 and 1996,
respectively, based on pretax present value assuming a ten percent discount rate
with year end pricing and costs. All reserve estimates are based on economic and
operating  conditions at that time.  Statement of Financial Accounting Standards
No. 69 established the standardized  measure of discounted future net cash flows
relating  to proved oil and gas  reserve  quantities  based on year end  prices,
costs,  statutory tax rates and a ten percent annual  discount rate.  Future net
cash flows as of each year end were computed in  accordance  with this method 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
constant.  With respect to certain properties that historically have experienced
seasonal curtailment,  the reserve estimates assume that the seasonal pattern of
such  curtailment  will continue in the future.  There can be no assurance  that
actual  production  will equal the estimated  amounts used in the preparation of
reserve projections.

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

         All reserves  included in the tables  below are located  onshore in the
United  States or  in the waters of the Gulf of Mexico.  The first set of tables
reflects  the  Company,  excluding  Patina,  and the second set of tables  shows
consolidated  Company totals.  In October 1997, the Company sold its interest in
Patina which  represented  71,918 MBOE of proved  reserves at December 31, 1996.
Subsequent to year end the Company sold its interest in the Piceance Basin which
represented 8,443 MBOE of proved reserves at December 31, 1998.










                                       52

<PAGE>    53
<TABLE>
<CAPTION>

                                                                       Excluding Patina          
                                                                  -----------------------------          

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

<S>                                                                <C>                 <C>    
Balance, December 31, 1996                                         18,022              308,977

          Revisions of previous estimates                            (266)              (6,649)
          Extensions, discoveries and additions                     1,790              100,874
          Production                                               (2,049)             (41,377)
          Purchases of reserves in place                               11                1,568
          Sales of reserves in place                                 (748)                (225)
                                                                ---------          -----------
Balance, December 31, 1997                                         16,760              363,168
                                                                ---------          -----------

          Revisions of previous estimates                            (211)              (5,066)
          Extensions, discoveries and additions                     3,171              148,378
          Production                                               (1,909)             (56,186)
          Purchases of reserves in place                            1,124               90,686
          Sales of reserves in place                                 (393)             (50,227)
                                                                ----------         ------------
Balance, December 31, 1998                                         18,542              490,753
                                                                =========          ===========
</TABLE>
<TABLE>
<CAPTION>

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

<S>                                                                <C>                 <C>    
December 31, 1996                                                  16,070              200,664
                                                                =========          ===========

December 31, 1997                                                  16,101              297,490
                                                                =========          ===========

December 31, 1998                                                  17,383              391,951
                                                                =========          ===========
</TABLE>
<TABLE>
<CAPTION>

                                                                      Excluding Patina        
                                                               -------------------------------        
                                                                    Year Ended December 31,    
Changes in Standardized Measure of                             -------------------------------    
   Discounted Future Net Cash Flows -                              1998               1997    
                                                               -----------        ------------    
                                                                       (In thousands)

<S>                                                            <C>                <C>    
Standardized measure of discounted future
   net cash flows, beginning of year                           $   291,818        $    438,656

Revisions:
         Net changes in prices and production costs                (79,926)           (284,824)
         Estimates of quantities                                    22,173               2,676
         Development costs incurred                                 (1,822)             (9,241)
         Accretion of discount                                      37,527              43,866
         Net changes in income taxes                                40,006              70,050
         Changes in production rates and other                     (28,541)            (31,871)
                                                               ------------       ------------

         Net revisions                                             (10,583)           (209,344)

Extensions, discoveries and additions                               85,899             142,209
Production                                                        (104,767)           (104,465)
Future development costs incurred                                   31,098              21,250
Purchases of reserves in place                                      65,919               2,374
Sales of reserves in place                                         (37,215)              1,138
                                                               ------------       ------------

Standardized measure of discounted future
   net cash flows, end of year                                 $   322,169        $    291,818
                                                               ===========        ============
</TABLE>

                                                        53

<PAGE>     54

<TABLE>
<CAPTION>

                                                                                      Consolidated        
                                                                               ---------------------------        

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

<S>                                                                               <C>              <C>    
Balance, December 31, 1995                                                        24,247           395,718

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

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

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

Balance, December 31, 1997                                                        16,760           363,168

          Revisions of previous estimates                                           (211)           (5,066)
          Extensions, discoveries and additions                                    3,171           148,378
          Production                                                              (1,909)          (56,186)
          Purchases of reserves in place                                           1,124            90,686
          Sales of reserves in place                                                (393)          (50,227)
                                                                               ----------        ---------

Balance, December 31, 1998                                                        18,542           490,753
                                                                               =========         =========
</TABLE>

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

                                                                                      Consolidated         
                                                                               ---------------------------         

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

<S>                                                                               <C>              <C>    
December 31, 1995                                                                 21,637           330,524
                                                                               =========         =========

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

December 31, 1997                                                                 16,101           297,490
                                                                               =========         =========

December 31, 1998                                                                 17,383           391,951
                                                                               =========         =========
</TABLE>

                                                        54
<PAGE>
<TABLE>
<CAPTION>


                                                                                           Consolidated         
                                                                                           December 31,         
Standardized Measure of Discounted Future                                        ------------------------------
   Net Cash Flows -                                                                  1998                1997   
                                                                                  -----------        -----------
                                                                                          (In thousands)

<S>                                                                               <C>                <C>        
Future cash inflows                                                               $ 1,127,778        $ 1,016,597

Future costs:
          Production                                                                 (385,866)          (339,147)
          Development                                                                 (78,424)           (64,237)
                                                                                  ------------       -----------

Future net cash flows before income taxes                                             663,488            613,213

Undiscounted future income taxes                                                     (106,132)          (148,049)
                                                                                  ------------       -----------

Future net cash flows                                                                 557,356            465,164

10 percent discount factor                                                           (235,187)          (173,346)
                                                                                  ------------       -----------

Standardized measure of discounted future net cash flows                          $   322,169        $   291,818
                                                                                  ===========        ===========
</TABLE>
<TABLE>
<CAPTION>


                                                                                 Consolidated             
                                                                    -------------------------------------             
                                                                            Year Ended December 31,              
Changes in Standardized Measure of Discounted Future           --------------------------------------------------
   Net Cash Flows -                                                1998              1997                1996     
                                                               ------------      ------------        ------------
                                                                                (In thousands)

<S>                                                            <C>                <C>                <C>   
Standardized measure of discounted future
   net cash flows, beginning of year                           $   291,818        $   938,592        $   331,106

Revisions:
         Net change in prices and production costs                 (79,926)          (609,467)           528,525
         Estimates of quantities                                    22,173              2,676             10,915
         Development costs incurred                                 (1,822)            (9,241)           (13,027)
         Accretion of discount                                      37,527             81,361  (a)        46,045   (b)
         Net change in income taxes                                 40,006            230,075           (242,536)
         Change in production rates and other                      (28,541)           (31,871)            11,052
                                                               ------------       -----------        -----------

         Net revisions                                             (10,583)          (336,467)           340,974

Extensions, discoveries and additions                               85,899            142,209            111,797
Production                                                        (104,767)          (164,330)          (146,257)
Future development costs incurred                                   31,098             21,250             18,400
Purchases of reserves in place                                      65,919              2,374            330,225   (b)
Sales of reserves in place                                         (37,215)          (311,810) (a)       (47,653)
                                                               -----------        -----------        -----------

Standardized measure of discounted future
   net cash flows, end of year                                 $   322,169        $   291,818        $   938,592
                                                               ===========        ===========        ===========
<FN>
(a)      In 1997, $12.5 million in "Accretion of Discount" was included in "Sales" due to the sale of Patina in
         October 1997.

(b)      In 1996, $12.9 million in "Purchases" were included in "Accretion of Discount" due to the significance
         of the accretion related to the reserves purchased in the acquisition of Gerrity Oil & Gas Corporation.
</FN>
</TABLE>
                                                       55

<PAGE>    56


                                     PART IV


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

      (a)      1.  Reference is made to Item 8 on page 31.

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

               3.  Exhibits.

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

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

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

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

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

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

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

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

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

      4.3      -   Amendment Number 1 to  Rights  Agreement, dated as of January
                   13, 1999, between the Registrant and ChaseMellon  Shareholder
                   Services, L.L.C., as Rights Agent. *



                                       56
<PAGE> 57


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

      10.1     -   Agreement  and  Plan  of  Merger,  dated  January  13,  1999,
                   between  Registrant  and Santa Fe  Energy  Resources  Inc. --
                   incorporated by reference from Exhibit 2.1 to Santa Fe Energy
                   Resources,   Inc.'s   Registration   Statement  on  Form  S-4
                   (Registration No. 333-71595).

      10.2      -  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).

      10.2.1    -  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).

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

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

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

      10.6      -  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).

      10.7      -  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).

      10.8      -  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).

      10.9      -  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).

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

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

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



                                       57

<PAGE>  58


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

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

      10.12     -  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).

      10.12.1   -  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).

      10.12.2   -  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).

      10.12.3   -  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).

      10.12.4   -  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).

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

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

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

      10.12.8   -  Eighth  Amendment  dated  as  of  November 1, 1998  to  Fifth
                   Restated Credit Agreement. *

      10.13     -  Directors  Deferral  Plan  for  Independent  Directors of the
                   Registrant.

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

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

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

                                       58
<PAGE>  59


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

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

      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.*

      27        -  Financial Data Schedule.*

      99.1      -  Reserve  letter from  Netherland,  Sewell &  Associates, Inc.
                   dated   February  3,  1999  to  the  Registrant  interest  as
                   of December 31, 1998*

      (b)          Current reports  on  Form 8-K filed during the quarter  ended
                   December 31, 1998.



      * Filed herewith.











                                       59
<PAGE>   60


                                    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 *                                              March 31, 1999
------------------------    Director and Chairman of the Board
John C. Snyder              (Principal Executive Officer)

/s/ William G. Hargett *                                          March 31, 1999
------------------------    Director, President and Chief         
William G. Hargett          Operating Officer


/s/ Roger W. Brittain *                                           March 31, 1999
------------------------    Director 
Roger W. Brittain


/s/ John A. Hill *                                                March 31, 1999
------------------------    Director
John A. Hill


/s/ B. J. Kellenberger *                                          March 31, 1999
------------------------    Director
B. J. Kellenberger


/s/ Harold R. Logan, Jr. *                                        March 31, 1999
------------------------    Director 
Harold R. Logan, Jr.


/s/ James E. McCormick *                                          March 31, 1999
------------------------    Director 
James E. McCormick


/s/ Edward T.  Story *                                            March 31, 1999
------------------------    Director 
Edward T.  Story

/s/ Mark A. Jackson *                                             March 31, 1999
------------------------    Senior Vice President and Chief 
Mark A. Jackson             Financial Officer (Principal Financial
                            and Accounting Officer)

* By: /s/John H. Karnes
     -------------------
      John H. Karnes
      Attorney-in-Fact

                                       60