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                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                                ________________
                                    FORM 10-K


         [ 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

         [   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
               SECURITIES EXCHANGE ACT OF 1934

                         Commission File Number 0-26662
                                  PANACO, Inc.
             (Exact name of registrant as specified in its charter)

                Delaware                                      43 - 1593374


         (State or other jurisdiction                     (I.R.S. Employer
          of incorporation or organization)               Identification Number)
         

         1100 Louisiana, Suite 5100
            Houston, TX  77002                                 77002-5220
         (Address of principal executive offices)              (Zip Code)

          Registrant's telephone number, including area code: (713) 970 - 3100


                 Securities registered pursuant to Section 12(d) of the Act:
                                                            None

           Securities registered pursuant to Section 12(g) of the Act:
                          Common Stock, $0.01 par value
                                (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  the  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. [ ]

The  aggregate  market value of the voting stock held by  non-affiliates  of the
registrant was approximately $14,877,008 as of March 31, 1999.

          23,985,927 shares of the registrant's Common Stock were outstanding as
          of March 31, 1999.


                       Documents Incorporated by Reference

     Portions of the registrant's annual proxy statement, to be filed within 120
days after December 31, 1998, are incorporated by reference into Part III.

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<PAGE>


                          PANACO, Inc. and Subsidiaries

                           Annual Report on Form 10-K
                   For the Fiscal Year Ended December 31, 1998


<TABLE>

                                Table of Contents

<CAPTION>



                                                                                   Page Number
<S>                                                                                   <C>   

Part I

  Item 1.      Business                                                                 2
  Item 2.      Properties                                                              16
  Item 3.      Legal Proceedings                                                       23
  Item 4.      Submission of Matters to a Vote of Security Holders                     24

Part II

  Item 5.       Market for Common Stock and
                Related Shareholder Matters                                            24
  Item 6.       Selected Financial Data                                                28
  Item 7.       Management's Discussion and Analysis of Financial
                Condition and Results of Operations                                    29
  Item 7a.      Quantitative and Qualitative Disclosures
                About Market Risks                                                     35
  Item 8.       Financial Statements and Supplementary Data                            36
  Item 9.       Changes in and Disagreements with Accountants on
                Accounting and Financial Disclosure                                    36

Part III

  Item 10.      Directors and Executive Officers of the Registrant                     37
  Item 11.      Executive Compensation                                                 37
  Item 12.      Security Ownership of Certain Beneficial Owners and
                Management                                                             37
  Item 13.      Certain Relationships and Related Transactions                         37

Part IV

  Item 14.      Exhibits, Financial Statement Schedules and Reports
                On Form 8-K                                                            37

Glossary of Selected Oil and Gas Terms                                                 40

Signatures                                                                             43

</TABLE>

                                                        
                                       -1-
<PAGE>


ITEM 1. BUSINESS.
----------------

     Forward-looking statements in this Form 10-K, future filings by the Company
with the  Securities  and  Exchange  Commission  ("SEC"),  the  Company's  press
releases and oral statements by authorized  officers of the Company are intended
to be subject to the safe harbor provisions of the Private Securities Litigation
Reform Act of 1995. Investors are cautioned that all forward-looking  statements
involve  risks and  uncertainty,  including  without  limitation,  the risk of a
significant  natural  disaster,  the inability of the Company to insure  against
certain  risks,  the adequacy of its loss  reserves,  fluctuations  in commodity
prices,  the  inherent  limitations  in the  ability  to  estimate  oil  and gas
reserves, changing government regulations, as well as general market conditions,
competition and pricing.  The Company believes that  forward-looking  statements
made by it are based on reasonable  expectations.  However, no assurances can be
given that actual  results will not differ  materially  from those  contained in
such forward-looking  statements.  The words "estimate," "anticipate," "expect,"
"predict,"   "believe"  and  similar   expressions   are  intended  to  identify
forward-looking statements.

     Unless the context otherwise requires, all references herein to "PANACO" or
the "Company"  include PANACO,  Inc., a Delaware  corporation,  its consolidated
subsidiaries   and  the  Company's   predecessor  Pan  Petroleum  MLP.   Certain
capitalized  terms  relating to the oil and natural gas  business are defined in
the Glossary. The Company's website may be found at www.PANACO.com.

     PANACO,  Inc.  is in the  business of  acquiring,  drilling  and  operating
offshore oil and natural gas properties in the Gulf of Mexico and onshore in the
Gulf Coast Region  (collectively,  the "GOM Region").  The Company is a Delaware
corporation that was organized in October 1991. Effective September 1, 1992, Pan
Petroleum MLP, the Company's predecessor,  was merged into the Company.  Between
1984 and 1988,  this  predecessor  acquired a total of 114 limited  partnerships
engaged in the onshore oil and natural gas business. With the acquisition of the
West Delta Fields in 1991, the Company shifted its emphasis offshore. Additional
offshore  properties  were  acquired in 1994,  1995,  1996,  1997 and 1998.  The
Company has  experienced  substantial  growth as a result of the  acquisition of
offshore  properties from Amoco (the "Amoco  Acquisition")  and BP Exploration &
Oil, Inc. (the "BP Acquisition") along with Gulf Coast properties,  both onshore
and in Texas  and  Louisiana  State  waters,  acquired  as part of the  Goldking
Companies, Inc. (the "Goldking Acquisition").

     The Company's  office is located at 1100  Louisiana,  Suite 5100,  Houston,
Texas  77002-5220,  and its  telephone  number  is  (713)  970-3100,  FAX  (713)
970-3151.

Business Strategy
-----------------

     The Company's strategy is to systematically grow its reserves,  production,
cash flow and earnings  through a program  focused on the GOM Region,  including
(i) strategic  acquisitions  and mergers,  (ii)  exploitation and development of
acquired  properties,  (iii)  marketing  of existing  infrastructure  and (iv) a
selective  exploration  program.  As a  result  of the BP,  Amoco  and  Goldking
Acquisitions,  described  below, the Company has an inventory of development and
exploration projects that provide additional reserve potential. The key elements
of the Company's objectives are outlined as follows:

     Strategic Acquisitions and Mergers
     
     The Company has an  acquisition  strategy  which focuses its efforts on GOM
Region properties that have a backlog of development and exploitation  projects,
significant  operating control,  infrastructure value and opportunities for cost
reduction.   The  properties   the  Company  seeks  to  acquire   generally  are
geologically  complex with multiple reservoirs,  have an established  production
history and are candidates for  exploitation.  Geologically  complex fields with
multiple  reservoirs  are  fields in which  there  are  multiple  reservoirs  at
different  depths and wells which penetrate more than one reservoir and have the
potential  for  recompletion  in more  than  one  reservoir.  In  pursuing  this
strategy,  the Company  identifies  properties that may be acquired,  preferably
through negotiated transactions or, where appropriate,  sealed bid transactions.


                                      -2-
<PAGE>

Once properties are acquired,  the Company  focuses on reducing  operating costs
and   implementing   production   enhancements   through  the   application   of
technologically advanced production and recompletion  techniques.

     Over the past seven years, the Company has taken advantage of opportunities
to  acquire  interests  in a  number  of  producing  properties  which  fit  its
acquisition  strategy.  A historical summary,  through December 31, 1998, of the
Company's acquisitions is illustrated below:

<PAGE>
<TABLE>

<CAPTION>

                                                                      Cumulative          Cumulative
                                            Purchase   Purchase         Capital              Cash          SEC
Acquisition              Seller              Date       Price       Expenditures(a)         Flow(b)      PV 10(c)
-------------------------------------------------------------------------------------------------------------------
                                                                 (dollars in millions)
<S>                       <C>                <C>           <C>            <C>                <C>           <C>


West Delta Fields(d)     CATO(e)           May 1991   $ 19.6           $ 18.8              $ 55.1        $  6.9
Zapata Properties        Zapata            Jul 1995      2.7(f)           2.1                15.2           3.3
Amoco Properties         Amoco             Oct 1996     40.4             43.7                32.0          27.7
Goldking                 Shareholders      Jul 1997     27.5(g)           9.5                11.2          29.6
BP Properties            BP                May 1998     19.6              1.8                 4.4          21.0
_______________

(a) Excludes exploration expenses for each acquisition subsequent to the date of
    acquisition.
(b) Defined as net revenues less direct operating expense.
(c) As of December 31, 1998.
(d) Excludes  $4.0  million  for  repair of Tank  Battery  #3 in the West Delta
    Fields.
(e) Conoco, ARCO, Texaco and Oxy.
(f) Excludes a production payment and fee sharing agreement with the seller.
(g) Excludes debt and liabilities of Goldking in the amount of $22.3 million.
</TABLE>

     Future  acquisitions  of  properties  may include  acquisitions  of working
interests,  royalty interests,  net profits interests,  production payments, and
other forms of direct or indirect  ownership  interest or  interests  in oil and
natural gas production.  The Company may also acquire general or limited partner
interests in general or limited  partnerships  and interests in joint  ventures,
corporations,  or other  entities  that own,  manage,  or are formed to acquire,
explore  for,  or develop  oil and  natural  gas  properties  or  conduct  other
activities associated with the ownership of oil and natural gas production.  The
Company  may also  acquire  or  participate  in the  expansion  of  natural  gas
processing plants and natural gas transportation or gathering systems.

     The success of the Company's  acquisitions will depend on (a) the Company's
ability to  establish  accurately  the volumes of  reserves  and rates of future
production from producing  properties  being  considered for acquisition and the
future net revenues  attributable to reserves from such properties,  taking into
account future operating costs,  market prices for oil and natural gas, rates of
inflation,  risks attendant to production of oil and natural gas, and a suitable
return on investment,  and (b) the Company's ability to purchase  properties and
produce and market oil and natural gas  therefrom  at prices and rates that over
time will generate cash flows  resulting in an attractive  return on the initial
investment.  The Company's  cash flow and return on investment  will vary to the
extent that the  Company's  production  from an acquired  property is greater or
less than that estimated at the time of acquisition because of, for example, the
results  of  drilling  or  improved  recovery  programs,  the demand for oil and
natural  gas,  or changes in the prices of oil and  natural  gas from the prices
used to calculate the purchase price for producing properties.  The Company will
evaluate any  economically  feasible project that would enhance the value of its
properties.  Such a project may involve both the  acquisition  of developed  and
undeveloped properties and the drilling of infield wells.

     While the Company tends to focus on  acquisitions  of properties from large
integrated oil companies,  it evaluates a broad range of acquisition  and merger
opportunities.  The Company has  assembled  a staff with  significant  technical
experience in evaluating,  identifying and exploiting GOM Region properties.  In
addition,  the Company is regarded in the industry as a competent buyer with the
proven ability to close transactions in a timely manner. Based on these factors,
the Company is usually asked to bid on significant  producing  property sales in
the GOM Region.

BP Acquisition
--------------

     On May  14,  1998  PANACO  entered  into a  definitive  agreement  with  BP
Exploration  & Oil,  Inc.  ("BP") to acquire  BP's 100%  interest in East Breaks
Blocks 165 and 209 and 75% interest in High Island  Block 587.  The  Acquisition
closed on May 26, 1998 and was accounted for using the purchase  method.  PANACO
acquired the properties for $19.6 million in cash.  Included with the properties
is 3-D seismic data covering twenty offshore blocks.  PANACO became the operator
of all three blocks effective June 1, 1998.

                                      -3-
<PAGE>

     The  production  platform  in Block 165 is named  "Snapper."  This  mammoth
structure,  located in 863 feet of water, is among the tallest bottom  supported
structures  in the Gulf of Mexico.  The two wells in High  Island  Block 587 are
completed subsea and tied back to the East Breaks 165 production  platform.  The
remaining 25% of High Island Block 587 is owned by Burlington Resources.

     The Company acquired 31.72 miles of 12" oil pipeline, with capacity of over
20,000 barrels of oil per day,  which ties the  production  platform back to the
High Island Pipeline System,  the major oil  transportation  system in the area.
The Acquisition also included 9.3 miles of 12 3/4" gas pipeline,  which ties the
production  platform  back to the High  Island  Offshore  System,  the major gas
transportation system in the area.

Goldking Acquisition
--------------------

     Effective  July 31, 1997, the Company  acquired  Goldking  Companies,  Inc.
("Goldking"),  a privately  owned,  Houston-based  oil and natural gas  company.
Through the Goldking  acquisition,  the Company  obtained  estimated  additional
Proved  Reserves  of 37.9  Bcfe from 234 wells  located  primarily  in Texas and
Louisiana,  both  onshore  and in State  waters.  Goldking  also had a  sizeable
portfolio  of  exploration  prospects  developed  using  3-D  Seismic  data,  an
extensive  development  program and a staff of people  experienced in Gulf Coast
oil and natural gas  operations.  As part of the  transaction,  the Company also
acquired three pipelines totaling 19 miles in length.  The Acquisition  provides
the Company with attractive  development  opportunities  in the currently active
Lower Frio/Vicksburg play in Trinity Bay, Chambers County, Texas.

     The Company acquired Goldking by merging  Goldking's  corporate parent, The
Union Companies, Inc. ("Union") into Goldking Acquisition Corp., a newly formed,
wholly-owned  subsidiary of the Company.  The individual  shareholders  of Union
received merger  consideration  consisting of $7.5 million in cash, $6.0 million
in notes (which were paid in October 1997) and 3,154,930  Company Common Shares,
valued for  purposes of the  transaction  at $14.0  million.  The  Company  also
assumed the debt and net liabilities of Goldking in the amount of $22.3 million.
In 1998 the Company merged the Union  subsidiaries  and changed the name of that
subsidiary to PANACO Production Company.

Amoco Acquisition
-----------------

     In October 1996, the Company acquired interests in six offshore fields from
Amoco Production Company for $40.4 million. In consideration for such interests,
the  Company  issued  Amoco  2,000,000  Common  Shares and paid the sum of $32.0
million in cash. The interests  acquired  include (1) a 33a% working interest in
the East Breaks 160 Field (two  Blocks)  and a 33a%  interest in the High Island
302 Field, both operated by Unocal  Corporation;  (2) a 50% interest in the High
Island 309 Field  (two  Blocks),  a 12%  interest  in the High  Island 330 Field
(three Blocks) both operated by Coastal Oil and Gas Corp., (3) a 12% interest in
the High Island 474 Field (four Blocks), operated by Phillips Petroleum Company;
and (4) a 12.5%  interest in the West Cameron 180 Field (one Block)  operated by
Texaco.  The Company  acquired an  additional  25%  interest in West Cameron 180
Field in 1998.

     Exploitation and Development of Acquired Properties

     The Company has an inventory of exploitation projects including development
drilling,  workovers,  sidetrack  drilling,  recompletions  and artificial  lift
enhancements.  As of December 31,  1998,  25% of the  Company's  total SEC PV-10
relates to Proved Undeveloped  Reserves.  The Company uses advanced technologies
where  appropriate in its development  activities to convert Proved  Undeveloped
Reserves to Proved Developed  Producing  Reserves.  These  technologies  include
horizontal  drilling and through tubing  completion  techniques,  new lower cost
coiled  tubing   workover   procedures  and  reprocessed  2-D  and  3-D  Seismic
interpretation.  A majority of the identified  capital projects can be completed
with the  Company's  existing  platform  and  pipeline  infrastructure,  thereby
improving project economics.

     Marketing of Existing Infrastructure

     Along with its purchase of producing properties,  the Company has platform,
pipeline and processing equipment  infrastructure.  The Company has interests in
23 offshore  platforms  and 109 miles of offshore oil and natural gas  pipelines
with  diameters  of 10" or larger.  To enhance  the value of these  assets,  the
Company has marketed this  infrastructure  to operators and leasehold  owners in
adjacent fields.  The Company  currently has pipeline and processing  agreements
relative  to its West Delta  Fields,  East  Cameron  359 Field,  East Breaks 109

                                      -4-
<PAGE>

Field,  East  Breaks 160 Field and East  Breaks 165  Field.  The annual  revenue
received from these  contracts for use of the Company's  infrastructure  in 1998
totaled $2.8 million,  which is accounted for as a reduction of lease  operating
expense.  The location of the East Breaks  facilities  is strategic to deepwater
development in the area, and the replacement costs of the platforms,  processing
facilities  and pipelines  exceed $100 million.  As a result of the  development
costs,  any operators with  discoveries in the  surrounding  deepwater area will
have the incentive to use the Company's East Breaks facilities,  thus increasing
the revenue  potential of these  platforms and  pipelines  and  extending  their
economic life.

     Selective Exploration Program

     The  Company  allocated  a modest  portion  of its 1998  capital  budget to
exploratory  projects and non-drilling  exploration  expenses.  The non-drilling
exploration  expenses  are  primarily  related  to the  acquisition,  review and
interpretation  of 3-D Seismic.  The Company  participated  in nine  exploratory
wells in 1998 all of which were  operated by third parties and the Company owned
working  interests in these wells  ranging  from 7.5% to 20%.  Three of the nine
exploratory  wells the Company  participated in were  successful.  The amount of
money  spent on these type of  expenditures  is  determined  by  management  and
approved by the board of  directors.  The Company  plans to spend  significantly
less money on exploration expenses in 1999.

     Geographic Focus

     The Company's reserve base is focused primarily in the GOM Region which has
historically  been the most  prolific  basin in North  America.  The GOM  Region
currently  accounts  for over 35% of the  natural gas  production  in the United
States  and  continues  to be  the  most  active  region  in  terms  of  capital
expenditures  and new  reserve  additions.  Because  of upside  potential,  high
production  rates,  technological  advances and acquisition  opportunities,  the
Company has focused its efforts in this region.  The Company believes it has the
technical  expertise  and  infrastructure  in  place  to take  advantage  of the
inherent  benefits  of the  GOM  Region.  In  addition,  as the  integrated  oil
companies move to deeper water, the Company believes it will continue to be well
positioned to use its expertise to acquire and exploit GOM Region properties.

     Quality Reserve Base

     Two of the Company's largest properties, the West Delta Fields and Umbrella
Point Field,  are prolific fields with total  cumulative  production of over one
Tcf of natural  gas and 50 MMbbls of oil.  These  fields  typify  the  Company's
focused  GOM Region  asset  base with  multiple  pay  horizons  and  significant
recompletion  and  workover  potential.  The West Delta  Fields  were  developed
without the benefit of 3-D Seismic and the Company is  currently  in the process
of  acquiring  and  applying  3-D  Seismic  technology  to  identify  additional
potential.  The majority of the Company's  properties  have multiple  reservoirs
providing a diverse set of  opportunities  for production rate  acceleration and
value  enhancement.  The number of  potential  reservoirs  also reduces the risk
associated with determining remaining reserves and forecasting future production
from the properties.

     Inventory of Exploitation and Development Projects

     The Company has identified  development drilling locations and recompletion
and  workover  opportunities.  The Company  believes  that the majority of these
opportunities  have a moderate risk profile and could add  incremental  reserves
and  production.  In addition  to these  identified  opportunities,  the Company
believes that with the use of 3-D Seismic technology,  additional  potential may
be exploited in the known reservoirs as well as deeper undrilled horizons.

     Application of Advanced Technologies

     The Company has been successful historically due to its use of 3-D Seismic,
horizontal  drilling  and  coiled  tubing  technologies.  As  a  result  of  its
acquisitions, the Company has a seismic database with a total of 49 linear miles
of 2-D Seismic  data and 443 square miles of 3-D Seismic  data.  The Company was
also  among the  first  offshore  operators  to drill  and  complete  successful
horizontal  wells  offshore.  The Company has drilled a total of four horizontal
wells in the West Delta Fields.  The Company  applies  coiled tubing  technology
where  applicable  to  decrease  workover  costs and avoid  using  drilling  and
workover rigs for  recompletions.  The Company uses existing inactive  wellbores
whenever  possible to sidetrack  drill to decrease costs and receive  production
tax benefits where  applicable.  Also, the Company has performed the less costly
through tubing recompletions in several of its existing fields.

                                      -5-
<PAGE>

     Significant Operating Control

     The Company  operates 63% of its properties as measured by SEC PV-10 value.
This  level of  operating  control  benefits  the  Company in  numerous  ways by
enabling   the  Company  to  (i)  control  the  timing  and  nature  of  capital
expenditures,  (ii) identify and implement cost control programs,  (iii) respond
quickly to  operating  problems and (iv) receive  overhead  reimbursements  from
other working interest owners. In addition to significant operating control, the
geographic  focus of the  Company  allows it to operate a large value asset base
with relatively few employees,  thereby decreasing  lease-operating expense on a
unit of production basis.

Well Operations
---------------

     The  Company  operates  93  offshore  wells  and  owns  all of the  working
interests in a majority of those  wells.  The  Company's  78 remaining  offshore
wells are  operated  by third party  operators,  including  Unocal  Corporation,
Coastal Oil & Gas Corp., Phillips Petroleum Company,  Texaco, Anadarko Petroleum
Corporation  and Burlington.  The Company  operates 80 onshore wells in which it
owns a majority or all of the working  interest.  In  addition,  it owns working
interests in 370 onshore wells operated by others. Where properties are operated
by others,  operations are conducted pursuant to joint operating agreements that
were  in  effect  at the  time  the  Company  acquired  its  interest  in  these
properties.  The Company  considers  these joint  operating  agreements to be on
terms  customary  within the  industry.  The  operator of an oil and natural gas
property supervises  production,  maintains  production  records,  employs field
personnel,   and  performs  other  functions  required  in  the  production  and
administration of such property.  The compensation paid to the operator for such
services customarily varies from property to property,  depending on the nature,
depth, and location of the property being operated.

Acquisition, Development, and Other Activities
----------------------------------------------

     The  Company  utilizes  its  capital  budget  for  (a) the  acquisition  of
interests  in other  producing  properties,  (b)  recompletions  of its existing
wells, and (c) the drilling of development and exploratory wells.

     In recent  years,  major oil  companies  have been  selling  properties  to
independent  oil  companies  because they feel these  properties do not have the
remaining reserve potential needed by a major oil company.  Several  independent
oil companies have acquired these properties and achieved significant success in
further  exploitation.  Even though a property  does not meet the  criteria  for
further  development  by a major oil  company,  that does not mean it is lacking
further  exploitation  potential.  The majors are simply moving further offshore
into  deeper  water and to other  countries  where they can find and produce the
super-fields  that fit their criteria.  Present day technology  permits drilling
and completing wells in water in excess of 10,000.

     The  Company  expects  that its  primary  activities  will  continue  to be
concentrated  offshore  in the Gulf of  Mexico  and  onshore  in the Gulf  Coast
region.  The number  and type of wells  drilled  by the  Company  will vary from
period to period  depending on the amount of the capital  budget  available  for
drilling,  the cost of each well, the Company's commitment to participate in the
wells  drilled  on  properties  operated  by  third  parties,  the  size  of the
fractional  working  interest  acquired  by the  Company  in each  well  and the
estimated  recoverable  reserves  attributable  to each  well.  Drilling  on and
production  from  offshore  properties  often  involves  higher  costs than does
drilling on and production from onshore properties,  but the production achieved
on successful wells is generally much greater.

Use of 3-D Seismic Technology
-----------------------------

     The use of 3-D Seismic and computer-aided  exploration  ("CAEX") technology
is an integral component of the Company's  acquisition,  exploitation,  drilling
and  business  strategy.  In general,  3-D  Seismic is the process of  obtaining
seismic data along multiple lines and grids within a large  geographic area. 3-D
Seismic differs from 2-D Seismic in that it provides information with respect to
multiple horizontal and vertical points within a geological formation instead of
information  on a single  vertical  line or multiple  vertical  lines within the
formation. By expanding the amount of data obtained with respect to a geological
formation,  the user is better able to  correlate  the data and obtain a greater
understanding and image of the formation. While it is impossible to predict with
certainty  the  specific   configuration   or  composition  of  any  underground
geological formation, 3-D Seismic provides a mechanism by which clearer and more
accurate projected images of complex geological formations can be obtained prior
to drilling for  hydrocarbons  therein.  In particular,  3-D Seismic  delineates
smaller reservoirs with greater precision than can be obtained with 2-D Seismic.

                                      -6-
<PAGE>

     3-D Seismic and CAEX technology have been in existence since the mid 1970s;
however,  it was not until the late 1980s, with the development of improved data
acquisition equipment and techniques capable of gathering significant amounts of
data  through a large  number  of  channels  and the  availability  of  improved
computer  technology at reasonable  costs,  that the method became  economically
available  to firms such as the  Company.  Prior to that,  it was the  exclusive
province  of  large  multinational  oil  companies.  The  Company  owns  its own
processing  equipment,  but it also  utilizes the  services of outside  firms to
process and interpret seismic data.

     With the BP  Acquisition,  the  Company  acquired  129 square  miles of 3-D
Seismic that it is currently reviewing. The Company has used the seismic for its
workover and recompletion activity to date, and plans further development on the
fields acquired with the seismic. The Company is also processing 18 square miles
of new 3-D Seismic  data shot over its East Breaks 109 and 110 fields for use in
developing those reserves.

Marketing of Production
-----------------------

     Production  from the Company's  properties  is marketed in accordance  with
industry  practices,  which  include  the sale of oil at the  wellhead  to third
parties and the sale of natural gas to third  parties at prices based on factors
normally  considered in the industry,  such as the spot price for natural gas or
the posted price for oil, and the quality of the oil and natural gas.

     The Company markets all of its offshore oil production to Plains Resources,
Amoco, Oxy, Conoco,  Texaco,  Unocal and Vastar. Oxy, Conoco,  Texaco and Vastar
each have 25% calls  (exclusive  rights to purchase) on the oil production  from
the West Delta Fields at their average posted price for each month.  Amoco has a
call on all of the oil  production  from the Amoco  Properties  at their  posted
prices.  If the  Company has a bona fide offer from a crude oil  purchaser  at a
higher  price than  Amoco's  posted  price,  then Amoco must match that price or
release the call.  Oil from the Zapata  Properties  is  currently  being sold to
Unocal and Amoco,  but can be sold to any crude oil  purchaser of the  Company's
choice.  Plains  Resources  purchases the oil production from the Umbrella Point
Fields and the East Breaks 165 and 209  Fields.  Natural gas is sold on the spot
market.  There are  numerous  potential  purchasers  for  offshore  natural gas.
Notwithstanding  this,  natural gas purchased by Tenneco Gas  Marketing  Company
(now El Paso Gas Marketing Co.) accounted for 42% of the revenues in 1998. There
are numerous natural gas purchasers doing business in the areas involved as well
as natural gas brokers and clearinghouses. Furthermore, the Company can contract
to sell the natural gas directly to end-users. The Company does not believe that
it is dependent  upon any one customer or group of customers for the purchase of
natural gas.

     The Company hedges the prices of its oil and natural gas production through
the use of oil and natural gas hedge and swap contracts within the normal course
of its business. The Company uses hedge and swap contracts to reduce the effects
of  fluctuations  in oil and natural gas prices.  Changes in the market value of
these  contracts  are  deferred  and  subsequent  realized  gains and losses are
recognized  monthly as adjustments to revenues in the same production  period as
the  hedged  item,  based on the  difference  between  the  index  price and the
contract price.

     Starting in 1997 the  Company's  natural gas hedge  transactions  are based
upon published  natural gas pipeline index prices and not the NYMEX. This change
has significantly  reduced price  differential risk due to  transportation.  The
Company has natural gas hedged in quantities  ranging from 7,301 to 27,301 MMbtu
per day in each of the  months  in 1999  for a  total  of  6,310,000  MMbtu,  at
pipeline prices averaging  approximately $1.98 per MMbtu, for a NYMEX equivalent
of approximately  $2.13 per MMbtu. The Company has hedged 218 MMbtu for each day
in 2000 at an average pipeline index swap price of $1.87. The Company has hedged
223 Bbls of oil for each day in 1999 at an  average  price of $17.27 per Bbl and
232 Bbls of oil for each day in 2000 at an average price of $17.35 per Bbl.

Plugging and Abandonment Escrows
--------------------------------

     Pursuant to existing agreements the Company is required to deposit funds in
bank trust and escrow accounts to provide a reserve against  satisfaction of its
eventual  responsibility  to plug and abandon wells and remove  structures  when
certain  fields no longer  produce oil and gas.  Through  November  30, 1997 the
Company  funded  $900,000 into an escrow  account with respect to the West Delta
Fields.  At that time,  the Company  completed its obligation for the funding of
the West Delta agreement.  The Company has entered into an escrow agreement with
Amoco Production  Company under which the Company deposits,  for the life of the
fields,  in a bank escrow  account ten  percent  (10%) of the net cash flow,  as
defined in the agreement, from the Amoco properties. The Company has established
the "PANACO East Breaks 110 Platform Trust" in favor of the Minerals  Management


                                      -7-
<PAGE>

Service of the U.S.  Department of the Interior.  This trust required an initial
funding of $846,720 in December 1996, and remaining  deposits of $244,320 due at
the end of each  quarter in 1999 and  $144,000 due at the end of each quarter in
2000 for a total of $2.4 million.  In connection  with the BP  Acquisition,  the
Company  deposited  $1 million  into an escrow  account on July 1, 1998.  On the
first day of each quarter thereafter, the Company will deposit $250,000 into the
escrow account until the balance in the escrow account reaches $6.5 million.

Insurance
---------

     The Company maintains insurance coverage which it believes is customary for
companies of a similar size engaged in operations similar to the Company's.  The
Company's insurance coverage includes  comprehensive general liability insurance
in the amount of $50 million per  occurrence  for  personal  injury and property
damage and cost of control and operators  extra expense  insurance of $3 million
on onshore wells, $20 million on wells in Louisiana State waters and $50 million
per  occurrence in Federal  offshore  waters,  which limits are  proportionately
reduced when the Company  owns less than 100% of the  respective  property.  The
Company maintains $77 million in property insurance on its offshore  properties.
There is no  assurance  that such  insurance  will be adequate to cover all such
costs or that such insurance will continue to be available in the future or that
such  insurance  will be available at premium  levels that justify its purchase.
The occurrence of a significant  event not fully insured or indemnified  against
could have a material  adverse effect on the Company=s  financial  condition and
operations.

Funding of Business Activities
------------------------------

     The Company  currently has a $17 million capital budget for 1999,  which is
subject to change  upon review by  management  and the board of  directors.  The
Company   anticipated  funding  this  capital  budget  through  cash  flows  and
borrowings  under its line of credit.  In  conjunction  with an amendment to the
loan  agreement,  on April 13, 1999 the borrowing  base under the line of credit
was reduced to $25 million, see "Bank Facility." The amendment provides for a $4
million  reductions  in this  borrowing  base on June 30, 1999 and September 30,
1999. With these reductions in the borrowing base, and the amount outstanding on
April 16, 1999 of $24  million,  the Company will be required to reduce its 1999
capital  budget to $11.5  million,  which it currently  has  committed to spend.
These   assumptions  do  not  include  any  external  sources  of  financing  or
redeterminations  of its  borrowings.  The line of credit permits the Company to
request such a redetermination from the bank.

     During 1998, the Company's capital  expenditures were  approximately  $61.8
million for (1) acquisition of an offshore property,  (2) the development of its
oil and gas properties and (3)  participation in exploratory  wells. The sources
of funds for capital expenditures were cash flow from operations,  proceeds from
the Senior Note offering and borrowings on the Company's existing bank facility.
The cash flow generated by the Company's activities would decline in the absence
of the  acquisition  and  development of other oil and natural gas properties or
increases in the  Company's  production  of oil and natural gas  resulting  from
exploration or the development of its properties.

     During 1996 shareholders'  equity increased by $1.8 million, as a result of
the exercise of warrants, and $8.4 million as a result of 2,000,000 shares being
issued to Amoco  Production  Company  as part of the Amoco  Acquisition.  During
1997,  shareholders' equity increased by $22 million as a result of the issuance
of 6,000,000  Common  Shares in a public  offering,  $1.2 million as a result of
issuance and  exercise of  warrants,  contributions  to the  Company's  ESOP and
employee  stock  bonuses,  and  $14.4  million  as a result of the  issuance  of
3,154,930  Common Shares to the beneficial  owners of Goldking and 84,000 Common
Shares as a finders fee, both in connection with the Goldking  Acquisition.  The
Company  issued  shares to the ESOP and as director  compensation  in 1998 which
increased shareholders' equity by $275,000.

Senior Notes
------------

     On October 9, 1997 the Company  issued  $100  million  aggregate  principal
amount of 10 5/8% Senior Notes due October 1, 2004. Interest on the Senior Notes
accrues  from the date of  original  issuance  and is payable  semi-annually  in
arrears on each April 1 and October 1, commencing April 1, 1998.

     The Senior Notes are general unsecured  obligations of the Company and rank
pari passu with any  unsubordinated  indebtedness of the Company and rank senior
in right of payment to all subordinated  obligations of the Company.  The Senior
Notes are effectively  subordinated  to all secured  indebtedness of the Company
and of the  Subsidiary  Guarantors  to the  extent  of the  value of the  assets
securing such indebtedness.


                                      -8-
<PAGE>

     The Senior Notes are  unconditionally  guaranteed  on a senior basis by the
Company's   Subsidiary   Guarantors.   The  Guarantees  are  general   unsecured
obligations  of  the  Subsidiary   Guarantors  and  rank  pari  passu  with  any
unsubordinated  indebtedness  of the  Subsidiary  Guarantors  and rank senior in
right of payment to all subordinated  obligations of the Subsidiary  Guarantors.
The Guarantees are effectively  subordinated to all secured  indebtedness of the
Subsidiary  Guarantors  to the extent of the value of the assets  securing  such
indebtedness.

     The Senior Notes are redeemable,  in whole or in part, at the option of the
Company on or after  October 1, 2001,  at set  redemption  prices,  plus accrued
interest, if any, thereon to the date of redemption. In addition, at any time on
or prior to October 1, 2000, the Company may, at its option, redeem up to 35% of
the aggregate  principal amount of the Senior Notes  originally  issued with the
net cash proceeds of one or more equity  offerings,  at a redemption price equal
to 110.625% of the aggregate principal amount of the Senior Notes to be redeemed
plus accrued  interest,  if any,  thereon to the date of  redemption;  provided,
however,  that, after giving effect to any such redemption,  at least 65% of the
aggregate  principal  amount  of the  Senior  Notes  originally  issued  remains
outstanding.

     Upon a Change of Control as defined in the  Indenture,  each  holder of the
Senior  Notes will have the right to require  the  Company  to  repurchase  such
holder's  Senior Notes at a price equal to 101% of the principal  amount thereof
plus accrued  interest,  if any, thereon to the date of repurchase.  The Company
must maintain a total Adjusted Consolidated Net Tangible Asset Value, as defined
in the  Indenture,  ("ACNTA")  equal to 125% of the Company's  indebtedness,  as
defined in the  Indenture,  at the end of each quarter.  If the Company's  ACNTA
falls below this percentage of  indebtedness  for two succeeding  quarters,  the
Company must redeem an amount of the Senior Notes  sufficient  to maintain  this
ratio.

     The Indenture contains certain restrictive covenants that limit the ability
of the Company and its  subsidiaries  to, among other things,  incur  additional
indebtedness,   pay  dividends  or  make  certain  other  restricted   payments,
consummate certain asset sales, enter into certain transactions with affiliates,
incur liens,  impose  restrictions on the ability of a Restricted  Subsidiary to
pay  dividends  or make  certain  payments  to the  Company  and its  Restricted
Subsidiaries,  merge or  consolidate  with any  other  person  or sell,  assign,
transfer,  lease, convey or otherwise dispose of all or substantially all of the
assets of the Company.  In addition,  under certain  circumstances,  the Company
will be required to offer to purchase the Senior Notes,  in whole or in part, at
a purchase  price equal to 100% of the  principal  amount  thereof  plus accrued
interest to the date of repurchase, with the proceeds of certain Asset Sales.

Bank Facility
-------------

     The  Company  has a $75.0  million  revolving  credit  facility  (the "Bank
Facility") from First Union National Bank of North Carolina,  as  Administrative
Agent and  Banque  Paribas  (collectively,  the  "Lenders").  The Bank  Facility
provides funds for working capital support and general corporate purposes and to
have available letters of credit.

     The Bank  Facility  is a  revolving  credit  subject  to a  borrowing  base
determination  made April 1 and October 1 of each year by the Lenders.  At April
1, 1999 the  borrowing  base was reduced to $25.0  million from $45.0 million at
December 31, 1998.  If at any time, at the sole  discretion of the Lenders,  the
borrowing  base is  determined  to be less than the current  loan  balance,  the
Company will be required to pay down the excess in two equal  payments due three
and six months after notification from the Administrative Agent. As of April 15,
1999,  the  Company's  balance under the Bank  Facility was $24.0  million.  The
borrowing  base is  subject  to $4  million  reductions  on June  30,  1999  and
September 30, 1999.
  
     The  Company may elect to pay  interest on the Bank  Facility at either the
Bank's  prime rate or at LIBOR plus 1 to 1.75% at December  31, 1998  (effective
April 1, 1999 1.5 to 2.25%),  depending  upon the  percentage of  utilization of
borrowing base. LIBOR is the London Interbank  Offered Rate on Eurodollar loans.
Eurodollar  loans can be for terms of one, two, three or six months and interest
on such loans is due at the  expiration of the terms of such loans,  but no less
frequently than every three months.

     The Bank  Facility has a maturity of four years with no required  principal
payments until maturity,  provided that the outstanding  principal  balance does
not exceed the borrowing base determinations  April 1 and October 1 of each year
by  the  Lenders.  Indebtedness  under  the  Bank  Facility  constitutes  senior
indebtedness  with  respect to the Senior  Notes.  Outstanding  indebtedness  is
secured by first priority  mortgages and security interests taken by the Lenders
in  substantially  all  properties  and assets owned by the Company.  All of the

                                      -9-
<PAGE>

capital stock of all subsidiaries of the Company is pledged pursuant to the Bank
Facility.  Each of the Company's wholly owned  subsidiaries  guarantees the Bank
Facility.

     Under the terms of the Bank Facility,  the Company must maintain a ratio of
EBITDA to  consolidated  interest  expense of not less than 2.0 to 1 at December
31, 1998 (2.5 to 1  thereafter).  In addition,  the Company  must also  maintain
current assets,  including availability under the line at that time, of not less
than  current  liabilities.   The  Bank  Facility  contains  certain  covenants,
including a minimum  tangible net worth test,  and negative  covenants  imposing
limitations  on  mergers,  additional  indebtedness,  and  pledges  and sales of
assets. At December 31, 1998, the Company had not satisfied all of the covenants
required under the Bank Facility.  The Company has obtained  waivers and amended
the agreement to eliminate the default. However, the Company has classified this
debt as a current  liability  since it is probable the Company will fail to meet
these covenants at measurement dates prior to December 31, 1999.

Competition, Markets, Seasonality and Environmental and Other Regulation
------------------------------------------------------------------------

     Competition.  There are a large number of companies and individuals engaged
in the  exploration  for and  development  of oil and  natural  gas  properties.
Competition is  particularly  intense with respect to the acquisition of oil and
natural gas producing properties and securing experienced personnel. The Company
encounters competition from various independent oil companies in raising capital
and in acquiring producing  properties.  Many of the Company's  competitors have
financial resources and staffs considerably larger than the Company.

     Markets.  The  ability of the Company to produce and market oil and natural
gas  profitably  depends on numerous  factors beyond the control of the Company.
The effect of these factors cannot be accurately predicted or anticipated. These
factors include the availability of other domestic and foreign  production,  the
marketing  of  competitive  fuels,  the  proximity  and  capacity of  pipelines,
fluctuations  in supply and demand,  the  availability  of a ready  market,  the
effect of federal and state regulation of production, refining,  transportation,
and sales of oil and natural gas,  political  instability  or armed  conflict in
oil-producing  regions,  and general national and worldwide economic conditions.
In recent years,  worldwide oil  production  capacity and natural gas production
capacity in the United  States  exceeded  demand and  resulted in a  substantial
decline in the price of oil and natural gas in the United States.

     Since  early  1986,  certain  members  of  the  Organization  of  Petroleum
Exporting  Countries  ("OPEC")  have, at various times,  dramatically  increased
their  production of oil,  causing a significant  decline in the price of oil in
the world market.  The Company cannot predict future levels of production by the
OPEC  nations,  the prospects for war or peace in the Middle East, or the degree
to which oil and natural gas prices will be  affected,  and it is possible  that
prices for any oil, natural gas liquids,  or natural gas produced by the Company
will be lower than those currently available.

     The demand for natural gas in the United  States has  fluctuated  in recent
years due to economic factors, a deliverability surplus,  conservation and other
factors.  This lack of demand has resulted in increased  competitive pressure on
producers.  However,  environmental  legislation is requiring certain markets to
shift  consumption from fuel oils to natural gas, thereby  increasing demand for
this cleaner burning fuel.

     In view of the many uncertainties  affecting the supply and demand for oil,
natural gas, and refined  petroleum  products,  the Company is unable to predict
future oil and natural gas prices. In order to minimize these  uncertainties the
Company, from time to time, hedges prices on a portion of its production.

     Seasonality.  Historically  the nature of the demand for natural gas caused
prices and demand to vary on a seasonal  basis.  Prices and  production  volumes
were  generally  higher  during the first and fourth  quarters of each  calendar
year. The substantial  amount of natural gas storage  becoming  available in the
U.S.  is  altering  this  seasonality.  During  1994,  1995,  1996  and 1997 the
Company=s   natural  gas  prices  averaged  $1.88,   $1.58,   $2.17  and  $2.49,
respectively,  in each case,  per Mcf. The Company  sells its natural gas on the
spot market based upon published  index prices for each  pipeline.  Historically
the net price  received by the Company  for its natural gas has  averaged  about
$.10 per MMbtu  below the NYMEX  Henry Hub index  price,  due to  transportation
differentials.  Fields  that are  located  further  offshore,  such as the Amoco
Properties,  will  generally  sell their natural gas for as much as $.1244 below
that index price.  Early 1997 pipeline  index prices were at  historical  highs,
moderated  during the late winter and spring only to rebound in the last half of
the year. During 1998,  natural gas prices received by the Company ranged from a
low of $1.62 to a high of $2.37 per Mcf. The average price  received per Mcf for
1998 was $2.05.

                                      -10-
<PAGE>

     Environmental and Other Regulation.  The Company's  business is affected by
governmental   laws  and   regulations,   including   price   control,   energy,
environmental,  conservation, tax and other laws and regulations relating to the
petroleum  industry.  For example,  state and federal agencies have issued rules
and  regulations  that require  permits for the drilling of wells,  regulate the
spacing of wells,  prevent the waste of natural gas and crude oil reserves,  and
regulate  environmental and safety matters including  restrictions on the types,
quantities and concentration of various substances that can be released into the
environment  in connection  with drilling and production  activities,  limits or
prohibitions  on drilling  activities on certain lands lying within wetlands and
other protected areas, and remedial  measures to prevent  pollution from current
and former operations. Changes in any of these laws, rules and regulations could
have a material  adverse effect on the Company's  business.  In view of the many
uncertainties  with  respect to current  law and  regulations,  including  their
applicability  to the Company,  the Company cannot predict the overall effect of
such laws and regulations on future operations.

     The Company  believes that its operations  comply in all material  respects
with all applicable laws and regulations and that the existence of such laws and
regulations  have  no  more  restrictive  effect  on  the  Company's  method  of
operations  than on other  similar  companies  in the  industry.  The  following
discussion  contains  summaries of certain laws and regulations and is qualified
in its entirety by reference thereto.

     Various  aspects  of the  Company's  oil and  natural  gas  operations  are
regulated by  administrative  agencies under statutory  provisions of the states
where such  operations  are  conducted  and by certain  agencies  of the federal
government  for  operations of federal  leases.  The Federal  Energy  Regulatory
Commission  (the "FERC")  regulates  the  transportation  and sale for resale of
natural gas in interstate  commerce pursuant to the Natural Gas Act of 1938 (the
"NGA") and the Natural Gas Policy Act of 1978 (the "NGPA").

     Sales of crude oil,  condensate  and natural gas liquids by the Company are
not regulated and are made at market prices. The price the Company receives from
the sale of these products is affected by the cost of transporting  the products
to market.  Effective as of January 1, 1995,  the FERC  implemented  regulations
establishing  an indexing  system for  transportation  rates for oil  pipelines,
which  would  generally  index  such  rates to  inflation,  subject  to  certain
conditions  and  limitations.  These  regulations  could  increase  the  cost of
transporting  crude oil, liquids and condensates by pipeline.  These regulations
are subject to pending petitions for judicial review. The Company is not able to
predict with certainty what effect,  if any, these  regulations will have on it,
but  other  factors  being  equal,   the   regulations   may  tend  to  increase
transportation costs or reduce wellhead prices for such conditions.

     Additional  proposals and proceedings that might affect the oil and natural
gas industry are pending before Congress,  the FERC and the courts.  The Company
cannot predict when or whether any such proposals may become  effective.  In the
past,  the natural gas industry  historically  has been very heavily  regulated.
There is no assurance that the current  regulatory  approach pursued by the FERC
will continue indefinitely into the future. Notwithstanding the foregoing, it is
not anticipated  that compliance  with existing  federal,  state and local laws,
rules and regulations will have a material or significantly  adverse effect upon
the capital expenditures, earnings or competitive position of the Company.

     Extensive  federal,  state and local  laws and  regulations  govern oil and
natural  gas   operations   regulating  the  discharge  of  materials  into  the
environment or otherwise relating to the protection of the environment. Numerous
governmental  departments  issue rules and  regulations to implement and enforce
such laws which change frequently, are often difficult and costly to comply with
and which carry  substantial  civil  and/or  criminal  penalties  for failure to
comply.  Some  laws,  rules and  regulations  to which the  Company  is  subject
relating to protection of the environment may, in certain circumstances,  impose
Astrict  liability@ for environmental  contamination,  rendering a person liable
for  environmental  damages and response  costs without  regard to negligence or
fault  on the  part of such  person.  For  example,  the  federal  Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended, also
known as the ASuperfund@ law, imposes strict,  joint and several liability on an
owner and operator of a facility or site where a release of hazardous substances
into the environment has occurred and on companies that disposed or arranged for
the  disposal of the  hazardous  substances  released  at the  facility or site.
Similarly,  the Oil Pollution Act of 1990 ("OPA")  imposes strict  liability for
remediation  and  natural  resource  damages  in the event of an oil  spill.  In
addition to other  requirements,  the OPA requires  operators of oil and natural
gas leases on or near  navigable  waterways to provide $35 million in "financial
responsibility," as defined in the Act. At present the Company is satisfying the
financial  responsibility  requirement with insurance  coverage.  The regulatory
burden on the oil and natural gas industry  increases its cost of doing business
and consequently  affects its  profitability.  These laws, rules and regulations
affect the operations and costs of the Company.  Furthermore, the Company cannot
guarantee  that such laws as they apply to oil and natural gas  operations  will
not change in the future in such a manner as to impose  substantial costs on the
Company. While compliance with environmental requirements generally could have a
material adverse effect upon the capital  expenditures,  earnings or competitive
position of the Company,  the Company  believes  that other  independent  energy
companies  in the oil  and  natural  gas  industry  likely  would  be  similarly
affected. The Company believes that it is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on the Company.

                                      -11-
<PAGE>

     Offshore  operations of the Company are conducted on both federal and state
lease  blocks of the Gulf of Mexico.  In all offshore  areas the more  stringent
regulation  of the federal  system,  as  implemented  by the Mineral  Management
Service of the  Department  of the  Interior,  will  ultimately be applicable to
state as well as federal leases, which could impose additional  compliance costs
on the  Company.  While there can be no  guarantee,  the Company does not expect
these  costs to be  material.  See  "Risk  Factors  -  Environmental  and  Other
Regulations."

Employees
---------

     The  Company has 34 full time  employees,  five of whom are  officers.  The
Company  utilizes an  additional  40 contract  personnel in the operation of its
properties,   and  uses  numerous  outside  geologists,   production  engineers,
reservoir  engineers,  geophysicists  and other  professionals  on a  consulting
basis.


Risk Factors
------------
     Information  contained or  incorporated  by reference in this Annual Report
may  contain  "forward-looking  statements"  within the  meaning of the  Private
Securities  Litigation Reform Act of 1995, which can be identified by the use of
forward-looking  terminology  such as "may," "expect,"  "intend,"  "anticipate,"
"estimate" or "continue" or the negative thereof or other variations  thereon or
comparable  terminology.  The following  matters and certain other factors noted
throughout  this Annual  Report  constitute  cautionary  statements  identifying
important factors with respect to any such forward-looking statements, including
certain  risks and  uncertainties,  that could  cause  actual  results to differ
materially from those in such forward-looking statements.

     Finding and Acquiring Additional Reserves; Depletion

     The Company's  future  success  depends upon its ability to find or acquire
additional  oil and  natural gas  reserves  that are  economically  recoverable.
Except to the extent the Company conducts successful  exploration or development
activities  or  acquires  properties  containing  Proved  Reserves,  the  Proved
Reserves of the Company will generally decline as they are produced. The decline
rate varies  depending upon  reservoir  characteristics  and other factors.  The
Company's  future oil and natural gas reserves and production,  and,  therefore,
cash flow and income are highly dependent upon the Company's level of success in
exploiting its current  reserves and acquiring or finding  additional  reserves.
The  business of exploring  for,  developing  or  acquiring  reserves is capital
intensive.  To the extent  cash flow from  operations  is reduced  and  external
sources of capital become limited or unavailable,  the Company's ability to make
the necessary  capital  investments  to maintain or expand its asset base of oil
and natural gas reserves  could be impaired.  There can be no assurance that the
Company's planned development projects and acquisition activities will result in
significant  additional  reserves or that the Company will have success drilling
productive  wells  at  economic  returns  to  replace  its  current  and  future
production.

     Substantial Leverage; Ability to Service Debt

     The  Company  incurred a  significant  loss in 1998,  and is  significantly
leveraged,  with  outstanding  long-term  indebtedness  of  $115.7  million  and
stockholders'  equity of $7.9  million as of December 31,  1998.  The  Company's
level of indebtedness has several  important  effects on its future  operations,
including (i) a  substantial  portion of the Company's cash flow from operations
is dedicated to the payment of interest on its indebtedness and is not available
for other purposes,  (ii) the  covenants  contained in the Bank Facility and the
Senior Notes require the Company to meet certain  financial  tests and limit the
Company's ability to borrow additional funds or to acquire or dispose of assets,
and (iii) the Company's ability to obtain additional financing in the future may
be impaired.  Additionally, the senior status of the Senior Notes, the Company's
high debt to equity  ratio,  and the use of  substantially  all of the Company's
assets as  collateral  for the Bank  Facility  will for the present time make it
difficult for the Company to obtain financing on an unsecured basis or to obtain
secured   financing   other   than   certain   "purchase   money"   indebtedness
collateralized by the acquired assets.

                                      -12-
<PAGE>

     The Company's ability to meet its financial covenants and to make scheduled
payments of principal  and  interest to repay its  indebtedness,  including  the
Senior Notes, is dependent upon its operating  results and its ability to obtain
financing.  However,  there can be no assurance that the Company's business will
generate sufficient cash flow from operations or that future bank credit will be
available  in an  amount  sufficient  to  enable  the  Company  to  service  its
indebtedness,   including  the  Senior   Notes,   or  make   necessary   capital
expenditures.  In such  event,  the  Company  would be  required  to obtain such
financing from the sale of equity securities or other debt financing.  There can
be no assurance that any such financing will be available on terms acceptable to
the Company if at all. Should sufficient  capital not be available,  the Company
may not be able to continue to implement its strategy.

     The Bank Facility limits the Company's  borrowings to amounts determined by
the lenders, in their sole discretion, based upon a variety of factors including
the amount of indebtedness which can be adequately supported by the value of oil
and natural gas reserves and assets owned by the Company (the "Borrowing Base").
The  Company  had $25.0  million  in  borrowing  base at April 1, 1999 under the
Borrowing Base of the Bank Facility.  If oil or natural gas prices decline below
their current levels, the availability of funds under the Bank Facility could be
materially adversely affected.

     The Bank Facility  requires the Company to satisfy certain financial ratios
in the  future.  The  failure to  satisfy  these  covenants  or any of the other
covenants in the Bank Facility would  constitute an event of default  thereunder
and, subject to certain grace periods,  may permit the lenders to accelerate the
indebtedness  then  outstanding  under the Bank  Facility  and demand  immediate
repayment  thereof.  See "Bank  Facility." At December 31, 1998, the Company had
not satisfied all of the covenants  required of the Bank  Facility.  The Company
has obtained  waivers and amended the Bank  Facility to  eliminate  the covenant
deficiency.  See "Bank  Facility" and  "Management's  Discussion and Analysis of
Financial Conditions and Results of Operations."

     Volatility of Oil and Natural Gas Prices

     The Company's revenues, profitability and the carrying value of its oil and
natural gas properties are  substantially  dependent upon prevailing  prices of,
and  demand  for,  oil and  natural  gas and the  costs of  acquiring,  finding,
developing and producing reserves. The Company's ability to maintain or increase
its borrowing capacity,  to repay the Senior Notes and outstanding  indebtedness
under any current or future credit facility, and to obtain additional capital on
attractive  terms  is also  substantially  dependent  upon oil and  natural  gas
prices. Historically, the markets for oil and natural gas have been volatile and
are likely to continue to be volatile in the future.  Prices for oil and natural
gas are  subject to wide  fluctuations  in  response  to:  (i) relatively  minor
changes  in the supply of, and demand  for,  oil and  natural  gas;  (ii) market
uncertainty;  and (iii) a variety of additional factors, all of which are beyond
the Company's  control.  These factors  include  domestic and foreign  political
conditions,  the price and availability of domestic and imported oil and natural
gas, the level of consumer and industrial demand, weather,  domestic and foreign
government  relations,  the  price and  availability  of  alternative  fuels and
overall economic conditions. The Company's production is weighted toward natural
gas,  making  earnings  and cash  flow  more  sensitive  to  natural  gas  price
fluctuations. Historically, the Company has attempted to mitigate these risks by
oil  and  natural  gas  hedging  transactions.  See  "Business  -  Marketing  of
Production."

     Uncertainty of Estimates of Reserves and Future Net Cash Flows

     This Annual Report contains  estimates of the Company's oil and natural gas
reserves  and the future net cash  flows  from those  reserves,  which have been
prepared  by  certain  independent  petroleum  consultants.  There are  numerous
uncertainties  inherent in estimating  quantities of Proved  Reserves of oil and
natural  gas and in  projecting  future  rates of  production  and the timing of
development  expenditures,  including many factors beyond the Company's control.
The estimates herein are based on various assumptions,  including,  for example,
constant oil and natural gas prices,  operating expenses,  capital  expenditures
and  the  availability  of  funds,  and,  therefore,  are  inherently  imprecise
indications  of future net cash flows.  Actual  future  production,  cash flows,
taxes,   operating   expenses,   development   expenditures  and  quantities  of
recoverable  oil and  natural gas  reserves  may vary  substantially  from those
assumed in the estimates.  Any significant  variance in these  assumptions could
materially affect the estimated quantity and value of reserves set forth herein.
Additionally,  the  Company's  reserves  may be  subject to  downward  or upward
revision based upon actual production performance, results of future development
and exploration,  prevailing oil and natural gas prices and other factors,  many
of which  are  beyond  the  Company's  control.  See  "Properties  - Oil and Gas
Information."


                                      -13-

 <PAGE>

     The SEC PV-10 of Proved Reserves referred to herein should not be construed
as the current market value of the estimated  Proved Reserves of oil and natural
gas  attributable  to the Company's  properties.  In accordance  with applicable
requirements of the Commission,  the estimated  discounted future net cash flows
from Proved  Reserves are generally  based on prices and costs as of the date of
the estimate, whereas actual future prices and costs may be materially higher or
lower.  The  calculation  of the SEC PV-10 of the  Company's oil and natural gas
reserves at  December  31, 1998 is based on prices of $2.05 per MMbtu of natural
gas and  $10.00  per Bbl of oil.  Actual  future  net cash  flows  also  will be
affected by (i) the timing of both production and related expenses; (ii) changes
in  consumption  levels  and (iii)  governmental  regulations  or  taxation.  In
addition,  the  calculation  of the  present  value of the future net cash flows
using a 10% discount as required by the  Securities  and Exchange  Commission is
not necessarily the most appropriate  discount factor based on interest rates in
effect from time to time and risks associated with the Company's reserves or the
oil and natural gas industry in general. Furthermore, the Company's reserves may
be subject to downward or upward revision based upon actual production,  results
of future development, supply and demand for oil and natural gas, prevailing oil
and  natural  gas  prices  and  other  factors.  See  "Properties  - Oil and Gas
Information."

     Acquisition Risks

     The  Company  has grown  primarily  through  acquisitions  and  intends  to
continue acquiring oil and natural gas properties. Although the Company performs
an extensive review of the properties proposed to be acquired,  such reviews are
subject to uncertainties.  Consistent with industry practice, it is not feasible
to review less significant  properties  involved in such acquisitions.  However,
even a detailed review may not reveal existing or potential  problems;  nor will
it permit the Company to become  sufficiently  familiar  with the  properties to
assess fully their deficiencies and capabilities.

     The Company has recently begun to focus its  acquisition  efforts on larger
packages of oil and natural gas properties,  such as the properties  involved in
the BP and Amoco  Acquisitions.  The  acquisition  of larger oil and natural gas
properties may involve substantially higher costs and may pose additional issues
regarding  operations  and  management.  There can be no assurance  that oil and
natural gas properties  acquired by the Company will be successfully  integrated
into the Company's operations or will achieve desired profitability  objectives.
See "Business - Acquisition, Development, and Other Activities."

     Exploration and Development Risks

     The  Company may  increase  its  development  and  exploration  activities.
Exploration  drilling and, to a lesser extent,  development  drilling of oil and
natural gas reserves involve a high degree of risk that no commercial production
will be obtained and/or that production will be insufficient to recover drilling
and completion  costs.  The cost of drilling,  completing and operating wells is
often uncertain. The Company's drilling operations may be curtailed,  delayed or
canceled as a result of numerous  factors,  including  title  problems,  weather
conditions, compliance with governmental requirements and shortages or delays in
the delivery of equipment.  The drilling of exploratory  and  development  wells
involves risks such as encountering unusual or unexpected formations, pressures,
and other  conditions that could result in the Company's  incurring  substantial
losses.  Furthermore,  completion  of a well  does not  assure  a profit  on the
investment or a recovery of drilling, completion and operating costs.

     Operating Hazards and Uninsured Risks

     The Company's oil and natural gas business  involves a variety of operating
risks,  including,  but not  limited to,  unexpected  formations  or  pressures,
uncontrollable  flows  of oil,  natural  gas,  brine  or well  fluids  into  the
environment (including groundwater contamination),  blowouts, fires, explosions,
pollution and other risks, any of which could result in personal injuries,  loss
of life,  damage to  properties  and  substantial  losses.  Although the Company
carries  insurance at levels which it believes are  reasonable,  it is not fully
insured  against all risks.  The Company  does not carry  business  interruption
insurance. Losses and liabilities arising from uninsured or under-insured events
could have a material  adverse effect on the financial  condition and operations
of the Company.

     Marketing Risks

     Substantially all of the Company's natural gas production is currently sold
to  gas  marketing   firms  or  end  users  either  on  the  spot  market  on  a
month-to-month  basis at  prevailing  spot  market  prices.  For the year  ended
December  31,  1998,  one  purchaser  accounted  for  approximately  42%  of the


                                      -14-
<PAGE>

Company's  revenues.  The Company does not believe that  discontinuation  of its
sales arrangement with such firm would be in any way disruptive to the Company's
natural  gas  marketing  operations.  See  "Business  -  Competition,   Markets,
Seasonality and Environmental and Other Regulation."

     Hedging Risks

     Historically,  the Company has reduced its  exposure to the  volatility  of
crude oil and  natural gas prices by hedging a portion of its  production.  In a
typical hedge  transaction,  the Company will have the right to receive from the
counterparty  to the hedge the excess of the fixed price  specified in the hedge
over a floating  price.  If the  floating  price  exceeds the fixed  price,  the
Company is required to pay the counter party all or a portion of this difference
multiplied  by the  quantity  hedged,  regardless  of whether  the  Company  has
sufficient   production  to  cover  the  quantities   specified  in  the  hedge.
Significant  reductions in  production at times when the floating  price exceeds
the fixed price  could  require  the  Company to make  payments  under the hedge
agreements  even though such payments are not offset by sales of production.  In
the  past,  the  Company  has  hedged  up to,  but  not  more  than,  50% of its
anticipated oil and natural gas production on an annualized basis.  Hedging also
prevents the Company from receiving the full advantage of increases in crude oil
or natural gas prices above the fixed amount specified in the hedge.

     AbandonmentCosts

     Due  to  the  Company's  number  of  offshore   properties  and  production
facilities,  government  regulations and lease terms will require the Company to
incur substantial  abandonment costs. As of December 31, 1998, total abandonment
costs for the Company's  offshore  properties  estimated to be incurred  through
2014 were approximately $17.4 million,  net of restricted cash, described below.
Estimated  abandonment costs have been included in determining  estimates of the
Company's  future net revenues from Proved  Reserves  included  herein,  and the
Company  accounts  for  such  costs  through  its  provision  for  depreciation,
depletion and amortization.  Under the terms of various agreements,  the Company
is required to fund restricted cash accounts as a reserve for abandonment  costs
on most of its offshore  properties.  See  "Business - Plugging and  Abandonment
Escrows."

     Environmental and Other Regulations

     The Company's  operations are affected by extensive  regulation pursuant to
various  federal,   state  and  local  laws  and  regulations  relating  to  the
exploration for and development,  production, gathering and marketing of oil and
natural  gas.  Matters  subject to  regulation  include  discharge  permits  for
drilling   operations,   drilling  and  abandonment  bonds  or  other  financial
responsibility  requirements,  reports  concerning  operations,  the  spacing of
wells,  unitization and pooling of properties,  and taxation. From time to time,
regulatory agencies have imposed price controls and limitations on production by
restricting  the  rate of  flow  of oil  and  natural  gas  wells  below  actual
production capacity in order to conserve supplies of oil and natural gas.

     Operations of the Company are also subject to numerous  environmental laws,
including but not limited to, those governing management of waste, protection of
water,  air  quality,  the  discharge  of materials  into the  environment,  and
preservation of natural  resources.  Non-compliance  with environmental laws and
the  discharge of oil,  natural gas, or other  materials  into the air,  soil or
water  may  give  rise to  liabilities  to the  government  and  third  parties,
including  civil and  criminal  penalties,  and may require the Company to incur
costs to remedy  the  discharge.  Oil and gas may be  discharged  in many  ways,
including  from a well or  drilling  equipment  at a drill  site,  leakage  from
pipelines or other gathering and transportation facilities, leakage from storage
tanks,  and sudden  discharges from oil and gas wells or explosion at processing
plants.  Hydrocarbons  tend to  degrade  slowly in soil and water,  which  makes
remediation  costly,  and discharged  hydrocarbons  may migrate through soil and
water  supplies or adjoining  property,  giving rise to additional  liabilities.
Laws and regulations  protecting the  environment  have become more stringent in
recent years,  and may in certain circumstances impose retroactive,  strict, and
joint and several liabilities rendering entities liable for environmental damage
without regard to negligence or fault. From time to time, the Company has agreed
to indemnify sellers of producing  properties from whom the Company has acquired
reserves against certain  liabilities for  environmental  claims associated with
such  properties.  There can be no assurance  that new laws or  regulations,  or
modifications of or new  interpretations of existing laws and regulations,  will
not increase  substantially the cost of compliance or otherwise adversely affect
the Company's  oil and natural gas  operations  and financial  condition or that
material  indemnity  claims will not arise  against the Company  with respect to
properties  acquired  by the  Company.  While the  Company  does not  anticipate
incurring  material  costs  in  connection  with  environmental  compliance  and
remediation,  it cannot guarantee that material costs will not be incurred.  See
"Business  -  Competition,  Markets,  Seasonality  and  Environmental  and Other
Regulation."

                                      -15-
<PAGE>

     Competition

     There are many companies and individuals engaged in the exploration for and
development  of oil and  natural gas  properties.  Competition  is  particularly
intense  with  respect  to the  acquisition  of oil and  natural  gas  producing
properties  and  securing   experienced   personnel.   The  Company   encounters
competition  from various  independent  oil companies in raising  capital and in
acquiring producing properties. Many of the Company's competitors have financial
resources  and staffs  considerably  larger than the  Company.  See  "Business -
Competition, Markets, Seasonality and Environmental and Other Regulation."

     Dependence Upon Key Personnel

     The success of the Company will depend almost  entirely upon the ability of
a small group of key  executives  to manage the business of the Company.  Should
one or more of these  executives  leave the Company or become  unable to perform
his duties,  no assurance  can be given that the Company will be able to attract
competent new management.

ITEM 2. PROPERTIES.
------------------

     The Company has grown through the  acquisition of producing  properties and
the subsequent application of advanced technology such as 3-D Seismic to exploit
potential  producing  zones which have been  overlooked  or bypassed by previous
operators.

     Since 1990, the Company has made six  acquisitions of producing  properties
for a  total  of  $106.4  million,  which  properties  had  Proved  Reserves  of
approximately 159 Bcfe as of their respective  acquisition dates. As of December
31, 1998, the Company had Proved  Reserves of 126 Bcfe with a SEC PV-10 of $94.6
million.  Approximately  75% of the Company=s  total SEC PV-10 are classified as
Proved Developed  Reserves and  approximately  65% of the Company=s total Proved
Reserves are natural gas.

     The Company's primary producing properties are located along the Gulf Coast
in Texas and  Louisiana and offshore in the federal and state waters of the Gulf
of  Mexico.  The  Company  owns  interests  in a total of 282 oil  wells and 362
natural gas wells.  The Company owns  interests in 23 federal blocks in the Gulf
of Mexico  and nine state  water  blocks and  operates  63% of the 171  offshore
wells,  based upon the SEC PV-10 value as of December  31, 1998.  The  Company's
non-operated  offshore  properties are operated by large  independents and major
oil  companies,  including  Unocal,  Phillips,  Texaco,  Coastal,  Anadarko  and
Burlington.  The 450 onshore wells account for 10.8% of the Company's  total SEC
PV-10 value as of December  31,  1998.  The Company  operates 65% of the onshore
wells,  based upon such SEC PV-10 value.  The Company also owns  interests in 23
offshore  production  platforms  and 109 miles of  offshore  oil and natural gas
pipelines with diameters of 10" or larger.

     The  following  table sets forth  certain  information  with respect to the
Company's  significant  properties  as of December  31, 1998.  These  properties
represent 79% of the aggregate SEC PV-10 value of the Company.

<TABLE>
<CAPTION>
                                                   Total Proved                            % of
                       Working                       Reserves               SEC PV-10     Total SEC
  Field               Interests   Wells  Operator      MBbls      Bcf       Value(000s)     PV-10  
---------------------------------------------------------------------------------------------------
<S>                      <C>      <C>      <C>          <C>       <C>          <C>             <C>

East Breaks 165       75 - 100%    18     PANACO       3,321      21.3     $  21,044          22%
Umbrella Point          80-100%    20     PANACO       1,783      16.0        20,480          22%
East Breaks 160           33.3%    16     Unocal         992       9.7        13,582          14%
High Island 309             50%    18     Coastal        115       9.8        13,001          14%
West Delta                 100%    35     PANACO         271       6.1         6,860           7%
---------------------------------------------------------------------------------------------------
   Total                          107                  6,482      62.9     $  74,967          79%

</TABLE>

     East Breaks 165

     For information regarding the East Breaks 165 field, see "Business Strategy
- BP Acquisition."

                                      -16-
<PAGE>

     Umbrella Point

     Since  its  discovery  in 1957 by Sun Oil,  the  Umbrella  Point  Field has
produced  over 17 MMbbls of oil and 100 Bcf of  natural  gas from 35 wells.  The
Company owns 100% of the working  interest in Texas State Leases 73,74,87 and 88
in Trinity  Bay,  Chambers  County,  Texas,  that  encompass  the  field.  Field
production is gathered on a small platform complex in approximately 10' of water
and transported via a Company owned 5 mile oil pipeline to the Company's onshore
production  facility at Cedar Point.  Gas  production is  transported  through a
Midcon  Pipeline Co. of Texas  pipeline.

     The  Umbrella  Point  Field  consists  of  multiple   stacked   reservoirs.
Production is from 13 main reservoirs from 7,700' to 9,000'. Prior to Goldking's
control of the field,  it was developed and produced by two different  operators
each  controlling  two  state  leases  which  created  a  competitive   drainage
situation.  This situation  resulted in several  reservoirs  that were abandoned
prematurely  as the former  operators  tried to accelerate  production in uphole
reservoirs.  Consequently,  significant development work remains to sufficiently
drain the abandoned  reservoirs.  On January 21, 1998 the Company  announced the
successful  completion of its first well in the Umbrella  Point Field.  The well
flowed 11.5 MMcf and 220 barrels of condensate  per day through a 20/64ths choke
with  flowing  tubing  pressure of 5,600 PSIG.  The Company  owns an 80% working
interest in the well. The remaining 20% is owned by Midcon Gas Services Corp.

     East Breaks 160

     The  Company  acquired a 33.3%  interest in this field as part of the Amoco
Acquisition in October 1996. The field consists of two federal  offshore blocks,
East Breaks 160 and 161, with a production platform set in 925' of water placing
this  production  facility on the edge of deep  water.  The field is operated by
Unocal  and  production  is  from  12  separate   reservoirs.   Unocal  acquired
proprietary  3-D  Seismic  over  the  field  in  1990  and  has  identified  the
undeveloped   locations.   The  Proved  Developed  Producing  Reserve  value  is
proportionately  dispersed among eleven  producing wells  decreasing the risk to
some  degree.   The  undeveloped   locations   included  are  based  on  seismic
interpretation  of attic  reserves.  The facility also receives  processing fees
from Vastar Corp.  related to a subsea well drilled in Block 117. Because of the
strategic  location of the platform on the edge of  deepwater,  the facility has
potential for additional processing and handling fees as more nearby discoveries
are made and tied into the  platform.  In  addition  to the  property  interests
acquired, the Company purchased a 33.3% interest in a 12.67 mile 12" natural gas
pipeline  connecting  the East  Breaks  Block 160  platform  to the High  Island
Offshore System ("HIOS") a natural gas pipeline system in the Gulf of Mexico and
a 33.3% interest in a 17.47 mile 10" oil pipeline connecting the platform to the
High Island Pipeline System ("HIPS"), a crude oil pipeline system in the Gulf of
Mexico. Currently such firms as Exxon, Reading and Bates and Santa Fe Energy are
actively exploring in the East Breaks Area and the Company believes that, due to
the ongoing  deepwater  exploration  in the Area,  the  Company's  platform  and
pipelines will become long term strategic  revenue  generating  assets after the
field reserves are depleted.

     High Island 309

     The Company  purchased  its  interest in the High Island  Block A-309 Field
from Amoco in October of 1996 and has a 50% working interest. The field consists
of the High  Island  blocks  A-309  and  A-310 in  approximately  200' of water.
Production  is from three  faulted  anticlines  with 18  productive  reservoirs.
Coastal Oil and Gas Corp. operates this property and has conducted an evaluation
of reprocessed proprietary 3-D Seismic surveys resulting in significant drilling
activity  in 1997 and 1998.  The  Company  has  drilled  new wells,  sidetracked
existing  wells  into  new  formations  and  recompleted  existing  wells in new
formations.  The field is currently producing 30 MMcf per day of natural gas and
15 Bbl per day of  condensate  compared  to 15 MMcf per day and 6 Bbl per day of
condensate at the beginning of 1997. The Company  believes that continued review
of the 3-D Seismic may result in additional development.

     West Delta

     These properties  consist of 13,565 acres in Blocks 52 through 56 and Block
58 in the West  Delta  Area,  offshore  Louisiana.  The West Delta  Fields  were
acquired from Conoco,  Inc.,  Atlantic  Richfield Company (now Vastar Resources,
Inc.),  OXY USA, Inc. and Texaco  Exploration and Production,  Inc. in May 1991.
These Fields were shut in from December 6, 1998 throughout the first quarter due
to a third  party  pipeline  being shut in.

                                      -17-
<PAGE>

     The Company has an 87.5% net revenue interest in the field, subject to a 5%
net  profits  interest on the  shallower  reservoirs  in favor of the  Company's
former lenders and a 4.166% overriding royalty interest on the deeper reservoirs
in favor of Conoco and OXY. The Company is the operator and generally  owns 100%
of the working interest in these wells. Presently, the properties have 36 wells,
five of which were  recently  drilled,  which  produce from depths  ranging from
1,200' to 16,800'.  Because of the existing  surface  structures  and production
equipment, additional wells can be added on the properties with lower completion
costs.

     The main  production  facility on the West Delta Fields is a four  platform
complex  designated as Tank Battery #3. There are three ancillary  platforms and
one three well  production  platform  in the eastern  portion of the  properties
connected to Tank  Battery #3. In the western  portion  there is one  production
platform designated as Platform "D" in Block 58, with three wells. The remaining
30 wells are located on satellite structures connected to Tank Battery #3 or one
of its  ancillary  platforms.  Eight wells produce oil and natural gas, with the
remaining  wells  producing  only natural gas. In 1997 the Company  replaced the
pipeline  connecting  "D"  Platform in Block 58 with Tank Battery #3 in Block 54
with  two new 6"  pipelines,  and  installed  a new 4"  pipeline  connected  "C"
Platform with "D" Platform.

     The field is characterized by multiple reservoirs with significant workover
and  recompletion   potential.   Proved  producing  reserves  are  based  on  an
established   consistent  production  history.  The  behind  pipe  reserves  are
generally  uphole  recompletions  with reserves  based on volumetric  estimates.
Currently there are no Proved  Undeveloped  Reserves  assigned to the field. The
Company has been historically  successful  increasing rates and reserves through
the use of horizontal  wells and coiled tubing  operations.  In 1994 the company
drilled  4  horizontal  wells  in  the  field  increasing   production  34%  and
accelerating  reserves.  The Company is also using coiled tubing technology with
increasing frequency to avoid costly rig workovers.

     During 1994, the Company  farmed out the deep rights (below  11,300') to an
1,875  acre  parcel  in Block 58 and sold "C"  Platform  to  Energy  Development
Corporation which drilled a successful well to 16,800'.  Production commenced in
April,  1995. The Company has a 15% overriding royalty interest in that acreage.
The well is currently producing 9,000 Mcf per day and 150 Bbls of condensate per
day. Energy  Development  Corporation was  subsequently  acquired by Samedan Oil
Corporation.

     The  Company  generated a prospect  in the  northern  portion of West Delta
Block 58 using 3-D Seismic, which it farmed out to Tana Oil & Gas Corporation in
1996. Tana drilled a successful well to 12,800' which encountered 85' of net pay
and is currently producing 7,000 Mcf per day. The Company retained an overriding
royalty  interest in the farmout,  which was converted to a 25% working interest
at payout on September 26, 1997.

     In connection with the  acquisition of the West Delta offshore  properties,
the Company  provides the sellers with a $4.1 million  plugging and  abandonment
bond  collateralized  in part with a bank  escrow  account.  See "The  Company -
Plugging and Abandonment Escrows."

     Other Properties

     Great River/Fort St. Phillips Fields.  The Company acquired the Great River
(33 1/3% working  interest)  and Fort St.  Phillips  (43 1/3% working  interest)
Fields  as  part  of  the  Goldking  Acquisition.   The  Company  operates  both
properties,  which total 1,688  acres and are  geologically  located on the same
fault  and  only  two  miles  apart.  These  fields  are low  relief  anticlinal
structures  with  stacked  reservoirs  from 7,600' to 10,000'.  The reserves are
spread over three active  completions  in two zones.  Behind pipe  reserves were
assigned to four sands considering analogous performance. The Proved Undeveloped
reserves  that  have  been   identified  in  the  fields   represent  attic  gas
accumulations.  New shallow  sands and deeper pay were  encountered  with the SL
#14645 #1 re-entry well. More wells are being  considered to further develop the
shallow and deep pay sands.

     High Island A-302 Field.  High Island  Block A-302  acquired  from Amoco in
1996 is in  approximately  200'  of  water.  The  Company  owns a 33.3%  working
interest  and  Unocal  Corporation  is the  operator.  Production  is from  four
producing horizons on a faulted anticlinal  structure.  A speculative 3-D survey
was shot in 1991 and processed in 1992.

     High Island A-330 Field.  The field  consists of three blocks,  High Island
A-330,  High Island A-349 and West Cameron  613,  located in 280' of water.  The
Company  owns a 12%  working  interest,  which it  acquired  from Amoco in 1996.
Coastal Oil and Gas Corporation is the operator. Three wells were recompleted in
1996. This field produces from a faulted anticline with 24 productive  horizons.
Significant  upside  potential  was  delineated  by a recently  shot 3-D Seismic
survey.


                                      -18-
<PAGE>

     High Island  A-474 Field.  This field  consists of three full blocks in the
High Island Area, A-474,  A-489, A-499, and part of Block A-475. The water depth
is 250' to 285' and  Phillips  Petroleum  Company is the  operator.  In 1996 the
Company  acquired from Amoco a 12% working interest in Blocks A-474 and A-489, a
13.1%  working  interest in Block  A-499,  and a 12%  working  interest in Block
A-475. There are 23 productive horizons in this faulted anticline. A proprietary
3-D Seismic survey was shot in 1991 and processed in 1993.

     West Cameron 180 Field. This field consists of a single block, West Cameron
144, in 40' of water.  Texaco is the operator.  The Company acquired its initial
12.5% working  interest from Amoco in 1996 and additional 25% from another owner
in 1998.  The  producing  feature is a  north-plunging  faulted  anticline  that
underlies West Cameron Blocks 173 and 180. There are three productive  horizons.
A new well was  completed  in  January  1998  and is  producing  4.1 MMcf and 60
barrels of condensate per day.

     East Cameron Block 359. The Company  acquired its 30.7% working interest in
this field from Zapata in 1995.  Anadarko  Petroleum Corp. is the operator.  The
property  has eight wells and is in 330' of water.  The  platform  also  handles
production for a nearby field owned by others.

     Eugene  Island  Block 372.  This field was  acquired  in 1995 from  Zapata.
Unocal Corp.  is the operator and the Company owns a 25% working  interest.  The
property has seven wells and is in 414' of water.

     South  Timbalier 185. The Company  acquired this field in 1995 from Zapata.
The Company owns a 7.7% working interest and Burlington  Resources,  Inc. is the
operator. The property has eleven wells and is in 180' of water.

     West Cameron Block 538. This field is operated by the Company and it owns a
35.3%  working  interest.  The property was acquired from Zapata in 1995. It has
six wells and is located in 194' of water.

                                      -19-
<PAGE>

Oil and Gas Information
-----------------------

     The following tables set forth selected oil and natural gas information for
the  Company,  and certain  forward-looking  information  about its  properties.
Future  results  may  vary  significantly  from  the  amounts  reflected  in the
information  set forth herein because of normal  production  declines and future
acquisitions.  The following  information  on Proved  Reserves,  future net cash
flows from Proved Reserves and the SEC PV-10 value of such estimated  future net
cash flows for the Company's properties as of December 31, 1998 were prepared by
independent  petroleum  engineers,  Ryder Scott  Company,  Netherland,  Sewell &
Associates,  Inc., W.D Von Gonten & Co. and McCune  Engineering,  P.E. See "Risk
Factors -  Uncertainty  of  Estimates of Reserves and Future Net Cash Flows" and
"Finding and Acquiring Additional Reserves; Depletion."

<TABLE>

                               Proved Reserves (a)
<CAPTION>


     The following  table sets forth  information  as of December 31, 1998 as to
the estimated Proved Reserves attributable to the Company's properties.

Oil and liquids (Bbl):                                                                 Pro Forma (b)
<S>                                                                        <C>              <C>

            Proved Developed Reserves...................................5,165,328        5,223,359
            Proved Undeveloped Reserves.................................2,288,917        2,629,180
                                                                       ----------       ----------
                     Total Proved Reserves..............................7,454,245        7,852,539

Natural gas (Mcf):
                Proved Developed Reserves .............................50,538,718       50,844,718
                Proved Undeveloped Reserves............................30,709,981       32,834,981
                     Total Proved Reserves.............................81,248,699       83,679,699

_____________
     (a)  Calculated by the Company in accordance with the rules and regulations
          of the SEC,  based upon  December 31, 1998 prices of $10.00 per Bbl of
          oil  and  $2.05  per  MMbtu  of  natural   gas,   adjusted  for  basis
          differentials, Btu content of natural gas and specific gravity of oil.
          The Company's independent reservoir engineers prepare a reserve report
          as of the end of each calendar year.

    (b)  Includes  reserve  amounts for  acquisitions  that were in progress at
         December 31, 1998.
</TABLE>

<TABLE>

                          Estimated Future Net Revenues
                            from Proved Reserves (a)
<CAPTION>

     The following  table sets forth  information  as of December 31, 1998 as to
the estimated  future net revenues  (before  deduction of income taxes) from the
production  and  sale  of the  Proved  Reserves  attributable  to the  Company's
properties.

                                                        Proved                         Total
                                                       Developed                       Proved
                                                       Reserves       Pro Forma(b)    Reserves       Pro Forma(b)
                                                       ---------      ---------       --------       ---------    
<S>                                                      <C>              <C>           <C>              <C>   

        Estimated Future net revenues (c):.............$86,547,916    $87,344,716    $129,326,942    $133,363,339

        Present value (10%) of estimated future net
         revenues (SEC PV-10)..........................$71,186,819    $71,692,758     $94,580,281     $97,156,670
_______________

(a)  Calculated by the Company in accordance  with the rules and  regulations of
     the SEC,  based upon  December 31, 1998 prices of $10.00 per Bbl of oil and
     $2.05 per MMbtu of offshore natural gas, adjusted for basis  differentials,
     Btu  content of natural  gas and  specific  gravity of oil.  The  Company's
     independent  reservoir  engineers prepare a reserve report as of the end of
     each calendar  year.

(b)  Includes  amounts for  acquisitions  that were in progress at December  31,
     1998.

(c)  Estimated  future net revenues  represent  estimated  future gross revenues
     from the production and sale of Proved Reserves, net of estimated operating
     costs,  future  development  costs  estimated  to be  required  to  achieve
     estimated future production and estimated future costs of plugging offshore
     wells and removing offshore structures.


                                      -20-
<PAGE>

                        Production, Price, and Cost Data

     The following  table sets forth certain  production,  price,  and cost data
with respect to the Company's  properties for the three years ended December 31,
1998, 1997 and 1996.

                                                                      For the year ended December 31,

                                                      ---------------------------------------------------------
                                                                1996(a)            1997                 1998
    
        Oil and Condensate:
             Net Production (Bbls)(b)                           276,000           515,000              895,000
             Revenue                                      $   5,356,000    $    9,354,000        $  10,916,000
             Hedge gains (losses)                         $          --    $      (67,000)       $   2,034,000
             Average net Bbl per day                                756             1,411                2,452
             Average price per Bbl before hedges          $       19.42    $        18.17        $       12.20
             Average price per Bbl including hedges       $       19.42    $        18.04        $       14.47
                                                                              

        Natural Gas:
             Net Production (Mcf)(b)                          6,788,000        11,468,000           18,041,000
             Revenue                                      $  18,653,000    $   29,751,000        $  36,910,000
             Hedge gains (losses)                         $  (3,946,000)   $   (1,197,000)       $     431,000
             Average net Mcf per day                             18,600            31,400               49,400
             Average price per Mcf before hedges          $        2.74    $         2.59        $        2.05
             Average price per Mcf including hedges       $        2.17    $         2.49        $        2.07
                                                                                
        Total Revenues                                    $  20,063,000    $   37,841,000        $  50,291,000

        Production Cost:
             Production cost                              $   8,186,000    $   11,150,000        $  18,148,000
             Mcfe(c)                                          8,444,000        14,557,000           23,411,000
             Production cost per Mcfe(c)                  $         .97    $          .77        $         .78
______________

(a)  The  information  shown for 1996 was  impacted by the fire on April 24th at
     West Delta Tank  Battery  #3,  which  resulted  in those  fields  being off
     production  until  October 7, 1996.  For that reason  management  would not
     consider this data to be indicative  of the future.  Also this  information
     includes Bayou Sorrel Field through  September 1, the date of its sale, and
     includes information with respect to the Amoco Properties only from October
     8,  1996.
(b)  Production information is net of all royalty interests,  overriding royalty
     interest and the net profits interest in the West Delta Fields owned by the
     Company's former lenders.
(c)  Oil  production  is  converted  to  Mcfe  at the  rate  of 6 Mcf  per  Bbl,
     representing the estimated relative energy content of natural gas to oil.
</TABLE>


                                      -21-
<PAGE>


<TABLE>
                              Productive Wells (a)
<CAPTION>

     The following table sets forth the number of productive oil and natural gas
wells, as of December 31, 1998, attributable to the Company's properties.

                                                            Productive Wells             Company Operated 
                                                            ----------------             ----------------
<S>                                                               <C>                          <C>   

        Gross productive offshore wells (b):
               Oil    .....................................         73                          47
               Natural Gas   ..............................        121                          46
                                                                   ---                         ---
                    Total  ................................        194                          93

         Net productive offshore wells (c):
               Oil    .....................................         53                          47
               Natural Gas   ..............................         60                          42
                                                                   ---                         ---
                    Total  ................................        113                          89

        Gross productive onshore wells (b):
               Oil    .....................................        209                          65
               Natural Gas   ..............................        241                          15
                                                                   ---                         ---
                    Total  ................................        450                          80

        Net productive onshore wells (c):
               Oil    .....................................         70                          58
               Natural Gas   ..............................         13                           8
                                                                   ---                         ---
                    Total  ................................         83                          66
__________

(a)  Productive   wells  consist  of  producing   wells  and  wells  capable  of
     production, including shut-in wells and water disposal and injection wells.
     One or more completions in the same borehole are counted as one well.

(b)  A "gross well" is a well in which a working  interest is owned.  The number
     of gross wells  represents the sum of the wells in which a working interest
     is owned.

(c)  A "net  well" is deemed  to exist  when the sum of the  fractional  working
     interests  in gross wells equals one. The number of net wells is the sum of
     the fractional working interests in gross wells.

                                Leasehold Acreage
     The  following  table sets forth the  developed  acreage as of December 31,
1998, attributable to the Company's properties.

        Developed onshore acreage (a):
                Gross acres (b)..........................................................     83,393
                Net acres (c)............................................................      6,734

        Undeveloped onshore acreage (a):
                Gross acres (b)..........................................................      8,787
                Net acres (c)............................................................      3,229

        Developed offshore acreage (a):
                Gross acres (b)..........................................................    127,935
                Net acres (c)............................................................     47,926

        Undeveloped offshore acreage (a)(d):
                Gross acres (b)..........................................................     82,380
                Net acres (c)............................................................     10,721
__________

(a)  Developed acreage is acreage assignable to productive wells.

(b)  A "gross acre" is an acre in which a working  interest is owned. The number
     of gross acres  represents the sum of the acres in which a working interest
     is  owned.

(c)  A "net  acre" is deemed  to exist  when the sum of the  fractional  working
     interests  in gross acres equals one. The number of net acres is the sum of
     the fractional working interests in gross acres.

(d)  In addition to these acres, the Company's  undeveloped  offshore  potential
     exists at greater depths beneath existing producing reservoirs.
</TABLE>


                                      -22-

<PAGE>

                               Drilling Activities

     The following table sets forth the number of gross productive and dry wells
in which the Company had an interest, that were drilled and completed during the
five years ended December 31, 1998.  Such  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 and
the oil and natural gas reserves  generated  thereby or the costs to the Company
of productive wells compared to the costs to the Company of dry wells.

<TABLE>
<CAPTION>

                      Developmental Wells                             Exploratory Wells
                       Completed    Dry                            Completed           Dry
                    Oil     Gas     Oil   Gas                   Oil      Gas     Oil      Gas
                    -------------------------                   -----------------------------
<S>                <C>      <C>     <C>   <C>                   <C>    <C>       <C>      <C>


1994                5        4      --     --                   --        1       --      --
1995               --       --      --     --                   --       --       --       3
1996               --       --       2     --                   --       --       --      --
1997                6       13      --      1                   --       --       --      --
1998                1        9      --     --                   --        3       --       6
Total              12       26       2      1                   --        4       --       9

</TABLE>

Title to Oil and Gas Properties
-------------------------------

     In the case of acquired properties title opinions are obtained for the more
significant  properties.  Prior to the  commencement  of drilling  operations  a
thorough  drill site title  examination is conducted and curative work performed
with respect to significant defects.

Unproved Properties
-------------------

     The Company  retained a 3% overriding  royalty  interest in depths that are
below 11,000' when it sold the Bayou Sorrel Field to National Energy Group, Inc.
Two successful wells were drilled to these depths from which the company derives
revenue.  In connection  with the Amoco and Goldking  acquisitions,  the Company
acquired  what  management  believes  to  be  further  reserve  potential,   not
quantified in its proved reserve  evaluations,  generally at greater depths than
previously developed.  A portion of the respective purchase prices was allocated
to these unproved properties.

ITEM 3. LEGAL PROCEEDINGS.
-------------------------

     The Company is  presently a party to several  legal  proceedings,  which it
considers to be routine and in the ordinary  course of its business.  Management
has no knowledge of any pending or threatened claims that could give rise to any
litigation which management believes would be material to the Company.

     An action was filed against the Company,  Exxon Pipeline Company ("Exxon"),
National  Energy  Group,  Inc.  ("NEG"),  Mendoza  Marine,  Inc.,  Shell Western
Exploration  &  Production,  Inc.  ("Shell"),  and the  Louisiana  Department of
Transportation  and  Development.  The petition  was filed in August  1998,  and
alleges  that,  in 1997 and  perhaps  earlier,  leaks  from a buried  crude  oil
pipeline  contaminated  the plaintiffs'  property.

     Pursuant to the  purchase and sale  agreement  between the Company and NEG,
NEG is required to indemnify the Company from any damages  attributable to NEG's
operations  on the  property  after  the sale.  However,  NEG is in  Chapter  11
bankruptcy proceedings, and so any action by the Company to assert its indemnity
rights  against NEG is currently  stayed.  Counsel for the Company have prepared
and may file a  motion  to lift the stay so that  the  Company  may  assert  its
indemnification  rights  against NEG. But even if the Company is  successful  in
proving its right to indemnity, NEG's judgmentworthiness is questionable because
of the bankruptcy.

     Pursuant  to another  purchase  and sale  agreement,  the  Company  may owe
indemnity to Shell and Exxon,  from which it had acquired the property  prior to
selling  same to NEG.  The Company may have  insurance  coverage  for the claims


                                      -23-
<PAGE>

asserted in the petition, and has notified or is in the process of notifying all
insurance  carriers  that might  provide  coverage  under their  policies.  Some
discovery  has  occurred  in  the  case,  but  discovery  is not  yet  complete.
Therefore,  at this point it is not  possible to evaluate the  likelihood  of an
unfavorable outcome, or to estimate the amount or range of potential loss.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
-----------------------------------------------------------

        None.

                                     PART II


ITEM 5. MARKET FOR COMMON STOCK AND RELATED SHAREHOLDER MATTERS.
---------------------------------------------------------------

     The authorized  capital shares of the Company consist of 40,000,000  Common
Shares, par value $.01 per share, and 5,000,000 preferred shares, par value $.01
per share.  The following  description of the capital shares of the Company does
not purport to be complete or to give full effect to the provisions of statutory
or common law and is subject in all respects to the applicable provisions of the
Company's  Certificate of Incorporation and the information  herein is qualified
in its entirety by this reference.

Common Shares
-------------

     The Company is authorized by its Certificate of Incorporation,  as amended,
to issue 40,000,000  Common Shares,  of which  23,985,927  shares are issued and
outstanding as of the date hereof and are held by over 6,700 shareholders, based
upon information available on individual security position listings.

     The holders of Common  Shares are  entitled to one vote for each share held
on all matters submitted to a vote of common holders.  The Common Shares have no
cumulative  voting  rights,  which  means that the  holders of a majority of the
Common Shares  outstanding  can elect all the directors if they choose to do so.
In that event, the holders of the remaining shares will not be able to elect any
directors.

     Each Common Share is entitled to participate  equally in dividends,  as and
when declared by the Board of Directors,  and in the  distribution  of assets in
the  event  of  liquidation,  subject  in all  cases  to  any  prior  rights  of
outstanding preferred shares. The Common Shares have no preemptive or conversion
rights,  redemption  rights, or sinking fund provisions.  The outstanding Common
Shares are duly authorized, validly issued, fully paid, and nonassessable.

     During  1998 the  Company  issued  52,793  Common  Shares to  directors  as
compensation for services on the board. The exemption from  registration  relied
upon was that of Section 4(2) of the Securities Act of 1933.

Warrants and Options
--------------------

     The Company has outstanding options to acquire 1,150,000 Common Shares at a
price of $4.45 per share,  expiring June 20, 2000. These options are all held by
current and former employees of the Company. They contain limited provisions for
adjustment of the number of shares in the event of a subdivision, combination or
reclassification  of  Common  Shares.  They do not have  any  rights  to  demand
registration  or "piggy  back" rights in the event of a  registration  of Common
Shares.

Preferred Shares
----------------

     Pursuant to the  Company's  Certificate  of  Incorporation,  the Company is
authorized to issue  5,000,000  preferred  shares,  and the  Company's  Board of
Directors,  by  resolution,  may  establish  one or more  classes  or  series of
preferred  shares  having the number of shares,  designations,  relative  voting


                                      -24-
<PAGE>


rights,   dividend  rates,   liquidation  and  other  rights  preferences,   and
limitations that the Board of Directors fixes without any shareholder approval.

Transfer Agent
--------------

     The transfer agent,  registrar and dividend disbursing agent for the Common
Shares is American Stock Transfer and Trust Company, 6201 15th Avenue, Brooklyn,
New York 11204.

Price Range of Common Shares
----------------------------

     The Common  Shares are quoted on the  National  Association  of  Securities
Dealers, Inc. Automated Quotation System ("NASDAQ") - National Market, under the
symbol "PANA".  They commenced  trading  September 21, 1989. The following table
sets forth, for the periods  indicated,  the high and low closing prices for the
Common Shares.



                                      1997
                                                                                
1st Quarter          2nd Quarter        3rd Quarter          4th Quarter
-----------          -----------        -----------          -----------

High $ 5 1/4          $ 4 5/8             $ 5                 $ 5 9/16
Low  $ 3 5/8          $ 3 3/4             $ 3 7/8             $ 3 9/16


                                      1998
                                             
1st Quarter          2nd Quarter        3rd Quarter          4th Quarter
-----------          -----------        -----------          -----------
High $ 4 1/2          $ 4 5/8             $ 3 7/8             $ 2
Low  $ 3 1/2          $ 3 7/8             $ 1 11/16           $ 13/16

     On March 31, 1999,  the last sale price of the Common Shares as reported on
the NASDAQ was $.94 per share.

Dividend Policy
---------------

     The  Company  has not paid any cash  dividends  on the Common  Shares.  The
Delaware General  Corporation Law, to which the Company is subject,  permits the
Company to pay  dividends  only out of its  capital  surplus  (the excess of net
assets over the aggregate par value of all outstanding capital shares) or out of
net  profits  for the  fiscal  year in which the  dividend  is  declared  or the
preceding   fiscal  year.  The  Bank  Facility  and  the  Senior  Notes  contain
restrictions  on  any  dividends  or  distributions  by the  Company  and on any
purchases by the Company of Common Shares.  The Company retains its earnings and
cash flow to finance the expansion and development of its business and currently
does not intend to pay dividends on the Common  Shares.  Any future  payments of
dividends  will  depend  on,  among  other  factors,  the  earnings,  cash flow,
financial condition, and capital requirements of the Company.

Certain Anti-takeover Provisions
--------------------------------

     In September  1998,  the Board  elected to redeem the  Company's  Preferred
Share Purchase Right at its stated value of $.005 per Common Share.


     The provisions of the Company's  Certificate of  Incorporation  and By-laws
summarized in the following  paragraphs  may be deemed to have an  anti-takeover
effect and may delay,  defer, or prevent a tender offer or takeover attempt that
a  shareholder  might  consider  to be in  that  shareholder's  best  interests,
including  attempts that might result in a premium over the market price for the
shares held by shareholders. In addition, certain provisions of Delaware law and
the Company's Long-Term Incentive Plan may be deemed to have a similar effect.

     Certificate  of  Incorporation  and By-laws.  The Board of Directors of the
Company  is  divided  into  three  classes.  The term of  office of one class of
directors expires at each annual meeting of shareholders,  when their successors

                                      -25-
<PAGE>

are  elected  and  qualified.   Directors  are  elected  for  three-year  terms.
Shareholders  may remove a director  only for cause.  In  general,  the Board of
Directors,  not the Company's shareholders,  has the right to appoint persons to
fill vacancies on the Board of Directors.


     Pursuant to the Company's Certificate of Incorporation, the Company's Board
of  Directors,  by  resolution,  may  establish one or more classes or series of
preferred  shares  having  the number of shares,  designation,  relative  voting
rights,  dividend  rates,  liquidation  and  other  rights,   preferences,   and
limitations that the Board of Directors fixes without any shareholder  approval.
Any rights, preferences,  privileges, and limitations that are established could
have the effect of impeding or  discouraging  the  acquisition of control of the
Company.
  
     The  Company's  Certificate  of  Incorporation   contains  a  "fair  price"
provision that requires the  affirmative  vote of the holders of at least 80% of
the voting shares of the Company and the affirmative vote of at least two-thirds
of the voting shares of the Company not owned,  directly or  indirectly,  by the
Related Person (hereafter defined) to approve any merger, consolidation, sale or
lease of all or substantially all of the assets of the Company, or certain other
transactions  involving  any  Related  Person.  For  purposes  of the fair price
provision,  a "Related Person" is any person  beneficially owning 10% or more of
the voting shares of the Company who is a party to the  Transaction  at issue, a
director who is also an officer of the Company and is a party to the Transaction
at issue, an affiliate of either such person,  and certain  transferees of those
persons.  The voting  requirement  is not  applicable  to certain  transactions,
including  those that are approved by the  Company's  Continuing  Directors  (as
defined in the Certificate of  Incorporation)  or that meet certain "fair price"
criteria contained in the Certificate of Incorporation.
        

     The  Company's   Certificate  of   Incorporation   further   provides  that
shareholders  may act only at an annual or special meeting of  shareholders  and
not by written consent, that special meetings of shareholders may be called only
by the Board of  Directors,  and that  only  business  proposed  by the Board of
Directors may be considered at special meetings of shareholders.

     The  Company's  Certificate  of  Incorporation  also provides that the only
business  (including  election of directors) that may be considered at an annual
meeting of shareholders,  in addition to business proposed (or persons nominated
to be  directors)  by the  directors  of the Company,  is business  proposed (or
persons  nominated to be directors) by  shareholders  who comply with the notice
and disclosure requirements of the Certificate of Incorporation. In general, the
Certificate of Incorporation requires that a shareholder give the Company notice
of  proposed  business  or  nominations  no later than 60 days before the annual
meeting  of  shareholders  (meaning  the  date on  which  the  meeting  is first
scheduled and not  postponements or adjournments  thereof) or (if later) 10 days
after  the  first  public  notice  of the  annual  meeting  is  sent  to  common
shareholders. In general, the notice must also contain certain information about
the  shareholder  proposing  the  business or  nomination,  his  interest in the
business,  and (with respect to nominations for director)  information about the
nominee  of the nature  ordinarily  required  to be  disclosed  in public  proxy
solicitations.  The shareholder must also submit a notarized letter from each of
his nominees  stating the nominee's  acceptance of the nomination and indicating
the nominee's intention to serve as director if elected.

     The Certificate of Incorporation also restricts the ability of shareholders
to  interfere  with the powers of the Board of  Directors  in certain  specified
ways,  including the constitution and composition of committees and the election
and removal of officers.

     The Certificate of  Incorporation  provides that approval by the holders of
at least  two-thirds of the  outstanding  voting shares is required to amend the
provisions  of the  Certificate  of  Incorporation  discussed  in the  preceding
paragraphs and certain other provisions,  except that approval by the holders of
at least 80% of the  outstanding  voting  shares of the Company,  together  with
approval by the holders of at least two-thirds of the outstanding  voting shares
not owned,  directly or indirectly,  by the Related Person, is required to amend
the fair price  provisions  and except that  approval of the holders of at least
80% of the  outstanding  voting  shares  is  required  to amend  the  provisions
prohibiting shareholders from acting by written consent.

     Delaware  Anti-takeover  Statute. The Company is a Delaware corporation and
is subject to Section 203 of the Delaware  General  Corporation Law. In general,
Section 203 prevents an "interested  shareholder" (defined generally as a person
owning 15% or more of the Company's  outstanding voting shares) from engaging in
a "business  combination" (as defined in Section 203) with the Company for three
years following the date that person became an interested shareholder unless (a)
before that person became an interested  shareholder,  the Board of Directors of
the Company approved the transaction in which the interested  shareholder became
an  interested  shareholder  or  approved  the  business  combination,  (b) upon
consummation  of the transaction  that resulted in the interested  shareholder's
becoming an interested shareholder, the interested shareholder owns at least 85%
of the voting  shares of the  Company  outstanding  at the time the  transaction
commenced  (excluding  shares  held by  directors  who are also  officers of the
Company and by employee stock plans that do not provide employees with the right
to  determine  confidentially  whether  shares held  subject to the plan will be
tendered in a tender or exchange  offer),  or (c) following the  transaction  in


                                      -26-
<PAGE>

which that person became an interested shareholder,  the business combination is
approved by the Board of Directors of the Company and authorized at a meeting of
shareholders  by the affirmative  vote of the holders of at least  two-thirds of
the  outstanding  voting  shares  of the  Company  not  owned by the  interested
shareholder.  In connection  with a private sale of Common  Shares in 1999,  the
Board elected to waive the Delaware Anti-takeover statute.

     Under Section 203, these restrictions also do not apply to certain business
combinations proposed by an interested shareholder following the announcement or
notification of one of certain extraordinary  transactions involving the Company
and a person who was not an  interested  shareholder  during the previous  three
years or who became an interested shareholder with the approval of a majority of
the Company's  directors,  if that extraordinary  transaction is approved or not
opposed by a majority  of the  directors  who were  directors  before any person
became  an  interested  shareholder  in the  previous  three  years  or who were
recommended  for election or elected to succeed such  directors by a majority of
such directors then in office.

     Long-Term   Incentive  Plan.  Awards  granted  pursuant  to  the  Company's
Long-Term  Incentive  Plan may  provide  that,  upon a change in  control of the
Company,  (a) each  holder of an option  will be granted a  corresponding  stock
appreciation  right,  (b) all outstanding  stock  appreciation  rights and stock
options become immediately and fully vested and exercisable in full, and (c) the
restriction  period on any restricted  stock award shall be accelerated  and the
restrictions shall expire.

     Debt.  Certain  provisions  in the Bank  Facility and Senior Notes may also
impede a change in control,  in that they provide that the Bank loans and Senior
Notes  become  due if there is a change in the  management  of the  Company or a
merger with another company.  The Senior Notes would become due upon an increase
in ownership of Common Shares  outstanding  to over 20% of the then  outstanding
Common Shares.


                                      -27-
<PAGE>

ITEM 6. SELECTED FINANCIAL DATA.
-------------------------------

     The  following  historical  selected  consolidated  financial  data  of the
Company  are  derived  from,  and  qualified  by  reference  to,  the  Company's
Consolidated Financial Statements and the notes thereto. The historical selected
financial  data for the five years ended December 31, 1998 were derived from the
Company's audited consolidated  financial statements.  The information contained
in this table should be read in conjunction  with  "Management's  Discussion and
Analysis of Financial Condition and Results of Operations," and the Consolidated
Financial  Statements  of the Company and the notes thereto  included  elsewhere
herein.
<TABLE>
<CAPTION>

                                                   For the year ended December 31,
                                      1994         1995         1996           1997         1998
                                      ----------------------------------------------------------
     Summary of Operating Data:             (dollars in thousands, except per share data)
<S>                                    <C>          <C>          <C>            <C>       <C>  

Oil and natural gas sales          $ 17,338    $  18,447     $  20,063     $   37,841    $  50,291
Lease operating expense               5,231        8,055         8,186         11,150       18,148
Depreciation, depletion &             
   amortization expense               6,038        8,064         9,022         18,866       37,500
General and administrative expense      587          690         1,063          1,919        4,629 
Production and ad valorem taxes       1,006        1,078           559            721        1,351
Exploratory dry hole expense             --        8,112            --             67        5,655
Geological and geophysical expense       --           --            --            286        1,927
Impairment of oil and gas properties  1,202          751            --             --       20,406
Office consolidation and severance
   expense                               --           --            --             --          987
West Delta fire loss                     --           --           500             --           --
                                   --------    ---------     ---------      ---------     --------
                                   $  3,274    $  (8,303)    $     733      $   4,832     $(40,312)
Interest expense (net)                1,623          987         2,514          3,930        9,639
Gain (loss) on investment in 
Common stock                             --           --          (258)            75           --
Income taxes (benefit)                   --           --            --             --       (3,100)
Extraordinary item- loss on early                                                                  
   retirement of debt                  (536)          --            --           (934)          --
                                   --------     --------     ---------      ---------     --------
Net income (loss)                  $  1,115     $ (9,290)    $  (2,039)     $      43     $(46,851)
                                   ========     ========     =========      =========     ========

Net income (loss) per Common Share $   0.11     $  (0.81)    $   (0.16)     $      --     $  (1.96)

Summary Balance Sheet Data:                                                              
Oil and gas properties (net)       $ 23,945     $ 29,485     $  50,540      $ 112,548     $100,723
Total assets                         29,095       36,169        73,768        179,629      143,372   
Long-term debt                       12,500       22,390        49,500        101,700      115,749
Stockholders' equity                 14,882        9,174        17,498         55,188        7,902
Dividends per Common Share 
</TABLE>

     The following  discussion  should be read in conjunction with the Company's
Consolidated  Financial Statements,  "Selected  Consolidated Financial Data" and
respective  notes thereto,  included  elsewhere  herein.  The information  below
should  not be  construed  to  imply  that the  results  discussed  herein  will
necessarily  continue into the future or that any conclusion reached herein will
necessarily  be  indicative  of actual  operating  results in the  future.  Such
discussion  represents  only the best present  assessment  of  management of the
Company. Because of the size and scope of the Company=s recent acquisitions, the
results of operations from period to period are not necessarily comparative.

     Several  material  acquisitions  and one  material  disposition  took place
during  the  five  years  ended  December  31,  1998,  see   "Business-Strategic
Acquisitions and Mergers." In July 1995 the Company  purchased  interests in six
offshore  blocks from Zapata  Exploration  Corp.  for $2.7 million in cash and a
production  payment to Zapata based on future  production.  In December 1995 the
Company purchased the Bayou Sorrel Field from Shell Western E & P Inc. for a net
purchase  price of $9.7 million in cash.  This was  primarily  an oil  property,
which was  subsequently  sold  effective  September 1, 1996 for $11 million.  In
October 1996 the Company  acquired  interests in six offshore  fields from Amoco
Production  Company for $32 million in cash and 2 million  newly  issued  Common
Shares. In July 1997 the Company acquired the Goldking Companies, Inc. for $27.5
million in  consideration  plus the assumption of  liabilities.  In May 1998 the
Company  acquired  interests in three offshore fields from BP Exploration & Oil,

                                      -28-
<PAGE>

Inc. for $19.6 million in cash.  All of these  acquisitions  were  accounted for
using the purchase  method.  This  information is also included in and should be
read in conjunction  with the Company's  Consolidated  Financial  Statements and
"Management's  Discussion  and  Analysis of Financial  Condition  and Results of
Operations."

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

General
-------
     Forward-looking statements in this Form 10-K, future filings by the Company
with the Securities and Exchange  Commission,  the Company's  press releases and
oral statements by authorized officers of the Company are intended to be subject
to the safe harbor provisions of the Private Securities Litigation Reform Act of
1995. Investors are cautioned that all forward-looking  statements involve risks
and uncertainty, including without limitation, the risk of a significant natural
disaster,  the inability of the Company to insure  against  certain  risks,  the
adequacy of its loss reserves,  fluctuations in commodity  prices,  the inherent
limitations in the ability to estimate oil and gas reserves, changing government
regulations, as well as general market conditions,  competition and pricing. The
Company  believes  that  forward-looking  statements  made  by it are  based  on
reasonable expectations. However, no assurances can be given that actual results
will  not  differ  materially  from  those  contained  in  such  forward-looking
statements.  The words "estimate,"  "anticipate," "expect," "predict," "believe"
and similar expressions are intended to identify forward-looking statements.

     The oil and natural gas industry has experienced  significant volatility in
recent  years  because  of the  fluctuatory  relationship  of the supply of most
fossil fuels relative to the demand for such products and other uncertainties in
the world energy markets.  These industry  conditions  should be considered when
this analysis of the Company's operations is read.

Year 2000 Issue
---------------

     The various problems that may result from the use of date codes in software
and other  machinery  is referred  to as the "Year 2000  Issue." The once common
practice  of using a  two-digit  identifier  for the year in a date may  cause a
program  or system to become  faulty or  inoperative  on or prior to  January 1,
2000.  This document  serves as an  informational  disclosure  regarding the Y2K
assessment  activities  for  PANACO,  Inc.  and its  subsidiaries  (collectively
"PANACO") under the Year 2000 Information and Readiness Disclosure Act of 1998.

     PANACO  established  a program  during 1998 to ensure  that,  to the extent
reasonably possible, all systems are or will be Year 2000 ready prior to the end
of 1999. The Year 2000 Program ("Y2K Program"),  designed with the assistance of
an outside  consultant,  consists of five phases: (a) Assessment -which includes
compiling an inventory of PANACO's  assets,  including  significant  third-party
supplier and customer relationships,  (b)  Repair/Upgrade/Replace  -including an
analysis of the assets to determine  compliance or non-compliance and repairing,
upgrading or replacing those that are non-compliant, (c) Compliance Testing, (d)
Contingency Planning, and (e) Roll-over Planning.

     A team consisting of PANACO managers from Information  Technology,  Finance
and Operations has been  established as the Year 2000  Compliance  Project Team.
With  the  assistance  of its  outside  consultant,  the Team  has  designed  an
aggressive schedule to identify information  technology ("IT") and non-IT assets
requiring readiness upgrades, and a timetable for performance and testing of the
affected  systems.  In  addition,  the  Y2K  Program  calls  for  validation  of
compliance by significant PANACO suppliers and customers.

     Once  identified,  detailed  remediation  steps will be scheduled to ensure
that internal systems and significant  external suppliers and customers meet Y2K
compatibility requirements, or that sufficient contingency plans are in place.

     Current Status

     As of April  1999,  PANACO's  Year  2000  assessment  is not  complete.  An
inventory of computing,  communications  and facility  systems has been prepared
and validated.  Significant  third-party  suppliers and customers have also been
identified for validation.


                                      -29-
<PAGE>

     PANACO has substantially completed the inventory for both its IT and non-IT
systems and expects to complete  the  assessment  phase for these  systems on or
prior to July 2, 1999.  The Y2K Program  calls for the  completion of all phases
for both IT and non-IT systems by year-end  1999.

     PANACO is  performing a review of  significant  third party  suppliers  and
customers and,  where  available,  is surveying the public Year 2000  statements
issued by them.  Additionally,  PANACO has sent  questionnaires to certain third
party   suppliers  and  customers   requesting   information   regarding   their
vulnerability  to  Year  2000  issues.  PANACO  intends  to  pursue  appropriate
responses to these inquiries and evaluate the responses it receives to determine
if alternate business actions will be necessary.  PANACO expects to complete the
third party assessment  phase by July 2, 1999, at which time  contingency  plans
will be developed.

     Costs

     The  estimated  total  costs  for Y2K  readiness  has been  nominal.  It is
anticipated  that such costs for  complete  Y2K  readiness  will  continue to be
nominal. In addition,  there have been no material capital  expenditures for Y2K
and there is not  anticipated  to be  material  capital  expenditures,  as it is
believed at this point that most major  critical  field  operations  do not have
date sensitive  equipment.  The company does not  separately  track the internal
costs  incurred  for the Y2K project as such costs are  principally  the related
payroll costs for its  information  systems  group.  Remediation  and testing is
scheduled to be completed during the 3rd quarter of 1999.

     Contingency Plans

     Should any systems,  customers or  significant  suppliers be  determined to
have questionable  remediation potential,  the Year 2000 Compliance Project Team
will  establish a  contingency  plan to address the at-risk  area.  This will be
decided during the analysis phase of the overall project now underway. PANACO is
unable at this time to  determine  what  contingency  plans,  if any,  should be
implemented.  As  PANACO  progresses  through  the Y2K  Program  and  identifies
specific risk areas, it intends to timely implement appropriate remedial actions
and contingency plans.

     Risks

     The failure to correct a Year 2000 problem could result in the interruption
or failure of certain normal business activities or operations.  PANACO believes
that the  greatest  risks lie in its (a)  financial  systems  applications,  (b)
embedded chips in field  equipment,  (c) and third parties.  A significant  Year
2000-related  disruption in these systems could disrupt financial and accounting
functions, crude oil and natural gas production,  transportation,  and marketing
activities.  This  disruption  could  have  a  material  adverse  effect  on the
Company's operating results and liquidity.

     PANACO is not presently aware of any vendor related Year 2000 issue that is
likely to result in any  disruption  of this type.  Although  there is  inherent
uncertainty in the Year 2000 issue,  PANACO expects that as it progresses in its
Y2K Program,  the level of  uncertainty  about the impact of the Year 2000 issue
will be reduced significantly.

     Conclusion and Disclaimers

     These estimates and conclusions contain forward-looking  statements and are
based on  management's  best estimates of future events.  PANACO's  expectations
about  risks,  future  costs,  and  the  timely  completion  of  its  Year  2000
remediation  are subject to  uncertainties  that could cause  actual  results to
differ materially from the statements made in this readiness disclosure.


                                      -30-
<PAGE>

Liquidity and Capital Resources
-------------------------------

     The Company  currently has a $17 million capital budget for 1999,  which is
subject to change  upon review by  management  and the board of  directors.  The
Company   anticipated  funding  this  capital  budget  through  cash  flows  and
borrowings  under its line of credit.  In  conjunction  with an amendment to the
loan  agreement,  on April 13, 1999 the borrowing  base under the line of credit
was reduced to $25 million,  see "Bank  Facility." The amendment  provides for 4
million  reductions  in this  borrowing  base on June 30, 1999 and September 30,
1999. With these reductions in the borrowing base, and the amount outstanding on
April 16, 1999 of $24  million,  the Company will be required to reduce its 1999
capital  budget to $11.5  million,  which it currently  has  committed to spend.
These   assumptions  do  not  include  any  external  sources  of  financing  or
redeterminations  of its borrowing  base. The line of credit permits the Company
to request such a redetermination from the bank.

     On March 5, 1997,  the Company  completed an offering of  8,403,305  common
shares at $4.00 per  share,  $3.728  net of the  underwriter's  commission.  The
offering  consisted of 6,000,000 shares sold by the Company and 2,403,305 shares
sold by shareholders,  primarily Amoco Production Company (2,000,000 shares) and
lenders advised by Kayne, Anderson Investment Management, Inc. (373,305 shares).
The  Company's net proceeds of $22 million from the offering were used to prepay
$13.5 million of its 12% subordinated  debt and the remainder was used to reduce
borrowings under the Company's bank facility.

     On October 9, 1997, the Company issued $100 million  principal amount of 10
5/8%  Senior  Notes due  October  1,  2004.  Interest  on the  Notes is  payable
semi-annually  in  arrears on each April 1 and  October 1,  commencing  April 1,
1998.  Of the  $96.2  million  net  proceeds,  $54.7  million  was used to repay
substantially all of the Company's  outstanding  indebtedness with the remaining
$41.5 million used for capital expenditures and the BP Acquisition.

Bank Facility

     In  December  1998,  the  Company  amended  its bank  facility.  See  "Bank
Facility." The loan is a reducing revolver designed to provide the Company up to
$75 million  depending on the  Company's  borrowing  base,  as determined by the
lenders. The Company's borrowing base at December 31, 1998 was $45 million, with
availability  under the revolver of $31.5 million.  The principal  amount of the
loan is due  October  22,  2002.  However,  at no  time  may  the  Company  have
outstanding  borrowings  in excess of its  borrowing  base. At April 1, 1999 the
borrowing  base was reduced to $25 million.  The borrowing base is subject to $4
million  reductions  on June 30,  1999  and  September  30,  1999.  The  balance
outstanding under the Bank Facility at April 15, 1999 was $24 million.  Interest
on the loan is computed at the bank's  prime rate or at 1.5 to 2.25%  (depending
upon the  percentage  of the  facility  being used) over the  applicable  London
Interbank  Offered Rate ("LIBOR") on Eurodollar  loans.  Eurodollar loans can be
for terms of one, two,  three or six months and interest on such loans is due at
the  expiration of the terms of such loans,  but no less  frequently  than every
three months.  The Bank Facility is  collateralized  by a first  mortgage on the
Company's offshore properties.

     The loan agreement  contains certain  covenants  including a requirement to
maintain a positive  indebtedness to cash flow ratio, a positive working capital
ratio,  a certain  tangible net worth,  as well as  limitations  on future debt,
guarantees,  liens, dividends, mergers, and sale of assets. At December 31, 1998
the Company was not in compliance  with these  covenants which has been remedied
by waivers  and an  amendment  to the Bank  Facility.  However,  the Company has
classified  this debt as a current  liability  since it is probable  the Company
will fail to meet these  covenants  at  measurement  dates prior to December 31,
1999. The failure to satify these  covenants,  or any of the other  covenants in
the Bank Facility would  constitute an event of default  thereunder and, subject
to grace  periods,  may  permit  the  lenders  to  accelerate  the  indebtedness
oustanding under the Bank Facility and demand immediate payment thereof. In such
event,  the Company  could be required to sell certain oil and gas assets,  sell
equity securities or obtain additional bank financing. No assurance can be given
that such  transactions can be consummated on terms acceptable to the Company or
its lenders,  whose approval may be required. In this situation,  if the Company
is unable to raise the necessary  funds,  the Company could become in default on


                                      -31-
<PAGE>

the full  amount of its  indebtedness,  which  includes  the Senior  Notes.  The
holders of the Senior Notes have acceleration  rights,  subject to certain grace
periods, if the Company is in default under the Bank Facility.

     In 1998 the Board  approved a program to  repurchase  up to 500,000  Common
Shares.  The Board also authorized the redemption of the Shareholder Rights Plan
at the stated value of $.005 per share.  In September,  October and November the
Company  purchased  304,650 shares of common stock for a total of $592,000.  The
cost of redeeming the Shareholders Rights Plan totaled $118,000.

     At December 31, 1998, 86% of the Company's total assets were represented by
oil and natural gas properties,  pipelines and equipment,  net of  depreciation,
depletion and amortization.

     Pursuant to existing agreements the Company is required to deposit funds in
bank trust and escrow accounts to provide a reserve against  satisfaction of its
eventual  responsibility  to plug and abandon wells and remove  structures  when
certain  fields no longer  produce oil and gas.  The Company has entered into an
escrow agreement with Amoco Production Company under which the Company deposits,
for the life of the fields,  in a bank escrow  account ten percent  (10%) of the
net cash flow,  as  defined in the  agreement,  from the Amoco  properties.  The
Company has  established the "PANACO East Breaks 110 Platform Trust" in favor of
the Minerals  Management  Service of the U.S.  Department of the Interior.  This
trust  required an initial  funding of $846,720 in December  1996, and remaining
deposits of $244,320  due at the end of each quarter in 1999 and $144,000 due at
the end of each quarter in 2000 for a total of $2.4 million.  In connection with
the BP Acquisition, the Company deposited $1.0 million into an escrow account on
July 1, 1998.  On the first day of each  quarter  thereafter,  the Company  will
deposit $250,000 into the escrow account until the balance in the escrow account
reaches  $6.5  million.

     In 1998, the Company spent $61.8 million in cash for capital  expenditures,
approximately  $19.6  million  of  which  was  for  the BP  Acquisition  and the
remainder  was for  development  of its  oil  and  natural  gas  properties  and
participation in exploration projects.

Results of Operations
---------------------

For the years ended December 31, 1998 and 1997:

     The  decreases  in oil and  natural  gas prices  realized by the Company in
1998,  as  discussed  below,  in  combination  with other key factors led to the
significant  loss in 1998.  Price declines led to a $20.4 million  impairment of
its oil and gas properties based on estimated  recoverability  of the book value
of those assets. A substantial increase in non drilling exploration expenses and
exploratory  dry hole expense,  along with the closing of the  Company's  Kansas
City,  Missouri office and the related severance expense also contributed to the
net loss for the year.

     Production.  Natural gas  production  increased  57%, to 18,041,000  Mcf in
1998,  from 11,468,000 Mcf in 1997. The BP Acquisition in May 1998, the Goldking
Acquisition in July 1997 and successful  developmental drilling programs in 1997
and 1998 were the primary  factors in the  increased  production.  The  Goldking
Acquisition  and  several  wells  completed  on  those  properties  during  1998
accounted for an increase of 4,844,000 Mcf. Successful developmental drilling in
the High Island 309 and 310 Fields  accounted  for an increase in  production of
2,537,000 Mcf, while a successful  developmental  well and the  acquisition of a
co-owner's  working  interest  in the West  Cameron 144 Field  accounted  for an
increase of 600,000 Mcf.

     Oil  production  increased  74% in 1998 to 895,000  barrels,  from  515,000
barrels in 1997. The primary  factors in the increased oil  production  were the
acquisition  of  the  East  Breaks  165  Field  in  May  1998  and a  successful
developmental well completed in the Umbrella Point Field in January 1998.

     Prices.  Average  natural  gas  prices,  net  of  the  impacts  of  hedging
transactions,  decreased  17% in 1998,  from  $2.49  per Mcf in 1997 to $2.07 in
1998.  The 1998  natural  gas hedge  program  had the effect of  increasing  the
natural gas price  realized by $0.02 per Mcf in 1998 and  decreasing it by $0.10
per Mcf in 1997.  The Company had natural gas hedged in quantities  ranging from
10,000 to 50,000  MMbtu per day in each month in 1998 for a total of  11,980,000
MMbtu, at pipeline prices averaging  approximately  $2.05 per MMbtu, for a NYMEX
equivalent of approximately $2.20 per MMbtu.

                                      -32-
<PAGE>

     Average oil prices, net of the impacts of hedging  transactions,  decreased
20%,  to $14.47 per barrel,  from $18.04 per barrel in 1997.  The 1998 oil hedge
program had the effect of increasing the average net oil price realized by $2.27
per barrel.  The Company hedged its oil prices on 1,268 Bbls of oil for each day
in 1998 at an average  swap price of $19.06  per Bbl,  with a 40%  participation
above $19.28 on 500 of the 1,268 Bbls.  Depressed commodity prices will continue
to have a  negative  impact on the  Company's  results of  operations.

     "Oil and natural gas sales"  increased 33% in 1998 despite the 20% decrease
in oil prices and 17%  decrease in natural gas prices.  Increases in natural gas
and oil  production  brought  about the  increase  in oil and natural gas sales.
During August and September, the Company was required for safety reasons to shut
in at least a portion of its production facilities due to severe weather on four
separate occasions.  The increased production in 1998, as discussed above, would
have been  greater had the storms in the Gulf of Mexico in August and  September
not occurred.

     "Lease operating  expense"  increased $7.0 million  primarily due to the BP
and Goldking  Acquisitions,  these  expenses  increased to $0.78 per Mcfe,  from
$0.77 per Mcfe in 1997.

     "Depletion,   depreciation  and   amortization"   increased  $18.6  million
primarily due to the increase in 1998 production as discussed  above. The amount
per Mcfe also increased from $1.30 in 1997 to $1.60 in 1998. The increase in the
amount  per Mcfe was in part due to the  decline  in  reserve  value of  several
small, non-operated oil properties.  The magnitude of depletion is also impacted
by the relatively short lives of the Company's proved reserves.  Currently,  the
average life of the Company's proved reserves is approximately five and one-half
years.

     "General and administrative  expense" increased $2.7 million in 1998 due to
acquisitions  made by the  Company  in July 1997,  April 1998 and May 1998.  The
Company  increased  its  allowance  for doubtful  accounts by $1 million in 1998
which also accounted for a large percentage of the increase.

     "Production and ad valorem taxes" increased  $630,000 in 1998, to 3% of oil
and natural gas sales,  from 2% in 1997. The increase is due to production  from
properties subject to state taxes which were acquired in July 1997.

     "Exploratory dry hole expense" reflects the Company's increased exploratory
activities  in 1998.  Of the 19 wells the  Company  drilled or  participated  in
during 1998, six of the exploratory wells were not commercially productive.  Two
of the wells were spudded and completed  during the first quarter of 1998, three
others  reached total depth during the second  quarter and the final one reached
total depth during the third  quarter.  The wells were operated by third parties
and the Company owned working interests ranging from 10 to 20%.

     "Geological  and  geophysical   expense"  during  1998  resulted  from  the
Company's non-drilling exploratory activities.

     "Impairment of oil and gas properties" represents an impairment of the book
value of the Company's oil and gas properties based on estimated future net cash
flows from those  properties.  The  impairment  was  primarily due to much lower
estimates  of oil and natural gas prices at December 31,  1998.  The  impairment
tests were based upon  future  cash flows  using an initial  price of $11.50 per
barrel of oil and $1.90 per MMbtu of  natural  gas,  each  moderately  escalated
thereafter. Costs and expenses were also escalated at 3%.

   
     "Office consolidation and severance expense" was a non-recurring charge for
the costs  associated with closing the Company's  Kansas City,  Missouri office.
The charge  includes  costs for the relocation of personnel and equipment to its
Houston, Texas office and severance costs for several former employees.

     "Interest  expense  (net)"  increased $5.8 million in 1998 primarily due to
increased  borrowing  levels.  The increase in borrowing is due to the Company's
Senior Note offering  completed in October 1997. The increase is somewhat offset
by a reduced  interest  rate on a majority of the  Company's  long term debt. In
connection  with the offering,  the Company  prepaid or repaid long term debt, a
significant  amount  of which  had  rates in  excess  of the 10 5/8% rate on the
Notes.  This included amounts borrowed in connection with the Amoco  Acquisition
in October 1996 and debt assumed in connection with the Goldking  Acquisition in
July 1997.

                                      -33-
<PAGE>

Results of Operations
---------------------

For the years ended December 31, 1997 and 1996:
 
     The Company  experienced a fire on April 24, 1996 at Tank Battery #3 in the
West Delta Fields  resulting in these fields being shut-in from April 24th until
being  returned  to  production  on October 7, 1996.  The fire  resulted in lost
revenues estimated by management to be approximately $6 million.

     The Company spent $8.5 million on Tank Battery #3 inclusive of the $500,000
expensed during 1996 and has received  reimbursement  from its insurance company
of $3.9 million,  after satisfaction of the $225,000 in deductibles.  The excess
of expenditures over insurance  reimbursement has been capitalized.  The Company
has filed suits  against the  employers of the persons who caused the  incidents
for recovery of these costs and its lost profits. No assurance can be given that
the Company  will  successfully  recover  any amounts  sought in any such suits.

     Production.  Natural gas production increased 69% to 11,468,000 Mcf in 1997
from  6,788,000  Mcf in 1996.  Oil  production  increased 87% in 1997 to 515,000
Bbls,  from 275,000 Bbls in 1996.  Results for 1997 include  production from the
former Amoco and Goldking  properties,  purchased in October 1996 and July 1997,
respectively.  Results for 1997 also included increased production from the West
Delta Fields, which were shut-in from April 24, 1996 until October 1996. They do
not include  production  from the Bayou Sorrel Field which was sold September 1,
1996.
     In March,  1997 the  federal  production  from the West Delta  Block 58 was
brought back on-line for the first time since April 1996 with the  completion of
a dual six inch,  eight  mile  pipeline  to the West  Delta  central  processing
facility,  Tank Battery #3. This pipeline also allowed  Samedan  Corporation  to
resume  production from their well,  drilled on a farm-out from the Company,  on
which the Company  receives  overriding  royalty revenue and fees for processing
the oil and low pressure  natural gas.

     Prices.  Natural  gas prices,  net of the impacts of hedging  transactions,
increased  from  $2.17 per Mcf in 1996 to $2.49 in 1997.  The 1997  natural  gas
hedge  program had the effect of reducing  natural gas prices by only ($.10) per
Mcf in 1997,  compared to ($.58) per Mcf in 1996. The 1997 hedge program allowed
the Company more  participation  in increases in market  prices for natural gas,
while  providing  the price  stability of no less than $1.80 per MMbtu on 14,000
MMbtu per day.  Oil prices  decreased  in 1997 to $18.04 per Bbl from $19.42 per
Bbl in 1996.

     "Oil and natural gas sales" increased 89% in 1997. Significant increases in
both natural gas and oil  production  were the primary factor in the increase in
revenues. The former Amoco and Goldking properties, acquired in October 1996 and
July 1997, respectively, coupled with the resumption of production from the West
Delta  Fields,  and  the  Company's  development  program  on the  former  Amoco
properties has significantly increased production.

     "Depletion,  depreciation and amortization expense" increased $9.8 million,
or 109% also in part due to the  purchase  of the  former  Amoco  properties  in
October 1996. The amount per Mcf equivalent also increased from $1.07 in 1996 to
$1.30 in 1997, due to several factors.  Downward engineering  revisions,  in the
West Delta and East Breaks 110 Fields at year-end 1996 were a  significant  part
of the increase.  Also,  $4.0 million in capital  expenditures  made during 1996
(over and above insurance reimbursement) to rebuild Tank Battery #3, the central
processing facility for the West Delta Fields,  increased the depletion cost per
Mcf equivalent for those fields.

 
     "Lease operating expense"  increased $3.0 million,  or 36% in 1997 with the
addition of interests in thirteen  offshore blocks acquired in October 1996 from
Amoco and the interests in the properties  acquired in the Goldking  Acquisition
in July  1997.  As a  percent  of oil and  natural  gas  sales,  lease-operating
expenses decreased to 29% in 1997 from 41% in 1996.

     "Production  and ad valorem  taxes"  increased 29% in 1997,  however,  as a
percentage of oil and natural gas sales they decreased to 2%, from 3% of oil and
natural gas sales in 1996. The decrease is due to the Company's shift to federal
offshore waters where there are no state severance taxes.

     "Geological and geophysical expense" in 1997 resulted from the non-drilling
exploratory costs incurred in the fourth quarter.

     "Exploratory  dry hole  expense"  incurred in 1997  resulted from an option
paid to  participate in an  exploratory  well in the High Island Area,  offshore

                                      -34-
<PAGE>

Texas  which was  condemned  before the well was  drilled  because of a dry hole
drilled  by  another  company  on an  adjacent  block.  There will be no further
exploration expenses associated with this prospect.

     "General and  administrative  expense"  increased  $856,000  primarily as a
result of the  Goldking  Acquisition.  As a  percentage  of oil and  natural gas
sales, general and administrative expenses remained flat at 5%.

     "Interest  expense  (net)"  increased  56%  in  1997  primarily  due to the
increased  average  borrowing  levels  from the  debt  assumed  in the  Goldking
Acquisition  and to a lesser extent the offering of 10.625% $100 million  Senior
Notes in October 1997.

     "Gain (loss) on  investment in common stock" is the gain on the sale of the
Company's 477,612 shares of National Energy Group, Inc. common stock realized in
1997. Item 7a. Qualitative and Quantitative Disclosure About Market Risks.

     The Company  follows a conservative  hedging  strategy  designed to protect
against  the  possibility  of  severe  price  declines  due  to  unusual  market
conditions.  Decisions  are usually  made so as to assure a payout of a specific
acquisition or development  project or to take advantage of unusual  strength in
the market.

     The Company enters into commodity  hedge  agreements to reduce its exposure
to price risk for oil and  natural  gas.  Pursuant  to these  hedge  agreements,
either the Company or the  counterparty is required to make payment to the other
each month. The natural gas hedge agreements in 1998 provided a minimum price of
$1.84 on volumes  ranging  from 10,000  MMbtu to 50,000 MMbtu per day of natural
gas. A gain of $431,000 was realized on this hedge in 1998.

     The oil hedge  agreement  in 1998  provided  the Company with an average of
$19.06 on 1,268 Bbls of oil per day,  based upon the  arithmetic  average of the
daily  settlement  prices for the New York  Mercantile  Exchange  (NYMEX) with a
participation  of 40% above  $19.28 on 500 of those  barrels  per day. A gain of
$2.0 million was realized on these hedges in 1998.

     The  Company  currently  has  hedge  agreements   involving  the  following
provisions for the periods shown:

                                       OIL
                      ------------------------------------------------
                                                 Average
                      Notional Quantity        Fixed Price          Market
      Period           Per day (Bbls)            (Bbl)              Price
     -------          ----------------         -----------          -----
       1999                  223                 $17.27             NYMEX

       2000                  232                 $17.35             NYMEX

                                    NATURAL GAS
                      ------------------------------------------------
                                                 Average
                      Notional Quantity        Fixed Price         Market
      Period           Per day (MMbtu)           (MMbtu)           Price
     -------          ----------------         -----------         -----
       1999                7,260                 $ 1.89           Pipeline
                                                                   Prices

       1999 (April to                                             Pipeline
       September)         20,000                 $ 2.06            Prices
                                 

       2000                  218                 $ 1.87           Pipeline
                                                                   Prices

     These hedge agreements provide for the counterparty to make payments to the
Company to the extent the market prices (as  determined  in accordance  with the


                                      -35-
<PAGE>

agreement) are less than the fixed prices for the notional  amount  hedged,  and
the Company to make payments to the counterparty to the extent market prices are
greater  than the fixed  prices.  For oil "market  prices and fixed  prices" are
referenced  to NYMEX.  However,  for  natural  gas, "market  prices" and "fixed
prices" are referenced to published  pipeline  index prices,  which are also the
prices at which  the  Company  sells its  natural  gas on the spot  market.  The
Company  accounts for the gains and losses in oil and natural gas revenue in the
month of hedged production.  The annual notional quantity of oil and natural gas
under  the  hedge  agreements  in 1999 is  equal  to  approximately  7% and 41%,
respectively, of its anticipated 1999 production based upon the year end reserve
reports.  At December 31,  1998,  the  estimated  fair market value of the hedge
agreements in place at that time was a gain of $1.8  million.  A 10% increase in
the underlying  commodity prices would result in a $1.4 million reduction in the
fair value of these agreements.

     At  December  31,  1998  the  Company  had $100  million  in  Senior  Notes
outstanding  with a fixed interest rate of 10 5/8%. The fair value of the Notes,
based on quoted market prices at December 31, 1998, was $78 million. The Company
had $13.5 million  outstanding under its Bank Facility at December 31, 1998. The
Bank Facility is a floating rate  facility,  with a fair value of $13.5 million.
The Company does not have any  interest  rate hedge  agreements  at December 31,
1998.

ITEM 8. FINANCIAL STATEMENT AND SUPPLEMENTARY DATA.
--------------------------------------------------

     The financial  statements  are included  herein  beginning at page F-1. The
table of contents at the front of the financial  statements  lists the financial
statements and schedules included therein.

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

     On June 11,  1998,  Arthur  Andersen  LLP  informed the Company that it had
declined to stand for reelection as  independent  auditors of the Company at its
1998 annual meeting. The board of directors,  upon recommendation from its Audit
Committee, engaged KPMG LLP as the Company's new independent accountant to audit
the financial  statements for the year ended  December 31, 1998.  During the two
most recent  fiscal years and through the date of this  report,  the Company has
had no  disagreements  with  Arthur  Andersen  LLP on any  matter of  accounting
principles or practices,  financial  statement  disclosure or auditing  scope or
procedure,  which  disagreement(s),  if not  resolved  would caused them to make
reference thereto in their report on the consolidated financial statement of the
Company for such years.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
-----------------------------------------------------------

     The  information  required by this item will be  included  in a  definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 1998. Such information is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION.
-------------------------------
     The  information  required by this item will be  included  in a  definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 1998. Such information is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. 
-----------------------------------------------------------------------

     The  information  required by this item will be  included  in a  definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 1998. Such information is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
-------------------------------------------------------

     The  information  required by this item will be  included  in a  definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after December 31, 1998. Such information is incorporated herein by reference.


                                      -36-
<PAGE>

Part IV

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

          (a) See Index to Financial Statements, Page F-1.

          (b) Reports on Form 8-K. The following  reports on Form 8-K were filed
          during the last quarter of the period covered by this report:

             October 23, 1998      Change in Registrant's Certifying Accountant

          (c) Exhibits and Financial Statement Schedules.

        Exhibit
        Number     Description
        ------     -----------------


          3.1*     Certificate of Incorporation of the Company.

          3.2*     Amendment to Certificate of Incorporation dated November 19,
                   1991. 3.3* By-laws of the Company.

          3.4      Amendment to  Certificate of  Incorporation  of the Company
                   dated September 24, 1996 filed as an exhibit to the Amended
                   Current Report on Form 8-K/A, filed with the Commission on
                   November 18, 1996, and incorporated herein by this reference.

          4.1*     Article Fifth of the  Certificate  of Incorporation  of the
                   Company in Exhibit  3.1.

          4.2*     Form of Certificate  of Common  Shares par value $.01 per
                   share,  of the Company.

          4.3      Rights Agreement, dated as of August 3, 1995, between PANACO,
                   Inc., and American Stock Transfer and Trust Company, which 
                   includes as Exhibit A the Form of Certificate of Designation
                   of Series A Preferred Stock, Exhibit B the Form of  Rights
                   Certificate and Exhibit C the Summary of Rights to Purchase 
                   Preferred  Stock was filed as Exhibit 1 to the  Registration
                   Statement on Form 8-A, filed with the Commission on August
                   21, 1995, and incorporated herein by this reference.


          4.4***   Indenture dated October 9, 1997, among the Company and UMB
                   Bank, N.A., as trustee.

          4.5***   Registration Rights Agreement,  dated as of October 9, 1997,
                   among PANACO,  Inc., and BT Alex Brown, First Union Capital
                   Markets Corp, A.G.Edwards & Sons Inc. and Gaines, Berland
                   Inc.

          4.6***   Form of 10 5/8 % Series B Senior Note due 2004.

          10.1*    PANACO, Inc. Long-Term Incentive Plan.

          10.13**  PANACO, Inc. Employee Stock Ownership Plan & Trust.

          10.13.1  Amendment to PANACO, Inc. Employee Stock Ownership Plan.

          10.14    Purchase and Sale  Agreement,  dated August 26, 1996,
                   between  Amoco  Production  Company and PANACO, Inc., filed
                   as an exhibit to the Current Report on Form 8-K, filed with
                   the  Commission on October 28, 1996, and incorporated herein
                   by this reference.


                                      -37-
<PAGE>

          10.17   Purchase and Sale Agreement,  dated November 11, 1996 between
                  National Energy Group,  Inc. and PANACO, Inc.,  filed as an
                  exhibit to the Current  Report on Form 8-K filed with the
                  Commission on January 29, 1997, and incorporated herein by
                  this reference.

          10.17.1 Restated Merger Agreement dated July 30, 1997 between PANACO,
                  Inc., The Union  Companies,  Inc., Leonard C. Tallerine,  Jr.
                  and Mark C. Licata,  filed with the Commission as an exhibit
                  to the Current Report on Form 8-K on August 15, 1997, and
                  incorporated herein by this reference.

          10.17   Form of Executive  Officer and Director  Indemnification 
                  Agreement,  filed with the  Commission as an exhibit to the
                  Company's Form 10-Q on August 15, 1997, and incorporated
                  herein by this reference.

          10.20*** Form of Warrant to Purchase Shares of Common Stock of PANACO,
                   Inc.  issued by the Company on October 9, 1997 to Offense
                   Group Associates,  L.P., Kayne, Anderson Non-Traditional
                   Investments,  L.P., ARBCO Associates,  L.P., Opportunity
                   Associates, L.P., Kayne, Anderson Offshore Limited, Foremost
                   Insurance Company, TOPA Insurance Company, and EOS Partners,
                   L.P., with respect to an aggregate of 2,060,606 shares.

          10.21*** Amended and Restated  Credit  Agreement,  dated  October 9,
                   1997,  among First Union  National Bank of North Carolina,
                   as agent, and the lenders signatory thereto, and PANACO, Inc.

          10.22****Third Amendment to Amended and Restated Credit Agreement
                   dated April 13, 1999.

          10.23****Employment contract between the Company and Larry M. Wright.

          21.1**** List of subsidiaries of PANACO, Inc.

          27****   Financial Data Schedule.

               *Filed with the  Registration  Statement on Form S-4,  Commission
               File  No.  33-44486,  initially  filed  December  13,  1991,  and
               incorporated herein by this reference.

               **Filed with the Registration  Statement on Form S-1,  Commission
               file  No.  333-18233,  initially  filed  December  19,  1996  and
               incorporated herein by this reference.

               ***Filed with the Registration  Statement on Form S-4, Commission
               File  No.  333-39919,  initially  filed  November  10,  1997  and
               incorporated herein by this reference.

                ****Filed herewith.

          (d) Financial Statement Schedules. See Index to Financial Statements,
           Page F-1.

                                      -38-
<PAGE>

                     GLOSSARY OF SELECTED OIL AND GAS TERMS

     2-D Seismic.  Seismic data and the related  technology  used to acquire and
process  such  data  to  yield  a  two-dimensional  view  of a  Aslice@  of  the
subsurface.

     3-D Seismic.  Seismic data and the related  technology  used to acquire and
process such data to yield a  three-dimensional  picture of the subsurface.  3-D
Seismic is created by the  propagation of sound waves through  sedimentary  rock
layers, which are then detected and recorded as they are reflected and refracted
back to the  surface.  By  measuring  the time taken for the sound to return and
applying computer technology to process the resulting data in volume, imagery of
significantly  greater  accuracy and usefulness than older-style 2-D Seismic can
be created.

     Bbl. One stock tank barrel,  or 42 U.S. gallons liquid volume,  used herein
in reference to oil or other liquid hydrocarbons.

     Bcf. One billion cubic feet of natural gas.

     Bcfe. One billion cubic feet of natural gas equivalents  converting one Bbl
of oil to six Mcf of natural gas.

     Block.  One offshore unit of lease  acreage,  generally  5,000 acres.

     Btu. British Thermal Unit, the quantity of heat required to raise one pound
of water by one degree Fahrenheit.

     Condensate.  A hydrocarbon  mixture that becomes  liquid and separates from
natural  gas when the gas is  produced  and is similar  to crude oil.

     Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.

     Development  Well.  A well  drilled  within  the  proved  area of an oil or
natural  gas  reservoir  to the  depth of a  stratigraphic  horizon  known to be
productive.

     Dry Hole. A well found to be  incapable of producing  either oil or natural
gas in  sufficient  quantities  to justify  completion  as an oil or natural gas
well.
     Estimated Future Net Revenues.  Revenues from production of oil and natural
gas, net of all  production-related  taxes, lease operating expenses and capital
costs.

     Exploratory  Well. A well drilled to find and produce oil or natural gas in
an unproved  area,  to find a new  reservoir in a field  previously  found to be
productive of oil or natural gas in another reservoir.

     Farmout.  An agreement  whereby the lease owner agrees to allow  another to
drill a well or wells and thereby earn the right to an  assignment  of a portion
or all of the lease,  with the  original  lease  owner  typically  retaining  an
overriding royalty interest and other rights to participate in the lease.

     Gross acres or gross wells.  The total acres or wells,  as the case may be,
in which a working interest is owned.

     Group 3-D  Seismic.  Seismic  procured  by a group of  parties or shot on a
speculative basis by a seismic company.

     MBbl. One thousand Bbls of oil or other liquid hydrocarbons.

     Mcf. One thousand cubic feet of natural gas.

     Mcfe. One thousand cubic feet of natural gas equivalents converting one Bbl
of oil to six Mcf of natural gas.


                                      -39-
<PAGE>


     Mcfe/d. Mcfe per day.

     MMbbl.  One million Bbls of oil or other liquid  hydrocarbons.

     MMbtu. One million Btu.

     MMcf. One million cubic feet of natural gas.

     MMcfe. One million cubic feet of natural gas equivalents converting one Bbl
of oil to six Mcf of natural gas.

     Natural  Gas  Equivalent.  The  amount of  natural  gas having the same Btu
content as a given  quantity of oil, with one Bbl of oil being  converted to six
Mcf of natural gas.

     Net Acres or Net Wells. The sum of the fractional  working  interests owned
in gross acres or gross wells.

     Net Oil and Gas Sales.  Oil and  natural gas sales less oil and natural gas
production expenses.

     Net Pay.  The  thickness of a productive  reservoir  capable of  containing
hydrocarbons.

     Net Production. Production that is owned by the Company after royalties and
production due others.

     Net Revenue  Interest.  A share of the Working  Interest that does not bear
any portion of the expense of drilling and completing a well and that represents
the holder's share of production after  satisfaction of all royalty,  overriding
royalty, oil payments and other non-operating interests.

     Overriding Royalty Interest. An interest in an oil and natural gas property
entitling the owner to a share of oil and natural gas  production  free of costs
of exploration and production.

     Payout.  That  point in time when a party has  recovered  monies out of the
production from a well equal to the cost of drilling and completing the well and
the cost of operating the well through that date.

     Productive  Well.  A well that is  producing  oil or natural gas or that is
capable of production in paying quantities

     Proprietary  3-D  Seismic.  Seismic  privately  procured  and  owned by the
procurer.

     Proved  Developed   Non-Producing   Reserves.   Reserves  that  consist  of
(i) Proved  Reserves from wells which have been completed and tested but are not
producing due to lack of market or minor completion  problems which are expected
to be corrected and (ii) Proved  Reserves  currently behind the pipe in existing
wells  and  which  are  expected  to be  productive  due to both  the  well  log
characteristics and analogous production in the immediate vicinity of the wells.
 
     Proved Developed  Producing  Reserves.  Reserves that can be expected to be
recovered  from  currently  producing  zones under the  continuation  of present
operating methods.

     Proved  Developed  Reserves.  Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

     Proved Reserves.  The estimated  quantities of 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  Undeveloped  Reserves.  Proved  reserves  that are  expected  to be
recovered  from new wells on undrilled  acreage,  or from existing wells where a
relatively major expenditure is required for recompletion.


                                      -40-
<PAGE>

     Recompletion.  The  completion for production of an existing well bore in a
different  formation  or  producing  horizon  from  that in  which  the well was
previously completed.

     Royalty Interest.  An interest in an oil and natural gas property entitling
the  owner  to a share  of oil and  natural  gas  production  free of  costs  of
production.

     SEC PV-10.  The  present  value of proved  reserves  is an  estimate of the
discounted  future net cash flows from each of the  properties  at December  31,
1998, or as otherwise indicated.  Net cash flow is defined as net revenues less,
after  deducting  production  and ad valorem  taxes,  future  capital  costs and
operating  expenses,  but before deducting  federal income taxes. As required by
rules of the  Commission,  the future net cash flows have been  discounted at an
annual rate of 10% to  determine  their  "present  value." The present  value is
shown to  indicate  the  effect of time on the value of the  revenue  stream and
should not be  construed as being the fair market  value of the  properties.  In
accordance  with Commission  rules,  estimates have been made using constant oil
and  natural  gas prices and  operating  costs,  at  December  31,  1998,  or as
otherwise indicated.

     Shut-In.  To close down a producing well or field  temporarily  for repair,
cleaning  out,  building  up  reservoir  pressure,  lack of a market or  similar
conditions.

     Sidetrack.  A  drilling  operation  involving  the use of a  portion  of an
existing  well to drill a second hole,  in which a milling tool is used to grind
out a "window"  through the side of a drill casing at some selected  depth.  The
drilling  bit is  then  directed  out of the  window  at a  desired  angle  into
previously  undrilled strata.  From this directional start a new hole is drilled
to the desired  formation  depth and casing is set in the new hole and tied back
into the older casing, generally at a lower cost because of the utilization of a
portion of the original casing.

     Tcf. One trillion cubic feet of natural gas.

     Undeveloped Acreage.  Lease acreage on which wells have not been drilled or
completed to a point that would permit the  production of commercial  quantities
of oil and  natural gas  regardless  of whether  such  acreage  contains  proved
reserves.

     Working Interest.  The operating interest that gives the owner the right to
drill,  produce and conduct operating  activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all  costs  of  exploration,  development  and  operations  and all  risks in
connection therewith.


                                      -41-
<PAGE>

                                   SIGNATURES

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

          PANACO, Inc.

          By: \s\ Larry M. Wright                                April 22, 1999
              -------------------                                --------------
              Larry M. Wright, Chief Executive Officer

     Pursuant to the  requirements of the Securities  Exchange Act of 1934, this
report  has  been  signed  below  by the  following  persons  on  behalf  of the
registrant and in the capacities and on the dates indicated.

          By: \s\ Larry M. Wright                                April 22, 1999
              -------------------                                --------------
              Larry M. Wright,
              Chief Executive Officer and
              Director

          By: \s\Todd R. Bart                                    April 22, 1999
              ---------------                                    --------------
              Todd R. Bart
              Chief Financial Officer

          By: \s\Mark C. Barrett                                 April 22, 1999
              ------------------                                 --------------
              Mark C. Barrett, Director

          By: \s\Donald Chesser                                  April 22, 1999
              -----------------                                  --------------
              Donald Chesser, Director

          By: \s\Harold First                                    April 22, 1999
              ---------------                                    --------------
              Harold First, Director


          By: \s\James B. Kreamer                                April 22, 1999
              -------------------                                --------------
              James B. Kreamer, Director

          By: __________________
              Richard Lampen, Director

          By: __________________
              Felix Pardo, Director

          By: __________________
              Michael Springs, Director

          By: __________________
              A. Theodore Stautberg, Director


                                      -42-
<PAGE>
                                                                 Exhibit 21.1

                          Subsidiaries of PANACO, Inc.

                                                         State of
                                                       Incorporation
                                                       -------------

          Goldking Acquisition Corp.                     Delaware
          
          PANACO Production Company, Inc.                Texas
<PAGE>



<PAGE>

                                  PANACO, Inc.
                          INDEX TO FINANCIAL STATEMENTS


PANACO, Inc. - AUDITED FINANCIAL STATEMENTS                          Page Number
-------------------------------------------                          -----------

  Independent Auditors' Report                                           F-2

  Report of Independent Public Accountants                               F-3

  Consolidated Balance Sheets, December 31, 1998 and 1997                F-4

  Consolidated Statements of Income (Operations) for the Years Ended
     December 31, 1998, 1997 and 1996                                    F-6

  Consolidated Statements of Changes in Stockholders' Equity
     for the Years Ended December 31, 1998, 1997 and 1996                F-7

  Consolidated Statements of Cash Flows for the Years Ended
     December 31, 1998, 1997 and 1996                                    F-8

  Notes to Consolidated Financial Statements for the Years Ended
     December 31, 1998, 1997 and 1996                                   F-10

<PAGE>

                          Independent Auditors' Report



The Board of Directors and Shareholders
PANACO, Inc.

We have audited the accompanying  consolidated balance sheet of PANACO, Inc. and
subsidiaries as of December 31, 1998, and the related consolidated statements of
income  (operations),  changes in stockholders'  equity,  and cash flows for the
year then ended. These consolidated  financial statements are the responsibility
of the  Company's  management.  Our  responsibility  is to express an opinion on
these consolidated financial statements based on our audit.

We conducted our audit 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 audit provides a reasonable basis for our opinion.

In our opinion, the consolidated  financial statements referred to above present
fairly, in all material  respects,  the financial  position of PANACO,  Inc. and
subsidiaries  as of December 31, 1998, and the results of its operations and its
cash  flows  for the year  then  ended in  conformity  with  generally  accepted
accounting principles.

The  accompanying  financial  statements  have been  prepared  assuming that the
Company  will  continue  as a  going  concern.  As  discussed  in  Note 5 to the
financial  statements,  the  Company's  substantial  indebtedness,   restrictive
covenant  requirements and working capital deficit raise substantial doubt about
its  ability to  continue as a going  concern.  Management's  plans in regard to
these  matters are also  described in Note 5. The  financial  statements  do not
include any adjustments that might result from the outcome of this uncertainty.


KPMG LLP
Houston, Texas

April 22, 1999
 


                                       F-2

<PAGE>

                    Report of Independent Public Accountants



To the Stockholders and Board of Directors of PANACO, Inc.:

We have audited the accompanying  consolidated  balance sheet of PANACO, Inc. (a
Delaware  Corporation)  and subsidiaries as of December 31, 1997 and the related
consolidated statements of income (operations),  changes in stockholders' equity
and cash flows for the years ended December 31, 1997 and 1996.  These  financial
statements   are  the   responsibility   of  the   Company's   management.   Our
responsibility  is to express an opinion on these financial  statements based on
our audits.

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

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


ARTHUR ANDERSEN LLP

Kansas City, Missouri
April 7, 1998



                                      F-3

<PAGE>
<TABLE>

                                  PANACO, Inc.
                           CONSOLIDATED BALANCE SHEETS

<CAPTION>

                                     ASSETS
                                     ------

                                                                                     December 31,
                                                                                     -----------
                                                                              1998                1997
                                                                              ----                ----
CURRENT ASSETS
<S>                                                                             <C>                 <C>
Cash and cash equivalents                                              $    3,452,000       $   36,909,000
Accounts receivable                                                         8,332,000            9,735,000
Accounts receivable-employee                                                   18,000                   --
Prepaid and other                                                             268,000              626,000
                                                                       --------------       --------------
        Total current assets                                               12,070,000           47,270,000
                                                                       --------------       --------------
OIL AND GAS PROPERTIES, AS DETERMINED
BY THE SUCCESSFUL EFFORTS METHOD
OF ACCOUNTING
    Oil and gas properties, proved                                        238,377,000          198,840,000
    Oil and gas properties, unproved                                       15,128,000           12,947,000
    Less accumulated depreciation, depletion and amortization            (152,782,000)         (99,239,000)
                                                                       --------------       --------------
        Net oil and gas properties                                        100,723,000          112,548,000

PIPELINES AND EQUIPMENT
    Pipelines and equipment                                                26,252,000           14,875,000
    Less accumulated depreciation                                          (3,415,000)          (1,416,000)
                                                                       --------------       --------------
        Net pipelines and equipment                                        22,837,000           13,459,000

OTHER ASSETS
    Deferred debt costs, net                                                3,359,000            3,813,000
    Restricted deposits                                                     3,719,000            2,256,000
    Employee note receivable                                                  300,000                   --
    Other                                                                     364,000              283,000
                                                                       --------------       --------------
        Total other assets                                                  7,742,000            6,352,000
                                                                       --------------       --------------

TOTAL ASSETS                                                           $  143,372,000       $  179,629,000
                                                                       ==============       ==============



          See accompanying notes to consolidated financial statements.


</TABLE>
                                       F-4



<PAGE>
<TABLE>


                      LIABILITIES AND STOCKHOLDERS' EQUITY
<CAPTION>



                                                                                    December 31,
                                                                                    -----------
                                                                             1998                 1997
                                                                       --------------       --------------
CURRENT LIABILITIES
<S>                                                                          <C>                     <C>    

    Accounts payable                                                   $   16,976,000       $   17,225,000
    Interest payable                                                        2,745,000            2,416,000
    Revolving credit facility                                              13,500,000                   -- 
                                                                       --------------       --------------
     Total current liabilities                                             33,221,000           19,641,000
                                                                       --------------       --------------


LONG-TERM DEBT                                                            102,249,000          101,700,000

DEFERRED INCOME TAXES                                                              --            3,100,000

STOCKHOLDERS' EQUITY
    Preferred Shares, $.01 par value,
       5,000,000 shares authorized; no
       shares issued and outstanding                                               --                   --
    Common Shares, $.01 par value,
       40,000,000 shares authorized;
       23,704,955 and 23,913,531 shares
       issued and outstanding, respectively                                   240,000              239,000
    Additional paid-in capital                                             69,197,000           69,041,000
    Treasury stock, held at cost                                             (592,000)                  --
    Retained deficit                                                      (60,943,000)         (14,092,000)
                                                                       --------------       --------------
       Total Stockholders' Equity                                           7,902,000           55,188,000
                                                                       --------------       --------------



TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                             $  143,372,000       $  179,629,000
                                                                       ==============       ==============


COMMITMENTS AND CONTINGENCIES




          See accompanying notes to consolidated financial statements.


</TABLE>
                                      F-5
<PAGE>
<TABLE>


                                  PANACO, Inc.
                 CONSOLIDATED STATEMENTS OF INCOME (OPERATIONS)

<CAPTION>
                                                                           Year Ended December 31,
                                                                           ----------------------
                                                              1998                 1997                 1996
                                                           ----------           ----------           ----------
REVENUES
<S>                                                            <C>                 <C>                  <C>

    Oil and natural gas sales                           $  50,291,000        $  37,841,000         $  20,063,000

COSTS AND EXPENSES
    Lease operating expense                                18,148,000           11,150,000             8,186,000
    Depreciation, depletion and amortization               37,500,000           18,866,000             9,022,000
    General and administrative expense                      4,629,000            1,919,000             1,063,000
    Production and ad valorem taxes                         1,351,000              721,000               559,000
    Exploratory dry hole expense                            5,655,000               67,000                    --
    Geological and geophysical expense                      1,927,000              286,000                    --
    Office consolidation and severance expense                987,000                   --                    --
    Impairment of oil and gas properties                   20,406,000                   --                    --
    West Delta fire loss                                           --                   --               500,000
                                                       --------------       --------------        --------------
          Total                                            90,603,000           33,009,000            19,330,000
                                                       --------------       --------------        --------------

OPERATING INCOME (LOSS)                                   (40,312,000)           4,832,000               733,000
                                                       --------------       --------------        --------------

OTHER INCOME (EXPENSE)
    Gain (loss) on investment in common stock                      --               75,000              (258,000)
    Interest income                                           849,000              745,000                29,000
    Interest expense                                      (10,488,000)          (4,675,000)           (2,543,000)
                                                       --------------       --------------        --------------
       Total                                               (9,639,000)          (3,855,000)           (2,772,000)
                                                       --------------       --------------        --------------
INCOME (LOSS) BEFORE INCOME
    TAXES AND EXTRAORDINARY ITEM                          (49,951,000)             977,000            (2,039,000)

INCOME TAXES (BENEFIT)                                     (3,100,000)                  --                    --
                                                       --------------       --------------        --------------
INCOME (LOSS) BEFORE
    EXTRAORDINARY ITEM                                    (46,851,000)             977,000            (2,039,000)
EXTRAORDINARY ITEM - Loss on early
    retirement of debt                                             --             (934,000)                   --
                                                       --------------       --------------        --------------
NET INCOME (LOSS)                                      $  (46,851,000)      $       43,000        $   (2,039,000)
                                                       ==============       ==============        ==============

BASIC AND DILUTED EARNINGS (LOSS)
   PER SHARE
    Income (loss) before extraordinary item            $        (1.96)      $          .05        $         (.16)
    Extraordinary item                                             --                 (.05)                   --
                                                       --------------       --------------        -------------- 
    Net income (loss)                                  $        (1.96)      $           --        $         (.16)
                                                       ==============       ==============        ==============

BASIC WEIGHTED AVERAGE
   SHARES OUTSTANDING                                      23,884,091           20,781,205            12,742,213
                                                       ==============       ==============        ==============

DILUTED WEIGHTED AVERAGE
   SHARES OUTSTANDING                                      23,884,091           21,024,847            12,742,213
                                                       ==============       ==============        ==============

          See accompanying notes to consolidated financial statements.
</TABLE>

                                      F-6

<PAGE>
<TABLE>


                                  PANACO, Inc.
           CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
              FOR THE YEARS ENDED DECEMBER 31, 1996, 1997 AND 1998
<CAPTION>




                                                                Common         Additional
                                                                 Share          Paid-In       Treasury         Retained
                                                  Shares       Par Value        Capital        Stock            Deficit
                                                  ------       --------        ----------     --------         --------
<S>                                                <C>           <C>              <C>           <C>              <C>

  Balances, December 31, 1995                   11,504,615  $    115,000    $  21,155,000   $        --    $ (12,096,000)

     Net loss                                           --            --               --            --       (2,039,000)
     Exercise of warrants, shares issued under
        Employee Stock Ownership Plan and
        Director stock bonuses                     845,640         8,000        1,955,000            --               --
     Acquisition of properties                   2,000,000        20,000        8,380,000            --               --
                                              ------------  ------------    -------------   -----------    -------------
  Balances, December 31, 1996                   14,350,255       143,000       31,490,000            --      (14,135,000)

     Net income                                         --            --               --            --           43,000
     Exercise of warrants, shares issued under
        Employee Stock Ownership Plan and
        Director and employee stock bonuses        324,346         3,000          783,000            --               --
     Issuance of warrants to retire debt                --            --          450,000            --               --
     Acquisition of properties                   3,238,930        33,000       14,381,000            --               --
     Issuance of new shares                      6,000,000        60,000       21,937,000            --               --
                                              ------------  ------------    -------------   -----------    -------------
  Balances, December 31, 1997                   23,913,531       239,000       69,041,000            --      (14,092,000)

     Net loss                                           --            --               --            --      (46,851,000)
     Shares issued under Employee
        Stock Ownership Plan and
        Director stock bonuses                      96,074         1,000          274,000            --               --
     Shareholder rights redemption                      --            --         (118,000)           --               --
     Purchase of treasury stock                   (304,650)           --               --      (592,000)              --
                                              ------------  ------------    -------------  ------------    -------------
  Balances, December 31, 1998                   23,704,955  $    240,000    $  69,197,000  $   (592,000)   $ (60,943,000)
                                              ============= ============    =============  ============    =============



          See accompanying notes to consolidated financial statements.
</TABLE>

                                      F-7
<PAGE>
<TABLE>


                                  PANACO, Inc.
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                            Year Ended December 31,
                                                                    1998             1997              1996
                                                                    ----             ----              ----
<S>                                                                   <C>             <C>                 <C>

CASH FLOWS FROM OPERATING ACTIVITIES
   Net income (loss)                                          $ (46,851,000)   $     43,000      $  (2,039,000)
   Adjustments to reconcile net income (loss)                            --              --                 --
       to net cash provided by operating activities:
     Extraordinary item                                                  --         934,000                 --
     Depreciation, depletion and amortization                    37,500,000      18,866,000          9,022,000
     Impairment of oil and gas properties                        20,406,000              --                 --
     Exploration expenses                                         5,655,000          67,000                 --
     Deferred income tax benefit                                 (3,100,000)             --                 --
     Loss (gain) on investment in common stock                           --         (75,000)           258,000
     ESOP stock contribution                                        275,000         165,000            122,000
     Changes in operating assets and liabilities:
         Accounts receivable                                      1,403,000        (969,000)        (1,811,000)
         Related party note receivable                             (318,000)
         Prepaid and other                                          572,000          129,000           274,000
         Accounts payable                                          (249,000)       4,172,000         1,803,000
         Interest payable                                           329,000        1,822,000           363,000
                                                              -------------    -------------     -------------
     Net cash provided by operating activities                   16,198,000       25,154,000         7,992,000
                                                              -------------    -------------     -------------

CASH FLOWS USED IN INVESTING ACTIVITIES
   Proceeds from the sale of oil and gas properties                  23,000           87,000         9,017,000
   Proceeds from the sale of investment in common stock                  --        1,717,000                --
   Capital expenditures and acquisitions                        (61,829,000)     (41,997,000)      (43,050,000)
   Increase in restricted deposits                               (1,463,000)        (141,000)       (2,115,000)
   Other                                                                 --               --            96,000
                                                              -------------    -------------     -------------
     Net cash used in investing activities                      (63,269,000)     (40,334,000)      (36,052,000)

CASH FLOWS FROM FINANCING ACTIVITIES
   Long-term debt proceeds                                       46,049,000      112,459,000        38,514,000
   Repayment of long-term debt                                  (32,000,000)     (84,742,000)      (11,753,000)
   Issuance of common shares                                        275,000       22,636,000         1,837,000
   Acquisition of treasury stock                                   (592,000)              --                --
   Shareholder rights redemption                                   (118,000)              --                --
                                                              -------------    -------------     -------------
     Net cash provided by financing activities                   13,614,000       50,353,000        28,598,000
                                                              -------------    -------------     -------------

NET INCREASE (DECREASE) IN CASH                                 (33,457,000)      35,173,000           538,000

CASH AT BEGINNING OF YEAR                                        36,909,000        1,736,000         1,198,000
                                                              -------------    -------------     -------------

CASH AT END OF YEAR                                           $   3,452,000    $  36,909,000     $   1,736,000
                                                              =============    =============     =============


          See accompanying notes to consolidated financial statements.
</TABLE>
                                      F-8
<PAGE>


      SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:


For the year ended December 31, 1998:
------------------------------------

The Company  issued 43,281  common  shares  valued at $165,000 to the ESOP.  The
Company  also  issued  52,793  common  shares  valued at  $110,000  as  director
compensation which were expensed in 1998.

For the year ended December 31, 1997:
------------------------------------

The Company  issued 10,649  common  shares as director and employee  bonuses and
contributed  24,332 shares to the ESOP. The Company also issued 3,238,930 common
shares, $6.0 million in notes, assumed $19.2 million in debt and net liabilities
and  recorded a $3.1  million  deferred  tax  liability  in  connection  with an
acquisition.

The  Company  issued  2,060,606  warrants to acquire  common  shares to a former
lender in connection with debt which was prepaid in 1997.

For the year ended December 31, 1996:
------------------------------------

The Company  issued  2,000,000  common  shares  totaling  $8.4  million to Amoco
Production Company in connection with an acquisition of oil and gas assets.

The Company  issued 2,447 common shares each to two new  directors.  The Company
also issued 24,220 shares to the ESOP.

The Company received 477,612 shares of National Energy Group,  Inc. common stock
in connection with the sale of the Bayou Sorrel Field.

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

Cash paid during the year ended December 31:

<TABLE>
<CAPTION>
                                                                   1998             1997             1996
                                                                   ----             ----             ----
<S>                                                               <C>                <C>            <C>   

Interest (net of capitalized interest)                        $10,489,000       $ 2,552,000      $ 2,218,000
                                                              ===========       ===========      ===========
                                                              
Income taxes                                                  $        --       $        --      $        -- 
                                                              ===========       ===========      ===========
</TABLE>
                                       F-9


<PAGE>

                                  PANACO, Inc.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

              FOR THE YEARS ENDED DECEMBER 31, 1998, 1997, AND 1996

 
Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
         ------------------------------------------
         

Nature of Business
------------------

The Company is an  independent  oil and natural gas  exploration  and production
company  with  operations  focused in the Gulf of Mexico and onshore in the Gulf
Coast region.  It operates in an  environment  with many financial and operating
risks,  including,  but not  limited  to,  the  ability  to  acquire  additional
economically  recoverable oil and gas reserves, the inherent risks of the search
for,  development  of and production of oil and gas, the ability to sell oil and
gas at  prices  which  will  provide  attractive  rates of  return,  the  highly
competitive  nature of the  industry  and  worldwide  economic  conditions.  The
Company's  ability to expand its reserve base and  diversify  its  operations is
also dependent upon obtaining the necessary capital through operating cash flow,
borrowings or the issuance of additional equity.

Revenue Recognition
-------------------

The Company  recognizes its ownership  interest in oil and gas sales as revenue.
Gas balancing  arrangements with partners in natural gas wells are accounted for
by the entitlements  method. At December 31, 1998 and 1997 both the quantity and
dollar amounts of such arrangements were immaterial.

Hedging Transactions
--------------------

The Company hedges the prices of its oil and gas  production  through the use of
oil and natural  gas hedge and swap  contracts  within the normal  course of its
business.  The Company  uses hedge and swap  contracts  to reduce the effects of
fluctuations  in oil and  natural gas prices (see Note 7). To qualify as hedging
instruments,  these instruments must be highly correlated to anticipated  future
sales such that the Company's  exposure to the risky of commodity  price changes
is reduced.  Changes in the market  value of these  contracts  are  deferred and
subsequent gains and losses are recognized monthly as adjustments to revenues in
the same production  period as the hedged item.  Contracts are placed with major
financial  institutions  that the Company  believes  have  minimal  credit risk.
Contracts that do not or cease to qualify as a hedge are recorded at fair value,
with changes in fair value recognized in income.

Income Taxes
------------

Income taxes are accounted for under the asset and  liability  method.  Deferred
tax assets  and  liabilities  are  recognized  for the  future tax  consequences
attributable to differences  between the financial statement carrying amounts of
existing  assets and  liabilities  and their  respective tax bases and operating
loss and tax credit  carryforwards.  Deferred  tax assets  and  liabilities  are
measured  using  enacted tax rates  expected  to apply to taxable  income in the
years in which those  temporary  differences  are  expected to be  recovered  or
settled.  The effect on deferred tax assets and  liabilities  of a change in tax
rates is recognized in income in the period that includes that enactment date.

Oil and Gas Producing Activities and Depreciation, Depletion and Amortization
-----------------------------------------------------------------------------

The Company utilizes the successful efforts method of accounting for its oil and
gas properties. Under the successful efforts method, lease acquisition costs are
capitalized.   Exploratory   drilling   costs  are  also   capitalized   pending
determination  of proved  reserves.  If proved reserves are not discovered,  the
exploratory   costs  are  expensed.   All  development  costs  are  capitalized.
Non-drilling  exploratory  costs including  geological and geophysical costs and
delay rentals are expensed.  Unproved  leaseholds with  significant  acquisition
costs are assessed periodically,  on a property-by-property basis, and a loss is
recognized  to the  extent,  if any,  that  the  cost of the  property  has been


                                      F-10

<PAGE>

impaired.  Unproved  leaseholds  whose  acquisition  costs are not  individually
significant  are  aggregated,  and  the  portion  of  such  costs  estimated  to
ultimately  prove  nonproductive,  based on  experience,  are amortized  over an
average holding period. As unproved  leaseholds are determined to be productive,
the  related  costs  are  transferred  to  proved   leaseholds.   Provision  for
depreciation  and depletion is  determined on a depletable  unit basis using the
unit-of-production  method.  Estimated future  abandonment costs are recorded by
charges  to  depreciation  and  depletion  expense  over the lives of the proved
reserves of the properties.

The Company performs a review for impairment of proved oil and gas properties on
a depletable  unit basis when  circumstances  suggest there is a need for such a
review.  For each depletable unit determined to be impaired,  an impairment loss
equal to the  difference  between the  carrying  value and the fair value of the
depletable  unit will be recognized.  Fair value, on a depletable unit basis, is
estimated  to be the  present  value of expected  future cash flows  computed by
applying  estimated future oil and gas prices,  as determined by management,  to
estimated  future  production of oil and gas reserves over the economic lives of
the reserves.  Future cash flows are based upon the Company's estimate of proved
reserves. In addition,  other factors such as probable and possible reserves are
taken into  consideration  when  justified by economic  conditions and actual or
planned  drilling.  The Company  recorded an asset  impairment  in 1998 of $20.4
million, primarily due to lower oil and natural gas prices.

Environment Liabilities
-----------------------

Environmental  expenditures  that  relate  to  current  or future  revenues  are
expensed or capitalized as appropriate.  Expenditures that relate to an existing
condition caused by past operations,  and do not contribute to current or future
revenue  generation,  are expensed.  Liabilities are recorded when environmental
assessments  and/or  clean-ups  are  probable,  and the costs can be  reasonably
estimated.  Generally, the timing of these accruals coincides with the Company's
commitment to a formal plan of action.

Capitalized Interest
--------------------

The Company capitalizes interest costs associated with unproved properties under
development.  Interest capitalized in 1998, 1997 and 1996 was $936,000, $513,000
and $0, respectively.

Property, Plant & Equipment
---------------------------

Property and  equipment  are carried at cost.  Oil and natural gas pipelines and
equipment  are  depreciated  on the  straight-line  method over their  estimated
lives,  primarily  fifteen  years.  Other  property is also  depreciated  on the
straight-line  method  over their  estimated  lives,  ranging  from three to ten
years.  Fees for  processing  oil and  natural  gas for others are  treated as a
reduction  of  lease   operating   expense   related  to  the   facilities   and
infrastructure.

Amortization of Deferred Debt Costs
-----------------------------------

Costs incurred in debt financing transactions are amortized over the term of the
debt.

Per Share Amounts
-----------------

The Company's  basic  earnings per share amounts have been computed based on the
average number of common shares  outstanding.  Diluted  weighted  average shares
outstanding  amounts  include  the  effect of the  Company's  outstanding  stock
options and warrants using the treasury  stock method when  dilutive.  Basic and
diluted  earnings per share were the same as reported  prior to adoption of SFAS
No. 128 for all periods presented.


                                      F-11
<PAGE>

Stock Based Compensation
------------------------

The Company  accounts for  stock-based  compensation  under the intrinsic  value
method. Under this method, the Company records no compensation expense for stock
options granted when the exercise price of options granted is equal to or higher
than the fair market value of the Company's  common shares on the date of grant,
see Note 8.

Consolidated Statements of Cash Flows
-------------------------------------

For purposes of reporting cash flows, the Company considers all cash investments
with original maturities of three months or less to be cash equivalents.

Use of Estimates
----------------

The preparation of financial  statements in accordance  with generally  accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets,  liabilities,  revenues and expenses, and
disclosure of contingent  assets and  liabilities  in the financial  statements,
including  the use of  estimates  for oil and gas  reserve  information  and the
valuation  allowance for deferred income taxes. Actual results could differ from
those estimates.  Estimates  related to oil and gas reserve  information and the
standardized measure are based on estimates provided by independent  engineering
firms. Changes in prices could significantly affect these estimates from year to
year.

Reclassification
----------------

Certain  financial  statement  items  have been  reclassified  to conform to the
current year's presentation.

Accounts and Note Receivable
----------------------------

At December 31, 1998 Accounts  receivable are net of an allowance of $1 million.
During 1998 the Company made a loan of $300,000 to an  executive  officer of the
Company  evidenced by a note and secured by a second  mortgage on certain assets
of the  officer.  The note  bears  interest  at 7%,  requires  monthly  interest
payments and matures March, 2002.

Note 2 - ACQUISITIONS AND DISPOSITIONS
         -----------------------------

On May  14,  1998  the  Company  entered  into a  definitive  agreement  with BP
Exploration and Oil, Inc.  ("BP") to acquire BP's 100% working  interest in East
Breaks Blocks 165 and 209 and 75% working interest in High Island Block 587. The
acquisition  was accounted  for using the purchase  method and closed on May 26,
1998. PANACO became the operator of all three blocks effective June 1, 1998. The
Company  acquired  the  properties  for $19.6  million in cash.  Included in the
acquisition  is the  production  platform,  located in 863 feet of water in East
Breaks Block 165. The Company also acquired  31.72 miles of 12"  pipeline,  with
capacity  of over  20,000  barrels  of oil per day,  which  ties the  production
platform to the High Island Pipeline System, the major oil transportation system
in the area.  It also  acquired  9.3 miles of 12 3/4"  pipeline,  which ties the
production   platform  to  the  High  Island  Offshore  System,  the  major  gas
transportation system in the area.

On July 31, 1997, the Company acquired Goldking by merging its corporate parent,
The Union Companies,  Inc.  ("Union") into Goldking  Acquisition  Corp., a newly
formed,  wholly-owned  subsidiary of the Company The individual  shareholders of
Union  received  merger  consideration  consisting  of $7.5 million in cash,  $6
million in notes (which were paid in October 1997) and 3,154,930  Company common
shares, valued at $14 million. The Company assumed the debt of Goldking of $15.9
million and other net  liabilities  of $3.3  million and recorded a $3.1 million
deferred tax  liability  based upon the complete  utilization  of the  Company's
deferred  tax asset  valuation  allowance  and the  requirement  for  additional
deferred tax liabilities resulting from the acquisition.

                                      F-12
<PAGE>

Both of these  acquisitions  were accounted for using the purchase  method.  The
following unaudited pro forma financial  information assumes the BP and Goldking
acquisitions  had been  consummated  January  1, 1997.  The pro forma  financial
information  does not purport to be indicative of the results of the Company had
these  transactions  occurred  on  the  date  assumed,  nor  is  it  necessarily
indicative of the future results of the Company.


                    Unaudited Pro Forma Financial Information
                 For the Years Ended December 31, 1998 and 1997

                                                        1998          1997
                                                        ----          ----
                                                                
Revenues                                            $54,666,000    $59,768,000

Income (loss) before extraordinary item             (46,177,000)     6,419,000

Net income (loss)                                   (46,177,000)     5,485,000

Net income (loss) per share                         $     (1.93)   $      0.24


On October 8, 1996, the Company closed its  acquisition of interests in thirteen
offshore  blocks  comprising  six  fields  in the  Gulf  of  Mexico  from  Amoco
Production  Company.  The  purchase  price  for  the  assets  acquired  in  this
transaction was $40.4 million,  paid by the issuance of 2,000,000 common shares,
valued at $4.20 per share,  and by payment to Amoco of $32 million in cash. This
acquisition  was  accounted for using the purchase  method.  The results for the
Amoco  acquisition  are included in the  Company's  results of  operations  from
October 8, 1996. The results for Goldking are included in the Company's  results
of operations from August 1, 1997.

Effective  September  1,  1996,  the  Company  sold its Bayou  Sorrel  Field for
$11,000,000. This field was purchased in 1995 from Shell Western E & P, Inc. for
$10,500,000.  There  was no  gain  or loss  on the  sale  of the  field  and the
remaining net book value is assigned to an overriding royalty interest retained.
In connection with the Company's  property review during 1998, an impairment was
provided for this property due to the uncertainty regarding the operator's plans
for the Bayou Sorrel Field.

Note 3 - EMPLOYEE STOCK OWNERSHIP PLAN (ESOP) 
         ------------------------------------

In  August  1994  the  Company   established  an  ESOP  and  Trust  that  covers
substantially all employees.  The Board of Directors can approve  contributions,
up to a maximum of 15% of eligible  employees' gross wages. The Company incurred
$275,000,  $165,000 and $122,000 in costs for the years ended December 31, 1998,
1997 and 1996, respectively.

Note 4 - RESTRICTED DEPOSITS
         -------------------

Pursuant to existing agreements the Company is required to deposit funds in bank
trust and escrow  accounts  to  provide a reserve  against  satisfaction  of its
eventual  responsibility  to plug and abandon wells and remove  structures  when
certain  fields no longer  produce oil and gas.  Through  November  30, 1997 the
Company  funded  $900,000 into an escrow  account with respect to the West Delta
Fields. At that time, the Company completed its obligation for the funding under
West Delta  agreement.  The Company has entered  into an escrow  agreement  with
Amoco Production  Company under which the Company deposits,  for the life of the
fields,  in a bank escrow  account ten  percent  (10%) of the net cash flow,  as
defined in the agreement, from the Amoco properties. The Company has established
the "PANACO East Breaks 110 Platform Trust" in favor of the Minerals  Management
Service of the U.S.  Department of the Interior.  This trust required an initial

                                      F-13
<PAGE>


funding of $846,720 in December 1996, and remaining  deposits of $244,320 due at
the end of each  quarter in 1999 and  $144,000 due at the end of each quarter in
2000 for a total of $2.4 million.  In connection  with the BP  Acquisition,  the
Company  deposited  $1.0 million into an escrow  account on July 1, 1998. On the
first day of each quarter thereafter, the Company will deposit $250,000 into the
escrow  account  until the balance in the escrow  account  reaches $6.5 million.

Note 5 - LONG-TERM DEBT
         --------------

                                           1998                        1997
                                           ----                        ----
       
10 5/8 % Senior Notes due 2004(a)      $100,000,000                $100,000,000
Revolving Credit Facility (b)            13,500,000                          --
Production payment(c)                     2,249,000                   1,700,000
                                       ------------                ------------
                                        115,749,000                $101,700,000

Less current portion                     13,500,000                          --
                                       ------------                ------------
    Long-term debt                     $102,249,000                $101,700,000
                                       ============                ============
                                        
 _______
     (a) In October 1997 the Company issued $100 million of 10.625% Senior Notes
due 2004.  Interest is payable  semi-annually April 1 and October 1 of each year
beginning April 1, 1998. The net proceeds of the transaction  were used to repay
or prepay  substantially all of the Company's  outstanding  indebtedness and for
capital  expenditures.  The estimated  fair value of these notes at December 31,
1998 was  $76,000,000  based on quoted market prices.  The notes are the general
unsecured  obligations of the Company and rank senior in right of payment to any
subordinated obligations. The Senior Note indenture contains certain restrictive
convenants that limit the ability of the Company and its  subsidiaries to, among
other things, incur additional indebtedness, pay dividends or make certain other
restricted  payments,   consummate  certain  asset  sales,  enter  into  certain
transactions with affiliates, incur liens, impose restrictions on the ability of
a restricted subsidiary to pay dividends or make certain payments to the Company
and its restrictive subsidiaries,  merge or consolidate with any other person or
sell,  assign,   transfer,   lease,  convey  or  otherwise  dispose  of  all  or
substantially  all of the assets of the  Company.  In  addition,  under  certain
circumstances,  the Company  will be  required  to offer to purchase  the Senior
Notes,  in whole or in part, at a purchase  price equal to 100% of the principal
amount  thereof  plus  accrued  interest  to the  date of  repurchase,  with the
proceeds of certain asset sales.

     (b) In December  1998,  the Company  amended its bank  facility.  See "Bank
Facility." The loan is a reducing revolver designed to provide the Company up to
$75 million  depending on the  Company's  borrowing  base,  as determined by the
lenders. The Company's borrowing base at December 31, 1998 was $45 million, with
availability  under the revolver of $31.5 million.  The principal  amount of the
loan is due  October  22,  2002.  However,  at no  time  may  the  Company  have
outstanding  borrowings  in excess of its  borrowing  base. At April 1, 1999 the
borrowing  base was reduced to $25 million.  The borrowing base is subject to $4
million  reductions  on June 30,  1999  and  September  30,  1999.  The  balance
outstanding under the Bank Facility at April 15, 1999 was $24 million.  Interest
on the loan is computed at the bank's  prime rate or at 1.5 to 2.25%  (depending
upon the  percentage  of the  facility  being used) over the  applicable  London
Interbank  Offered Rate ("LIBOR") on Eurodollar  loans.  Eurodollar loans can be
for terms of one, two,  three or six months and interest on such loans is due at
the  expiration of the terms of such loans,  but no less  frequently  than every
three months.  The Bank Facility is  collateralized  by a first  mortgage on the
Company's offshore properties.

     The loan agreement  contains certain  covenants  including a requirement to
maintain a positive  indebtedness to cash flow ratio, a positive working capital
ratio,  a certain  tangible net worth,  as well as  limitations  on future debt,
guarantees,  liens, dividends, mergers, and sale of assets. At December 31, 1998
the Company was not in compliance  with these  covenants which has been remedied
by waivers  and an  amendment  to the Bank  Facility.  However,  the Company has
classified  this debt as a current  liability  since it is probable  the Company
will fail to meet these  covenants  at  measurement  dates prior to December 31,
1999. The failure to satify these  covenants,  or any of the other  covenants in
the Bank Facility would  constitute an event of default  thereunder and, subject
to grace  periods,  may  permit  the  lenders  to  accelerate  the  indebtedness
oustanding under the Bank Facility and demand immediate payment thereof. In such
event,  the Company  could be required to sell certain oil and gas assets,  sell
equity securities or obtain additional bank financing. No assurance can be given
that such  transactions can be consummated on terms acceptable to the Company or
its lenders,  whose approval may be required. In this situation,  if the Company
is unable to raise the necessary  funds,  the Company could become in default on
the full  amount of its  indebtedness,  which  includes  the Senior  Notes.  The
holders of the Senior Notes have acceleration  rights,  subject to certain grace
periods, if the Company is in default under the Bank Facility.


                                      F-14
<PAGE>

     (c) Represents a production  payment obligation to a former lender which is
paid with a portion of the revenues from certain wells.  The production  payment
is a non-recourse  loan related to the  development of certain wells acquired in
the Goldking Acquisition.  The agreement requires repayment of principal plus an
amount sufficient to provide an internal rate of return of 18%.

Note 6 - EXTRAORDINARY ITEM-LOSS ON EARLY RETIREMENT OF DEBT
         ---------------------------------------------------

In October  1997,  the Company  issued $100 million of 10.625%  Senior Notes due
2004,  see Note 5. A portion of the proceeds from the offering was used to repay
or prepay substantially all of the Company's outstanding indebtedness.  With the
early  retirement  of the debt,  the  Company  incurred  a $  484,000  charge to
write-off  the  deferred  financing  costs  associated  with the  previous  debt
facilities.   In  addition,  as  part  of  the  prepayment  of  the  convertible
subordinated  notes,  the Company  issued  2,060,606  warrants to acquire common
shares  at an  exercise  price of  $4.125  per  share  which  were the  existing
conversion terms of the prepaid notes. The fair value of these warrants has been
estimated by an investment banker to be approximately  $450,000,  which has been
recorded as an extraordinary item and additional paid-in capital.

Note 7 - COMMODITY HEDGE AGREEMENTS
         --------------------------

Starting in 1997 the  Company's  natural gas hedge  transactions  are based upon
published  natural gas pipeline index prices and not the NYMEX.  This change has
significantly reduced price differential risk due to transportation. During 1997
the Company hedged 263,000 barrels of oil and 5.1 Bcf of gas, which  represented
51% and 45%, respectively,  of production, and resulted in a loss on such hedges
of $1,270,000  thereby,  reducing the Company's  average gross margin on oil and
gas by $0.13 per barrel and $0.10 per Mcf, respectively.

During 1998 the Company hedged 463,000 barrels of oil and 12.0 Bcf of gas, which
represented 52% and 67%, respectively,  of production, and resulted in a gain on
such hedges of $2,465,000, thereby increasing the Company's average gross margin
on oil and gas by $2.27 per barrel and $0.02 per Mcf, respectively.

The Company has natural gas hedged in  quantities  ranging  from 7,301 to 37,301
MMbtu per day in each of the months in 1999 for a total of 8,770,000  MMbtu,  at
pipeline prices averaging  approximately $1.99 per MMbtu, for a NYMEX equivalent
of approximately  $2.14 per MMbtu. The Company has hedged 218 MMbtu for each day
in 2000 at an average pipeline index swap price of $1.87. The Company has hedged
223 Bbls of oil for each day in 1999 at an  average  price of $17.27 per Bbl and
232 Bbls of oil for each day in 2000 at an average  price of $17.35 per Bbl.  At
December 31, 1998, the estimated fair market value of the hedge agreements was a
gain of $1.8 million.  At December 31, 1997,  the estimated fair market value of
the hedge agreements in place at that time was a loss of $61,000. The fair value
of the Company's  commodity  hedging  instruments  is the  estimated  amount the
Company  would  receive  or pay  to  settle  the  applicable  commodity  hedging
instrument at the reporting  date,  taking into account the  difference  between
NYMEX prices or index prices at year-end and the contract price of the commodity
hedging  instrument.  Certain of the Company's  commodity  hedging  instruments,
primarily  swaps  and  options,   are  off  balance  sheet   transactions   and,
accordingly,  no respective carrying amounts for these instruments were included
in the  accompanying  consolidated  balance  sheets as of December  31, 1998 and
1997.


                                     F-15
<PAGE>

These hedge  agreements  provide for the  counterparty  to make  payments to the
Company to the extent the market prices (as  determined  in accordance  with the
agreement) are less than the fixed prices for the notional amount hedged and the
Company to make  payments to the  counterparty  to the extent  market prices are
greater than the fixed prices.  The Company accounts for the gains and losses in
oil and natural gas revenue in the month of hedged production.

Note 8 - STOCK OPTIONS AND WARRANTS
         --------------------------

On August 26,  1992,  the  shareholders  approved  a  long-term  incentive  plan
allowing  the  Company  to grant  incentive  and  non-statutory  stock  options,
performance units,  restricted stock awards and stock appreciation rights to key
employees,  directors, and certain consultants and advisors of the Company up to
a maximum of 20% of the total number of shares outstanding.

SFAS No. 123,  "Accounting  for Stock-based  Compensation"  defines a fair value
method of accounting for an employee stock option or similar equity  instrument.
The Company has elected to account  for its stock  options  under the  intrinsic
value method,  whereby, no compensation  expense is recognized for stock options
granted with an exercise  price equal to or greater than the market value of the
Company's  common stock on the date of the grant.  On June 18,  1997,  1,200,000
options at $4.45 per share were issued to certain employees under the provisions
of the Company's long-term incentive plan, which expire June 20, 2000. Ownership
of the stock acquired upon exercise is contractually restricted for a three-year
period from the date of exercise,  except in certain  circumstances as described
in the plan.


                                      F-16
<PAGE>

 
<TABLE>
<CAPTION>
                                                                                                                
                                                1996                        1997                       1998
                                         -------------------        ----------------------     ----------------------
 
                                                    Wtd. Avg.                    Wtd. Avg.                   Wtd. Avg.
                                         Shares     Ex. Price       Shares       Ex. Price      Shares       Ex. Price
                                         ------     ---------       ------       ---------      ------       ---------

<S>                                      <C>           <C>           <C>            <C>         <C>             <C>
Outstanding at beginning of year        289,365      $ 2.21         289,365       $ 2.21      1,190,000        $ 4.45

Granted                                       0          --       1,200,000         4.45              0            --
Exercised                                     0          --        (289,365)        2.21              0            --
Forfeited                                     0          --         (10,000)        4.45        (40,000)         4.45
                                        -------      ------       ---------       ------      ---------        ------
Outstanding at end of year              289,365        2.21       1,190,000         4.45      1,150,000          4.45

                                        -------                   ---------                   ---------
Exercisable at end of year              289,365      $ 2.21       1,190,000       $ 4.45      1,150,000        $ 4.45
Fair value of options granted             N/A                        $ 1.42                       N/A
</TABLE>

The fair value of each option in 1997 was  estimated  at the date of grant using
the  Black-Scholes  Modified  American  Option  Pricing Model with the following
assumptions:
                    Expected option life-years                  3
                    Risk-free interest rate                   6.1%
                    Dividend yield                              0%
                    Volatility                               38.4%

If  compensation  expense for the Company's stock option plans had been recorded
using the Black-Scholes  fair value method and the assumptions  described above,
the Company's net income (loss) and earnings  (loss) per share for 1998 and 1997
would have been as shown below:
                                                    1998                 1997
                                                ------------        ------------
    Net income (loss):           As reported    $(46,851,000)       $   43,000
                                 Pro forma      $(47,133,000)       $ (239,000)

    Earnings (loss) per share    As reported    $      (1.96)       $       --
                                 Pro forma      $      (1.97)       $    (0.01)

Note 9 - MAJOR CUSTOMERS 
         --------------- 

One purchaser  accounted for 42%, 62% and 49% of revenues in 1998, 1997 and 1996
respectively.  These  transactions  represented spot sales of natural gas to one
customer.

Note 10 - INCOME TAXES
          ------------

At December  31, 1998,  the Company had net  operating  loss carry  forwards for
federal income tax purposes of  approximately  $40.6 million which are available
to offset future federal  taxable  income through 2018. The Company's  timing of
its utilization of net operating loss carry forwards may be limited on an annual
basis in the future due to its  issuance  of common  shares and the  purchase of
Goldking common stock.

                                      F-17
<PAGE>

Significant  components of the Company's deferred tax assets (liabilities) as of
December 31 are as follows:
                                                       1998            1997
                                                    ---------       ----------
Deferred tax assets (liabilities)
    Fixed asset basis differences                 $  (388,000)    $(17,200,000)
     Net operating loss carry forwards             14,207,000       14,100,000
     State Taxes                                    1,461,000               --
     Other                                            410,000               --
                                                   ----------       ----------
         Total deferred tax assets (liabilities)   15,690,000       (3,100,000)
                                                   ----------       ----------

Valuation allowance for deferred
     tax assets                                   (15,690,000)              --
                                                   ----------       ----------
         Total deferred tax assets (liabilities)  $        --     $ (3,100,000)
                                                   ==========      ===========
 
At December 31, 1998, the Company determined that it is more likely than not the
deferred  tax  assets  will not be  realized  and the  valuation  allowance  was
increased by $15,690,000.  In connection with the Goldking  Acquisition in 1997,
the  Company  recorded a $3.1  million  deferred  tax  liability  based upon the
complete utilization of the Company's deferred tax asset valuation allowance and
the  requirement  for  additional  deferred tax  liabilities  resulting from the
acquisition.

Total income taxes were different than the amounts computed by appying the
statutory income tax rate to income before income taxes.  The sources of these
differences are as follows:

                                                    1998                1997
                                                   ------              ------

Before any valuation allowance
     Statutory federal income tax rate             (35.00%)           35.00%
     State income taxes, net of federal benefit    ( 2.92%)              --
     Other                                           0.31%               --
     Adjustments to valuation allowance             31.40%           (35.00%)
                                                   -------           ------- 
                                                   ( 6.21%)            0.00%
                                                   =======           =======

Note 11 - COMMITMENTS AND CONTINGENCIES
          -----------------------------

The Company is subject to various  legal  proceedings  and claims which arise in
the ordinary  course of business.  In the opinion of  management,  the amount of
liability, if any, with the respect to these actions would not materially affect
the financial  position of the Company or its results of operation.

The Company has commitments under an operating lease agreement for office space.
At December 31, 1998, the future minimum rental payments due under the lease are
as follows:

                            1999                  $   329,000
                            2000                  $   336,000
                            2001                  $   389,000
                            2002                  $   102,000
                                                  -----------
                            Total                 $ 1,156,000
                                                  ===========


                                      F-18
<PAGE>
                      

Note 12 - SUPPLEMENTAL INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES
          (UNAUDITED)
          -------------------------------------------------------------------- 

The  following  table  reflects  the  costs  incurred  in oil and  gas  property
activities for each of the three years ended December 31:

                                            1998         1997          1996
                                         ----------   ----------    ----------
                                             
Property acquisition costs, proved      $ 9,877,000 $ 39,384,000  $ 26,859,000

Property acquisition costs, unproved      1,245,000    6,026,000     5,390,000

Exploration expenses                      7,582,000      353,000            --

Development costs                        29,957,000   29,276,000     8,863,000


Quantities of Oil and Gas Reserves
----------------------------------

The estimates of proved reserve  quantities at December 31, 1998, are based upon
reports of third party  petroleum  engineers  (Ryder Scott Company,  Netherland,
Sewell & Associates,  Inc., W.D. Von Gonten & Co. and McCune Engineering,  P.E.)
and do not  purport  to  reflect  realizable  values  or fair  market  values of
reserves.  It  should  be  emphasized  that  reserve  estimates  are  inherently
imprecise  and  accordingly,  these  estimates  are expected to change as future
information  becomes  available.  These are  estimates  only and  should  not be
construed as exact amounts. All reserves are located in the United States.

Proved  reserves  are  estimated  reserves  of  natural  gas and  crude  oil and
condensate  that  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 those expected
to be recovered through existing wells, equipment and operating methods.

Proved developed and undeveloped reserves:             Oil              Gas
                                                      (BBLS)           (MCF)
                                                      ------           -----
 Estimated reserves as of December 31, 1995          1,900,000       46,711,000

     Production                                       (276,000)      (6,788,000)
     Extensions and discoveries                             --          972,000
     Sale of minerals in-place                        (805,000)      (3,102,000)
     Purchase of minerals in-place                   1,379,000       16,633,000
     Revisions of previous estimates                    41,000      (12,980,000)
                                                     ---------       ----------
Estimated reserves as of December 31, 1996           2,239,000       41,446,000

     Production                                       (515,000)     (11,468,000)
     Extensions and discoveries                        459,000       20,002,000
     Sale of minerals in-place                         (11,000)        (252,000)
     Purchase of minerals in-place                   2,334,000       23,904,000
                                                     ---------       ----------
Estimated reserves as of December 31, 1997           4,506,000       73,632,000

    Production                                        (895,000)     (18,041,000)
    Extensions and discoveries                          14,000        1,077,000
    Sale of minerals in-place                               --         (272,000)
    Purchase of minerals in-place                    3,735,000       23,479,000
    Revisions of previous estimates                     94,000        1,374,000
                                                     ---------       ----------
Estimated reserves as of December 31, 1998           7,454,000       81,249,000
                                                     =========       ========== 
                                      F-19
<PAGE>

Proved developed reserves:
                                       Oil                 Gas
                                       (BBLS)             (MCF)
                                     ---------          ----------

    December 31, 1995                1,794,000          40,323,000
                                     =========          ==========
                                     

    December 31, 1996                1,867,000          39,288,000
                                     =========          ==========

    December 31, 1997                3,194,000          55,690,000
                                     =========          ==========

    December 31, 1998                5,165,000          50,539,000
                                     =========          ==========





Standardized Measure of Discounted Future Net Cash Flows
--------------------------------------------------------

     Future cash inflows are computed by applying year-end prices of oil and gas
(with  consideration of price changes only to the extent provided by contractual
arrangements) to the year-end  estimated future production of proved oil and gas
reserves.  The prices used for estimates of future revenues at December 31, 1998
were $10.00 per barrel of oil and $2.05 per MMbtu of natural  gas,  adjusted for
transportation,  gravity and Btu content.  Estimates of future  development  and
production costs are based on year-end costs and assume continuation of existing
economic conditions and year-end prices. The estimated future net cash flows are
then  discounted  using a rate of 10 percent per year to reflect  the  estimated
timing of the future cash flows.  The  standardized  measure of discounted  cash
flows is the future net cash flows less the computed discount.

The accompanying  table reflects the standardized  measure of discounted  future
cash flows  relating to proved oil and gas  reserves as of the three years ended
December 31:

<TABLE>
<CAPTION>

                                               1998                  1997                1996
                                          -------------         -------------        -------------
<S>                                             <C>                  <C>                  <C>   
Future cash inflows                       $ 259,071,000         $ 269,141,000        $ 210,875,000
Future development and production costs    (129,744,000)         (102,114,000)         (61,822,000)
                                          -------------         -------------        -------------
Future net cash flows                       129,327,000           167,027,000          149,053,000
Future income taxes                                  --           (10,563,000)         (17,899,000)
                                          -------------         -------------        -------------
Future net cash flows after income taxes    129,327,000           156,464,000          131,154,000
10% annual discount                          34,747,000           (35,592,000)         (31,313,000)
                                          -------------         -------------        -------------
Standardized measure after income taxes   $  94,580,000         $ 120,872,000        $  99,841,000
                                          =============         =============        =============
</TABLE>

Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
The  accompanying  table  reflects  the  principal  changes in the  standardized
measure of discounted  future net cash flows  attributable to proved oil and gas
reserves for each of the three years ended December 31:
<TABLE>
<CAPTION>


                                                   1998               1997                 1996 
                                               ------------       -------------       -------------
<S>                                                <C>                 <C>                 <C> 
   
Beginning balance                              $120,872,000       $  99,841,000       $  62,921,000
Sales of oil and gas, net of production costs   (30,692,000)        (25,815,000)        (11,027,000)
Net change in income taxes                        8,160,000           5,465,000          (4,116,000)
Changes in price and production costs           (42,711,000)        (32,461,000)         44,088,000
Purchases of minerals in-place                   23,657,000          40,027,000          45,521,000
Sale of minerals in-place                          (514,000)                 --         (10,518,000)
Revision of previous estimates, extensions &
   discoveries, net                              15,808,000          33,815,000         (27,028,000)
                                               ------------       -------------       -------------
Ending balance                                 $ 94,580,000       $ 120,872,000       $  99,841,000
                                               ============       =============       =============
</TABLE>


                                      F-20
<PAGE>

                                                                 Exhibit 10.22

            SECOND AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT


     THIS  SECOND  AMENDMENT  TO AMENDED AND  RESTATED  CREDIT  AGREEMENT  (this
"Amendment")  dated as of March 31,  1999 is among:  PANACO,  INC.,  a  Delaware
corporation  (the  "Borrower");  each of the  Lenders  (as defined in the Credit
Agreement  as  hereinafter  defined)  that is a  signatory  hereto;  FIRST UNION
NATIONAL  BANK, a national  banking  association  (in its  individual  capacity,
"First  Union"),  as agent for the Lenders (in such capacity,  together with its
successors  in such  capacity,  the  "Administrative  Agent");  and  PARIBAS  as
Documentation Agent.
                                 R E C I T A L S

     A. The Borrower,  the Administrative Agent, the Documentation Agent and the
Lenders have entered into that  certain  Amended and Restated  Credit  Agreement
dated as of October 9, 1997 as amended by First  Amendment  to Credit  Agreement
dated as of December 11, 1998 (as amended, the "Credit Agreement"),  pursuant to
which the Lenders have agreed to make certain loans and  extensions of credit to
the Borrower upon the terms and conditions as provided  therein.

     B. An Event of Default exists under the Credit Agreement under Section 9.13
as of March 31, 1999.

     C. The Borrower,  the Administrative Agent, the Documentation Agent and the
Lenders now desire to make certain amendments to the Credit Agreement.
        
     NOW,  THEREFORE,  in  consideration  of the  premises  and  other  good and
valuable consideration and the mutual benefits,  covenants and agreements herein
expressed, the parties hereto now agree as follows:

     1. All capitalized  terms used in this Amendment and not otherwise  defined
herein shall have the meanings ascribed to such terms in the Credit Agreement.

     2. The definition "Applicable Margin" is hereby amended to read as follows:

               "Applicable  Margin"  shall  mean for Base  Rate  Loans or LIBOR
     Loans the following rate per annum as applicable:
<PAGE>

-------------------------------------------------------------------------------
 Borrowing Base Utilization        Base Rate Loans          LIBOR Loans
       Percentage
------------------------------------------------------------------------------- 
less than 25%                          0.50%                  1.50%
greater than or equal to 25%           0.50%                  1.75%
but less than 50%
greater than or equal to 50%           0.50%                  2.00%
but less than 75%
equal to or greater than 75%           0.50%                  2.25%
  
     3.  Section  1.02 of the Credit  Agreement  is hereby  supplemented,  where
alphabetically appropriate, with the addition of the following definitions:

     "Second  Amendment" shall mean that certain Second Amendment to Amended and
     Restated  Credit  Agreement  dated as of March 31, 1999 among the Borrower,
     the Lenders,  the Administrative  Agent and the Documentation  Agent.

     4. On the date that this Amendment  becomes  effective  until the Borrowing
Base is redetermined in accordance with the terms of the Credit  Agreement,  the
Borrowing Base shall decrease to $25,000,000, which will automatically reduce by
$4,000,000 on June 30, 1999 and by $4,000,000 on September 30, 1999.

     5.  Section  9.13 of the  Credit  Agreement  is hereby  amended  to read as
follows:

     "Section 9.13 Tangible Net Worth. The Borrower will not permit its Tangible
     Net Worth to be less at the end of any fiscal  quarter than an amount equal
     to 85% of Tangible  Net Worth as March 31, 1999 plus 85% of the  Borrower's
     Net Income (only if positive) for each fiscal quarter of the Borrower after
     December  31,  1998,  plus 75% of the net  proceeds of any new  issuance of
     capital stock or other equity securities of the Borrower issued after March
     31, 1999."

     6. Section 8.01(a) of the Credit  Agreement  requires that Borrower provide
certain audited consolidated financial statements and other financial statements
by no later than 90 days after the end of each fiscal year. The Majority Lenders
hereby  waive,  on a one time basis,  but only until two (2) Business Days after
the  effectiveness  of this Amendment,  any violation of Section 8.01(a) and any
other relevant sections of the Credit Agreement as a result of the late delivery
of the annual  financial  statements  required to be  delivered no later than 90
days after December 31, 1998.

     7. This Amendment  shall become binding on the Lenders when, and only when,
the following  conditions shall have been satisfied and the Administrative Agent
shall have received each of the following, as applicable,  in form and substance
satisfactory to the Administrative Agent or its counsel:
<PAGE>

          (a)  counterparts  of this  Amendment  and the  Ratification  attached
     hereto executed by the Borrower,  the Guarantors and the Lenders;  and

          (b) such other documents as it or its counsel may reasonably request.

     8. The  parties  hereto  hereby  acknowledge  and  agree  that,  except  as
specifically  supplemented and amended,  changed or modified hereby,  the Credit
Agreement shall remain in full force and effect in accordance with its terms.

     9. The Borrower hereby reaffirms that as of the date of this Amendment, the
representations and warranties contained in Article VII of the Credit Agreement,
as amended by this Amendment,  are true and correct on the date hereof as though
made on and as of the date of this Amendment, except as such representations and
warranties are expressly limited to an earlier date.

     10.  THIS  AMENDMENT  (INCLUDING,  BUT NOT  LIMITED  TO, THE  VALIDITY  AND
ENFORCEABILITY  HEREOF) SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE  WITH,
THE LAWS OF THE STATE OF TEXAS, OTHER THAN THE CONFLICT OF LAWS RULES THEREOF.
         
     11. This  Amendment  may be executed  in two or more  counterparts,  and it
shall not be necessary that the signatures of all parties hereto be contained on
any one counterpart  hereof;  each counterpart shall be deemed an original,  but
all of which together shall constitute one and the same instrument.

                          [SIGNATURES BEGIN NEXT PAGE]

<PAGE>
     IN WITNESS  WHEREOF,  the parties  hereto have caused this  Amendment to be
executed as of the date first above written.

BORROWER:                                      PANACO, INC


                                               By:_____________________________
                                               Name:
                                               Title:


LENDER AND ADMINISTRATIVE                      FIRST UNION NATIONAL BANK
AGENT:

                                               By:_____________________________
                                               Name:
                                               Title:


LENDER AND DOCUMENTATION                       PARIBAS
AGENT:


                                               By:_____________________________
                                               Name:
                                               Title:


                                               By:_____________________________
                                               Name:
                                               Title:



<PAGE>

                                  RATIFICATION

     Each of the undersigned (a "Guarantor")  hereby agrees that its liabilities
under  its  respective   Guaranty   Agreement   guaranteeing  the  indebtedness,
obligations  and  liabilities  under that certain  Amended and  Restated  Credit
Agreement dated October 9, 1997, as amended,  shall remain  enforceable  against
such  Guarantor  in  accordance  with the terms of its Guaranty and shall not be
reduced,  altered, limited, lessened or in any way affected by the execution and
delivery of this Second Amendment to Amended and Restated Credit Agreement. Each
Guarantor hereby confirms and ratifies its liabilities under its Guaranty in all
respects.
                                               PANACO PRODUCTION COMPANY

 

                                               By:_____________________________
                                               Name:
                                               Title:



                                               GOLDKING ACQUISITION CORP.



                                               By:_____________________________
                                               Name:
                                               Title:




<PAGE>
                   



                                                                 Exhibit 10.23

                              EMPLOYMENT AGREEMENT


     PANACO,  INC.,  ("Panaco")  hereby  employs  LARRY M.  WRIGHT  (hereinafter
referred to as "Employee")  to be  employed  and serve as  President  and Chief
Executive  Officer,  effective September 1, 1998, on the  following  terms and
conditions:
                                   WITNESSETH

     1. DUTIES. Employee shall perform such services regarding the operations of
Panaco as the Board of Directors may from time to time request.  Employee  shall
at all  times  faithfully,  with  diligence,  and to the  best of his  ability,
experience and talents, perform all the duties that may be required of and from
him pursuant to the terms of this Agreement.  It is expressly  understood  and
agreed that in the performance of his duties and obligations hereunder, Employee
shall at all times be  subject to the  direction and control of the Board of
Directors of Panaco.

     2.  TERM AND RENEWAL.  The initial term of employmentcontemplated by this
Agreement shall commence effective September 1, 1998, and continue for a term
of three (3) years.  Thereafter, this  Agreement  shall automatically renew for
consecutive terms of two (2) years each, upon expiration of the initial term
and each renewal term  hereunder.

     3.  COMPENSATION.  In consideration of the work and other services that
Employee performs for Panaco hereunder, Panaco shall pay Employee the following:

         (a)  BASE SALARY.  During the term hereof, Panaco shall pay Employee
          a gross annual salary of $285,000, payable semi-monthly in accordance
          with the company's normal payroll  policies,  subject to  withholding
          for federal income tax, social  security,  state and local  taxes, if
          any, and any other sums that Panaco may be legally  required to with-
          hold.  Employee will be eligible for all cost of living  adjustments
          that are awarded to Panaco  employees.
          
         (b)  SUPPLEMENTAL SALARY.  In addition to all other compensation
          provided herein,  but only so long as Employee remains indebted to
          Panaco by virtue of that  certain  Promissory  Note (the Note) from
          Employee to Panaco dated November 4, 1998 (the "Note"), Employee
          shall be entitled to the following  supplemental  payments:
               
              (i)  On March 31, 1999, an amount equal to the interest  which
               has accrued on the Note through  February  28,1999;

              (ii)  On the last  calendar  day of each month  thereafter,
               Employee  shall be entitled to a supplemental  payment of an
               amount equal to the interest  which  accrued on the Note during
               the preceding calendar month;
              
              (iii)  At its option, Panaco may apply all supplemental payments
               directly against the interest obligations accruing on the Note.

         (c)  VACATION. Employee shall be entitled to vacation in accordance
          with the vacation policies of Panaco from time to time in effect with
          respect to the executive  employees of Panaco.

         (d)  OTHER BENEFITS. During the term of this Agreement, Employee shall
          be entitled to  participate  in all employee  benefit plans from time
          to time made available to the executives or general employees of
          Panaco.
          
         (e) Insurance. Panaco will provide Employee and Employee's dependant's
          with coverage under a policy of  hospitalization  and major medical
          insurance at no cost to the Employee.  Panaco will provide life
          insurance  coverage and short term and long term disability insurance
          coverage to Employee in an amount to be determined by the company.

     4. EXPENSES.  Panaco shall reimburse Employee for all reasonable  expenses
and disbursements incurred by Employee in connection with Employee's duties
hereunder, including expenses for entertainment and travel, as are  consistent
with the policies and  procedures  of Panaco.

     5.  CONFIDENTIAL INFORMATION.  Employee  acknowledges that in the course
of employment by Panaco, Employee  will  receive  certain  trade  secrets  and
confidential information belonging to the Panaco which Panaco desires to protect
as confidential. For the purposes  of this  Agreement,  the term "confidential
information"  shall mean information  of any nature  and in any form  which at
the time is not  generally known to those persons engaged in business  similar
to that conducted by Panaco.  Employee  agrees  that such  information  is
confidential and that he will not reveal such information to anyone other than
officers, directors and employees of Panaco.  Upon  termination of employment,
for any reason, Employee  shall surrender  to Panaco all papers,  documents and
other  property  of Panaco.

     6.  AGREEMENT NOT TO SOLICIT.  During the initial or renewal term hereof 
and for a period of two years after the  termination  of  employment  hereunder
(the "Termination  Date"),  regardless of how terminated,  Employee will not,
singly, jointly,  or  as a  partner,  member,  contractor,  employee  or  agent
of  any partnership or as an officer, director, employee, agent, contractor,
stockholder or  investor  in  any  other  entity  or in  any  other  capacity,
directly  or indirectly:

         (a)  induce,  or attempt to induce,  any person or party who, on the
          Termination Date is  employed  by or  affiliated  with Panaco or at
          any time during the term of  this  covenant  is,  or may  be,  or
          becomes  an  employee  of or affiliated  with  Panaco,  to  terminate
          his,  her  or its  employment  or affiliation with Panaco;

         (b) induce,  or attempt to induce,  any person,  business or entity
          which is or becomes a customer or supplier of Panaco,  or which
          otherwise is a  contracting party with Panaco,  as of the Termination
          Date, or at any time during the term hereof, to terminate any written
          or oral agreement or understanding with Panaco, or to  interfere  in
          any manner with any  relationship  between  Panaco and such customer
          or  supplier; 

         (c) employ or  otherwise  engage in any capacity any person who at the
          Termination  Date or at any time  during the period two years prior
          thereto was employed, or otherwise engaged, in any capacity by Panaco
          and who, by reason  thereof is or is  reasonably  likely to be in
          possession of any confidential information.

     Employee acknowledges and agrees that the provisions of this paragraph
constitute a material, mutually bargained for portion of the consideration to
be delivered under this  agreement and that it is a condition precedent to the
creation and existence of the obligations of Panaco  hereunder.

     7. TERMINATION OF EMPLOYMENT.

    (a)  TERMINATION OF CAUSE.  Nothing hereunder shall prevent Panaco from
     terminating  Employee's employment for Cause (as hereinafter defined).
     Upon termination for Cause Employee shall receive his base salary only
     through the date of termination, and neither Employee nor any other person
     shall be entitled to any further payments from Panaco under this Agreement.
     Any rights and benefits  Employee  may have under  employee  benefit plans
     and programs of Panaco by reason of or after his  termination  shall be
     determined in accordance with the terms of such  plans and  programs. For
     purposes  of this  Agreement, Termination for Cause shall mean:

              (i) termination  due to continued  neglect of duties for which
          Employee is employed  after receipt of written  notice thereof from
          the Board of Directors of Panaco;

              (ii) termination due to conduct involving moral  turpitude in the
          performance  of duties for which  Employee is employed, including,
          without  limitation,  the commission of fraud,  misappropriation  or
          embezzlement by Employee; or

              (iii)  termination due to conduct which, if not in connection 
          with the performance of Employee's duties hereunder, would result in
          serious prejudice to the interests of Panaco if he were retained as
          an employee.

    (b)  DEATH, DISABILITY AND TERMINATION OTHER THAN FOR CAUSE.  Notwithstand-
     ing any other term or provision  of this Agreement,  Panaco may  terminate
     Employee's employment  at any time,  during any  initial or renewal  term
     hereof, for any reason it deems appropriate or for no reason. If Employee's
     employment hereunder is terminated for any reason other than Cause in
     accordance with paragraph 7(a), or if Employee  dies or becomes  disabled
     (meaning  that  employee is unable to perform his duties prescribed by
     section 1 of this Agreement for a period of 180 consecutive  days),  then
     Employee  shall be  entitled  to  payment of his base salary,  at the rate
     in effect at the time of such termination (i) for a period of 24 months, if
     such termination occurs after September 1, 1999, (ii) or for a period equal
     to the remainder of the initial term of this Agreement (August 31, 2001),
     if such termination  occurs before September 1, 1999. Any rights and
     benefits  Employee may have under employee  benefit plans and programs of
     Panaco by reason of or after his termination shall be determined in
     accordance with the terms of such plans and  programs.

    (c)  VOLUNTARY TERMINATION.  Employee  may terminate his employment at any
     time upon ninety (90) days' prior written notice to Panaco;  provided,
     however,  that Panaco, in its discretion,  may cause such termination to be
     effective at any time during that ninety (90) day period.  In the event of
     such a  voluntary  termination of employment, Employee will be entitled to
     receive only his base salary through the ninety (90) day period.  Neither
     Employee nor any other person shall be entitled to any further payments
     from Panaco under this Agreement upon a voluntary termination by Employee
     of his employment  hereunder, and any  rights  and  benefits Employee may
     have under employee  benefit plans and  programs of Panaco  by  reason of
     or after his termination shall be determined in accordance with the terms
     of such plans and programs.

    (d) VOLUNTARY TERMINATION FOR "GOOD REASON."  Notwithstanding any other
     term or provision of this  Agreement, if Employee  voluntarily  terminates
     his employment  for Good Reason (as  hereinafter  defined), then Employee
     shall be entitled  to  payment of his base  salary,  at the rate in effect
     at the time of such termination (i) for a period of 24 months, if such
     termination occurs after September 1, 1999, (ii) or for a period  equal to
     the remainder of the initial term of this Agreement  (August 31, 2001), if
     such termination occurs before September 1, 1999.  Any rights and benefits
     Employee  may have under  employee benefit plans and programs of Panaco by
     reason of or after his termination shall be  determined in accordance with
     the terms of such plans and programs.  "Good Reason" shall mean any of the
     following (without Executive's  express  written consent):

              (i)  Employee's Base Salary is set at an amount less than  90
          percent of  the  greater  of (a)  his  annual  salary  in  effect on
          September 1, 1998, or (b) his annual  salary in effect  during  the
          preceding calendar year,  and Employee  resigns within ninety days
          after he is notified of the  decision  to  modify  his Base Salary.

              (ii)  A substantial  and  material alteration  in the  nature or
          status of  Employee's  responsibilities, or the assignment of duties
          inconsistent with Employee's duties and  responsibilities;

              (iii)  Employee's line of report is changed so that he is
          required to report to anyone  other than the  Executive  Committee or
          the Board of  Directors;

              (iv)  A change in  Employee's  titles or  Panaco's employing a
          co-President or Chief Executive Officer;

              (v)  Employee is not elected as a director of Panaco;

              (vi)  Any  material breach by  Panaco  of any  provision  of this
          Agreement if such material  breach has not been cured within thirty
          (30) days following  written notice of such breach by Employee to the
          Executive  Committee setting forth with reasonable specificity the
          nature of the breach.

     8.  CONTINGENT IMMEDIATE VESTING OF OPTIONS.  Employee  will be entitled
to the  immediate  full  vesting of any existing options outstanding if his
employment is terminated prior to the end of the  term of this  Agreement due
to one or more of the  following  events:

          (a)  Employee's   employment  is  terminated  other  than for Cause;
          
          (b)  Employee voluntarily terminates his employment for Good Reason;

          (c)  Employee becomes disabled; or

          (d) Employee  dies.

     9.  OFFSET.  Upon termination of  Employee's employment with Panaco, for
whatever reason,  Panaco shall be entitled to offset from any amounts owing to
Employee  under this  Agreement,  any  principal and accrued  unpaid  interest
owing under the Note or any renewals,  extensions, or modifications thereof.

     10. NOTICES.  All notices or other communications pursuant to this contract
may be given by personal delivery, or by certified  mail, addressed to the home
office of Panaco or to the last known address of Employee.  Notices given by
personal  delivery  shall  be  deemed  given  at the time of delivery, and
notices  sent by  certified  mail shall be deemed given when deposited with the
U.S. Post Office.

     11. ENTIRETY OF AGREEMENT.  This Agreement contains the entire understand-
ing of the parties and all of the covenants and agreements  between the parties
with respect to the  employment.

     12.  GOVERNING LAW.  This Agreement shall be construed and enforced in
accordance with, and be governed by, the laws of the State of Texas.

     13. WAIVER.  The failure of either party to enforce any rights hereunder
shall not be deemed to be a waiver of such rights, unless such waiver is an
express written waiver which has been signed by the  waiving party.  Waiver of
one  breach  shall not be deemed a waiver of any other breach of the same or
any other provision  hereof.

     14.  ASSIGNMENT.  This Agreement  shall  not be  assignable  by  Employee.
In the event of a future disposition of the  properties and business of Panaco
by merger, consolidation, sale of assets, or otherwise, then Panaco may assign
this Agreement and all of its rights and  obligations to the acquiring or
surviving entity; provided that any such entity shall assume all of the
obligations  of Panaco  hereunder.

     15.  ARBITRATION.  Any dispute, controversy or claim arising out of or
relating to this Agreement shall be submitted to and finally settled by binding
arbitration to be held in  Houston, Texas, in accordance with the rules of the
American Arbitration Association in effect on the date of this  Agreement, and
judgment upon the award rendered by the arbitrator(s) may be entered in any
court having jurisdiction thereof.  All agreements contemplated herein to be
entered into to which the parties hereto are parties shall contain provisions
which provide that all claims, actions or disputes  pursuant to, or related to,
such agreements shall be  submitted  to  binding  arbitration.  Employer agrees
to pay all fees charged by the American Arbitration Association  in  connection
with any arbitration.



DATED this ------- day of --------, 1999

PANACO, INC.                                       EMPLOYEE



By: ---------------------------------              -------------------------- 
    A member of its Executive Committee

<PAGE>