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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, 1999

           [   ] 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 of                 (I.R.S. Employer
       incorporation or organization)                Identification Number)

       1100 Louisiana, Suite 5100
       Houston, TX 77002 77002-5220                       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. [ X ]

The  aggregate  market value of the voting stock held by  non-affiliates  of the
registrant was approximately $11,933,777 as of March 20, 2000.

         24,323,521  shares of the registrant's  Common Stock were outstanding
         as of March 20, 2000.

                      Documents Incorporated by Reference

     Portions of the registrant's annual proxy statement, to be filed within 120
days after December 31, 1999, are incorporated by reference into Part III.

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<PAGE>


                                  PANACO, Inc.

                           Annual Report on Form 10-K
                   For the Fiscal Year Ended December 31, 1999



                                Table of Contents

<TABLE>
<CAPTION>



                                                                     Page Number
<S>                                                                     <C>
Part I

  Item 1.     Business                                                    2
  Item 2.     Properties                                                 15
  Item 3.     Legal Proceedings                                          20
  Item 4.     Submission of Matters to a Vote of Security Holders        20

Part II

  Item 5.     Market for Registrant's Common Equity and
              Related Stockholder Matters                                20
  Item 6.     Selected Financial Data                                    24
  Item 7.     Management's Discussion and Analysis of Financial
              Condition and Results of Operations                        24
  Item 7a.    Qualitative and Quantitative Disclosures
              About Market Risks                                         29
  Item 8.     Financial Statements and Supplementary Data                30
  Item 9.     Changes in and Disagreements with Accountants on
              Accounting and Financial Disclosure                        30

Part III

  Item 10.    Directors and Executive Officers of the Registrant         30
  Item 11.    Executive Compensation                                     30
  Item 12.    Security Ownership of Certain Beneficial Owners and
              Management                                                 30
  Item 13.    Certain Relationships and Related Transactions             30

Part IV

  Item 14.    Exhibits, Financial Statement Schedules and Reports
              On Form 8-K                                                31

Glossary of Selected Oil and Gas Terms                                   33

Signatures                                                               36

</TABLE>






                                       1

<PAGE>

                                     PART 1

Item 1. Business.

     With the exception of historical information, the matters discussed in this
Form 10-K contain forward-looking  statements. The forward-looking statements we
make, not only in this Form 10-K, but also in press  releases,  oral  statements
and other  reports  that we file with the  Securities  and  Exchange  Commission
("SEC") are intended to be subject to the safe harbor  provisions of the Private
Securities  Litigation  Reform Act of 1995.  These  statements  relate to future
results of operations,  the ability to satisfy future capital requirements,  the
growth  of  our  Company  and  other   matters.   You  are  cautioned  that  all
forward-looking   statements   involve  risks  and   uncertainties.   The  words
"estimate," "anticipate," "expect," "predict," "believe" and similar expressions
are intended to qualify these  forward-looking  statements.  We believe that the
forward-looking  statements  that we make are based on reasonable  expectations.
However,  due to the nature of the business we are in and other factors,  we can
not assure you that the actual results of our Company will not differ from those
expectations.

     Unless  otherwise  specified,  all  references  we make to  "PANACO" or the
"Company" include PANACO, Inc. and the predecessor company, PAN Petroleum,  MLP.
Through December 31, 1999 we had two  subsidiaries,  Goldking  Acquisition Corp.
and PANACO Production Company. On December 31, 1999 we merged these into PANACO,
Inc.  and our  references  to PANACO  may  include  these  former  subsidiaries.
Capitalized  terms in this Form 10-K are defined in a glossary,  which begins on
Page 33. Our corporate  headquarters are located at 1100 Louisiana Street, Suite
5100,  Houston,  Texas 77002. Our telephone number is (713) 970-3100 and our fax
number is (713) 970-3151.  You can also visit our website, which can be found at
www.panaco.com.

     The  predecessor of PANACO was formed in 1984 as a consolidator  of oil and
gas  partnerships.  From  1984  through  1988 a total of 114  partnerships  were
acquired and merged into our  predecessor,  which became PAN  Petroleum,  MLP in
1987. In 1991, we formed PANACO, Inc. as a Delaware Corporation and acquired PAN
Petroleum,  MLP in 1992.  At that time,  we began  focusing our resources on the
Gulf of Mexico and the states surroundings the Gulf, which we collectively refer
to as the Gulf Coast  Region.  We  acquired  our first  property  in the Gulf of
Mexico in 1991, and since that time, have acquired other  properties in the Gulf
Coast Region and Gulf of Mexico in every year since 1994. We have grown not only
through  acquisitions in each of those years but also by further  developing the
properties we have acquired. We acquired those properties from companies such as
Conoco, Texaco, Arco, Oxy and BP Exploration & Oil, Inc. (now BP Amoco). We also
acquired  the  common  stock and the oil and gas  properties  from the  Goldking
Companies  in 1997.  We are in the  business  of  selling  oil and  natural  gas
produced  on  properties  we lease to third  party  purchasers.  We  obtain  the
reserves  of crude oil and  natural  gas by a  combination  of buying  them from
others,  drilling  developmental  wells  on  acquired  properties  and  drilling
exploratory wells in new locations.

Business Strategy

     Our strategy is to systematically grow reserves,  production, cash flow and
earnings through a program focused on the Gulf Coast Region. Some of the ways we
do this are:  (i)  strategic  acquisitions  and  mergers,  (ii)  exploiting  and
developing acquired properties,  (iii) marketing of existing  infrastructure and
(iv)  a  selective  exploration  program.  As  a  result  of  previous  property
acquisitions from BP, Amoco,  Goldking and others, which are described below, we
have  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

     In  implementing  our strategy,  we focus our  acquisition  efforts on Gulf
Coast Region  properties that have an inventory of development and  exploitation
projects, significant operating control,  infrastructure value and opportunities
for cost reduction. The properties we seek to acquire are generally geologically
complex with multiple reservoirs, have an established production history and are
candidates for exploitation and further exploration. 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,  we  identify  properties  that may be  acquired,  preferably  through

                                       2

<PAGE>

negotiated transactions or, where appropriate,  sealed bid transactions. Once we
acquire these  properties we focus on reducing  operating costs and implementing
production  enhancements  through the  application of  technologically  advanced
production and recompletion techniques.

     In the future, we may acquire more oil and natural gas assets or ownerships
in other assets that we believe will provide  value to our  investors.  In doing
so, there are inherent risks  associated  with the oil and natural gas industry.
The success of our  acquisitions  will  depend on our  ability to  estimate  the
quantity of oil and natural gas reserves  using all of the data  available to us
at the time.  The  success  of these  acquisitions  will also  depend on how the
actual results of the  properties  compare to the results that we projected when
the acquisition was evaluated.

     While we tend to focus on acquisitions of properties from large  integrated
oil   companies,   we  evaluate  a  broad  range  of   acquisition   and  merger
opportunities.  PANACO is  comprised  of a staff with  technical  experience  in
evaluating,  identifying,  exploiting  and  exploration  on  Gulf  Coast  Region
properties. Also, we believe that we are regarded in the industry as a competent
buyer with the proven ability to close transactions in a timely manner. Based on
these  factors,  we are usually asked to bid on significant  producing  property
sales  in the  Gulf  Coast  Region.  Below  are  highlights  of some of our more
significant acquisitions.

Price Lake Field

     We acquired  the Price Lake Field in April 1998 as a potential  development
field in addition to exploration  prospects which had been identified  using new
3-D Seismic data. The Field had previously  produced 26.7 Bcf of natural gas and
913,000 barrels of oil from shallower reservoirs.  As operator, we evaluated the
3-D Seismic data,  identified  potential drilling locations and brought partners
into the prospect. We spudded the first well in January 1999 and reached a depth
of 16,467 in May 1999.  This well, the Sturlese Estate #1, was successful in the
exploratory zones of the prospect and encountered 144' of producing formation in
the MA-22 and MA-24 sands.  This well began production in September 1999 once we
completed  production  facilities.  We own  56.25% of this well until it reaches
payout,  after  which we will own 51.2% and we will own 51.2% of the  subsequent
wells in this Field.  The second well in the Field,  the Sturlese #3 was spudded
in November 1999, and was completed as a successful  developmental well in March
2000. The Sturlese #3 was drilled to a total depth of 17,000' and encountered an
estimated 98' of productive sand in two zones.

BP Acquisition

     In May 1998 we acquired  100% of East Breaks  Blocks 165 and 209 and 75% of
High Island Block 587 from BP Exploration and Oil, Inc., now BP Amoco ("BP"). We
entered  into a  purchase  and sale  agreement  with BP on May 14 and closed the
acquisition  on May 26. We paid  $19.6  million  in cash and  accounted  for the
acquisition as a purchase.  In addition to the leases acquired, we also received
3-D  Seismic  data which  covers 20  offshore  blocks.  We became  the  operator
effective June 1, 1998.

     The central  production  platform  for all three  blocks is located in East
Breaks 165. This  platform is nicknamed  "Snapper" and is located in 863 feet of
water.  Also  included in the  acquisition  was 31.72 miles of 12" oil pipeline,
with capacity of over 20,000  barrels of oil per day. This oil pipeline ties our
production  platform to the High Island Pipeline System,  which is the major oil
transportation  system in that area.  We also  acquired a 9.3 mile,  12 3/4" gas
pipeline,  which  connects to the High  Island  Offshore  System,  the major gas
transportation  system in the area.  We currently  receive  payments  from other
lease  operators  in the area  for  their  use of our  platform  and  processing
facilities,  which  reduces  our  operating  expenses  in  this  Field.  We have
completed some  development on the Field since it was acquired,  and continue to
evaluate the 3-D Seismic data for further development.

Goldking Acquisition

     On July 31, 1997, we acquired the Goldking Companies,  Inc. ("Goldking") by
purchasing all of the common stock of its parent  Company,  a privately held oil
and natural gas company.  The Goldking acquisition included not only oil and gas
reserves,  but  also  a  portfolio  of  exploration   prospects,   an  extensive
development  program and a  technical  staff  experienced  in Gulf Coast oil and

                                       3

<PAGE>

natural gas operations. Goldking was held as a subsidiary of PANACO, Inc., which
was named  PANACO  Production  Company.  On  December  31,  1999 we  merged  the
subsidiary  into  PANACO,  Inc.  The largest oil and gas lease we acquired  from
Goldking was the  Umbrella  Point Field,  which we have  successfully  developed
since the  acquisition.  In January 1998 we completed a developmental  well that
began  production  in February  1998,  the State Lease  #74-10  well.  This well
produced  as much as 27 MMcf of natural gas and 260  barrels of  condensate  per
day.  In  December  1999,  we  completed a workover on this well and brought its
production  back up to 19 MMcf of natural gas and 176 barrels of condensate  per
day. We recently completed another successful  development well in this Field in
January  2000.  The State tract #87-12 was spud on December 25, 1999 and drilled
to a total depth of 12,000'.  The well  reached  total depth in January 2000 and
encountered 85' of net productive  intervals in four different  zones.  The well
flowed 10,100 Mcf and 337 barrels of condensate  during a 24 hour test and has a
calculated open flow rate of 38,100 Mcf per day.

Amoco Acquisition

     In October 1996 we acquired  interests  in six  offshore  fields from Amoco
Production  Company,  now BP Amoco. We paid Amoco $32 million in cash and issued
them 2 million  shares  of common  stock in  consideration  for the  properties.
Following is a summary of the interests acquired:
<TABLE>
<CAPTION>

                                                          Net Reserves at 12/31/99
                                                   ---------------------------------------
                                         Working                              Pretax PV-10
    Field                  Blocks        Interest  Oil (Mbbls)   Gas (Bcf)    ($ Millions)
    -----                  ------        --------  -----------   ---------    ------------
<S>                          <C>             <C>        <C>        <C>            <C>


East Breaks 160           160/161           33%        995          9.5          $ 24.9
West Cameron 180            144           12.5%         11          2.4             3.5
High Island 309           309/310           50%          4          3.7             2.4
High Island 474       474/475/489/499       12%        100          0.3             1.1
High Island 330           330/349           12%         --          0.3            (0.3)
High Island 302             302             33%         --           --            (0.3)

</TABLE>

     All of the properties we acquired from Amoco are operated by third parties,
which are Unocal,  Texaco,  Coastal  Oil and Gas and  Newfield  Exploration.  We
acquired an additional 25% interest in West Cameron 144 in 1998.

Zapata Acquisition

     In  July  1995,  we  acquired  all of  Zapata  Corp.'s  remaining  offshore
properties.  The net purchase  price was $2.8 million in cash and was  effective
October 1, 1994. The purchase price also included a production payment to Zapata
and a platform  revenue  sharing  agreement,  both of which  related to the East
Breaks 109 Field.  In January  2000,  we  acquired  the  production  payment and
revenue sharing  agreement for $1.4 million in cash and a 1% overriding  royalty
on East  Breaks  109/110.  In late 1998 we  acquired  new 3-D  Seismic  covering
several blocks in the East Breaks area, including blocks 109 and 110. Based on a
review of this new seismic data, we have identified  several  developmental  and
exploratory  drilling  locations  on blocks 109 and 110 and we have  allocated a
relatively  significant part of our 2000 capital budget to developmental work on
these blocks.

Exploitation and Development of Acquired Properties

     Primarily  through these  acquisitions,  we have  developed an inventory of
exploitation  projects  including  development  drilling,  workovers,  sidetrack
drilling,  recompletions  and artificial lift  enhancements.  As of December 31,
1999, 40% of our total Pretax PV-10 relates to Proved Undeveloped  Reserves.  We
use advanced technologies where appropriate in development activities to convert
Proved Behind Pipe and 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  utilizing our existing  platform and pipeline
infrastructure, which improve project economics.

                                       4

<PAGE>


Marketing of Existing Infrastructure

     A key  element  of  each  acquisition  we have  made  has  been  production
infrastructure.  While we focus  primarily on oil and natural gas  reserves,  we
view platforms,  pipelines and related facilities as an often-overlooked  source
of additional revenues.  We own interests in 23 offshore platforms and 109 miles
of offshore oil and natural gas pipelines with  diameters of 10" or greater.  We
market the use of this  infrastructure  to other lease  operators as a source of
additional revenue to us and as a way for other lease operators to produce their
hydrocarbons  in a more  economical  fashion.  We currently have facility use or
processing  agreements in the West Delta Fields,  the Umbrella Point Field,  the
East Cameron 359 Field,  the East Breaks 109 Fields,  the East Breaks 160 Fields
and the East Breaks 165 Fields.  Our major focus of marketing  these  facilities
has been in the East  Breaks  area.  We own 100% of the  platforms  and  related
pipelines  in the East  Breaks  109 and East  Breaks  165  Fields and 33% of the
platforms and pipelines in the East Breaks 160 Fields.  These existing platforms
are three of the  furthest  from the coast line in the Gulf of Mexico and are in
700' to 900' of water and replacement  costs for these  facilities are in excess
of  $100  million.  These  existing  platforms  can  significantly  improve  the
economics  of  operating  an adjacent  oil and gas lease and in return lower our
costs of  operating  this  infrastructure.  We currently  receive  approximately
$175,000  per month from other  lease  operators  in the East Breaks area alone,
which we account for as a reduction of lease operating expense.

Selective Exploration Program

     During 1996 we began to increase  our exposure to  exploration  projects by
allocating more resources to and reviewing more of these projects.  This process
continued  with  the  Goldking  acquisition  in  1997.  Goldking  increased  our
inventory of exploratory projects and the technical staff of PANACO. In 1998 and
1999 we allocated 10% to 20% of our capital budget on exploratory  projects.  We
believe a balanced  capital  budget  includes the higher  reward and higher risk
exploratory projects along with the lower risk developmental projects.

     The  increased  technical  staff has helped us by  increasing  exposure  to
third-party  projects and, more importantly,  by generating more projects on the
properties  we already own. New 3-D Seismic  data and our  technical  staff have
generated several exploration prospects, most recently the successful Price Lake
wells and Umbrella Point wells. Our exploratory inventory is unique in that many
of the exploration  prospects can be reached in conjunction  with  developmental
wells,   which  reduces  the  risk  by  providing  "bail  outs"  in  lower  risk
developmental reserves.

Geographic Focus

     Our  reserve  base is focused  primarily  in the Gulf Coast  Region,  which
includes the Gulf of Mexico.  The Gulf of Mexico has historically  been the most
prolific  basin in North  America  and  currently  accounts  for over 35% of the
natural gas  produced 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,  we have focused our efforts in this  region.  We believe we have
the technical  expertise and  infrastructure  in place to take  advantage of the
inherent  benefits  of the  Gulf  Coast  Region.  Also,  as the  integrated  oil
companies  move  to  deeper  water,  we  believe  we  will  continue  to be well
positioned  to use our  expertise  to acquire  and  exploit  Gulf  Coast  Region
properties.

Inventory of Exploitation and Development Projects

     We have identified  development  drilling  locations and  recompletion  and
workover opportunities. We believe that the majority of these opportunities have
a moderate risk profile and could add incremental  reserves and  production.  In
addition  to  these  identified  opportunities,  with  the  use of  3-D  Seismic
technology,   additional  opportunities  continue  to  be  found  in  the  known
reservoirs as well as deeper undrilled horizons. For example, new 3-D Seismic on
the West Delta  Fields,  which were  acquired in 1991,  has  identified  further
development potential, which led to a new well completed in January 2000.

Significant Operating Control

     We operate 78% of our  properties  as measured by Pretax PV-10  value.  The
operator of an oil and natural gas  property  supervises  production,  maintains
production  records,  employs  field  personnel,  and performs  other  functions

                                       5

<PAGE>

required in the production and  administration  of such property.  This level of
operating control benefits us in numerous ways by enabling us 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, our geographic focus allows us to operate a large
value asset base with  relatively few  employees,  thereby  decreasing  overhead
relative to other offshore lease operators.

Well Operations

     We  operate  64  productive  offshore  wells  and  own  all of the  working
interests in a majority of those wells.  Our 50  remaining  productive  offshore
wells are  operated  by third party  operators,  including  Unocal  Corporation,
Coastal  Oil & Gas  Corp.,  Newfield  Exploration,  Texaco,  Anadarko  Petroleum
Corporation and Burlington. We also operate 25 productive onshore wells in which
we own a majority or all of the working  interest.  In addition,  we own working
interests in two productive  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 we  acquired  our  interest in these
properties.  We  consider  these  joint  operating  agreements  to be  on  terms
customary within the industry.  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

     We utilize our capital budget for (a) the acquisition of interests in other
producing  properties,  (b)  recompletions  of our 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
larger fields that fit their criteria.  Present day technology  permits drilling
and completing wells in water in excess of 10,000 feet.

     We believe that our 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 we drill will vary from  period to period  depending  upon the
amount of the capital budget available for drilling,  the cost of each well, our
commitment to participate  in the wells drilled on properties  operated by third
parties,  the size of the fractional working interest acquired 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 greater.

Use of 3-D Seismic Technology

     The use of 3-D Seismic and computer-aided  exploration  ("CAEX") technology
is an integral component of our acquisition, exploitation, drilling and business
strategy. In general, 3-D Seismic is the process of obtaining continuous seismic
data within a large  geographic area,  rather than as individual,  widely spaced
lines. 3-D Seismic differs from 2-D Seismic in that it provides information as a
seamless  volume,  or  "cube"  of data  instead  of  information  along a single
vertical  line  or  numerous  separate  vertical  lines  across  the  geological
formations of interest.

     By integrating  well log and  production  data from existing wells with the
structural and  stratigraphic  details of a continuous 3-D Seismic  volume,  our
Geoscience  team  obtains  a  greater  understanding  and  clearer  image of the
formations of interest.  While it is  impossible  to predict with  certainty the
exact structural  configuration  or lithological  composition of any underground
geological  formation,  3-D Seismic  provides a mechanism by which more accurate
and detailed  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 smaller companies such as ours. Prior to that, it was the exclusive
province  of  large  multinational  oil  companies.   We  own  our  own  seismic
interpretation  workstations  and data  processing  equipment  and  utilize  the
services of outside firms to process and interpret seismic data.

     With the BP  Acquisition,  we acquired 129 square miles of 3-D Seismic.  We
have used the seismic for workover  and  recompletion  activity to date,  and we
plan further development on the fields acquired with this seismic data.

Marketing of Production

     We sell the  Production  from our  properties in  accordance  with industry
practices,  which  include the sale of oil and  natural  gas at the  wellhead to
third parties.  We sell both at prices based on factors  normally  considered in
the  industry,  such as index price for natural gas or the posted price for oil,
price premiums or bonuses with adjustments for transportation and the quality of
the oil and natural gas.

     We market all of our offshore oil  production to Plains  Resources,  Amoco,
Oxy, Conoco, Texaco, Unocal and Vastar. Oxy, Conoco, Texaco and Vastar each have
a 25% call  (exclusive  right 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 our  properties  acquired  from  Amoco at their
posted  prices.  If we have 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 our  choice.
Plains  Resources  purchases the oil production  from the Umbrella Point Fields,
the East  Breaks 165  Fields,  the Price  Lake Field and on some of our  smaller
fields  that  produce  oil.  Plains  Resources  accounted  for 37% of our  total
revenues  in 1999.  Natural  gas is  generally  sold on the spot market or under
short-term  contracts  of  one  year  or  less.  There  are  numerous  potential
purchasers  for natural  gas.  Notwithstanding  this,  natural gas  purchased by
Columbia Energy Services  Corporation  (now Enron North America Corp.) accounted
for 39% of our total revenues in 1999. There are numerous natural gas purchasers
doing  business  in the areas that we operate in as well as natural  gas brokers
and  clearinghouses.  Furthermore,  we can  contract  to sell  the  natural  gas
directly to  end-users.  We do not believe  that we are  dependent  upon any one
customer or group of customers for the purchase of natural gas.

Plugging and Abandonment

     All of our reserve  values include the estimated  future  liability to plug
and abandon ("P&A") all of the wells, platforms and pipelines in accordance with
guidelines established by regulatory authorities.  These costs vary according to
the  location  of the lease,  depth of water,  number of wells,  etc.  The total
estimated  future  abandonment  costs  for all of our  properties  is  over  $21
million.  The Minerals Management Service of the U.S. Department of the Interior
("MMS")  requires  operators of offshore  platforms  to provide  evidence of the
ability to satisfy  these  future  obligations.  The  companies  that we acquire
properties from may also require evidence of our ability to satisfy these future
obligations.  Our preferred  method of providing  evidence to these parties is a
combination of escrow  accounts and surety bonds.  Following is a description of
the methods by which we have accomplished these objectives.

West Delta Fields

     The former owner of these Fields requires a $4.1 million surety bond, based
on their  estimate of the P&A Liability of the Fields.  As security for the $4.1
million bond, we have provided a cash escrow  account to the  underwriter of the
bond.  The balance of this escrow account was $1.1 million at December 31, 1999,
and was fully funded in November 1997 in accordance with the terms of the escrow
agreement. We also provide the MMS a $50,000 surety bond for the plugging of two
wells in federal blocks of these Fields.

East Breaks 165 Fields

     We  provide  the MMS  with a $10.9  million  surety  bond  based  on  their
estimated P&A Liability for these  Fields.  As security for the  underwriter  of
this bond we have established a cash escrow account.  The balance in this escrow

                                       7

<PAGE>

account  totaled  $2.3  million at  December  31,  1999 and  requires  quarterly
deposits  of  $250,000  until the  balance in the escrow  account  reaches  $6.5
million.  The underwriter  also provides the former owner of these Fields with a
$6.5 million  security  bond based on the same escrow  account used for the bond
provided to the MMS.

East Breaks 109 Fields

     We provide the MMS with a $5.8  million  surety bond for these  Fields.  As
security for the  underwriter  of these  bonds,  we have  established  an escrow
account,  the balance of which was $1.8 million at December 31, 1999. The escrow
agreement  requires  quarterly  deposits  of  $250,000  until the balance of the
account reaches $5.4 million.

Amoco Properties

     The  properties  we acquired  from Amoco in 1996 are all  operated by third
parties and as such, the MMS does not require  non-operators to provide evidence
of the ability to P&A the properties. However, Amoco Production Company requires
us to fund an escrow  account to  provide  them with this  evidence.  The escrow
agreement requires that we deposit 10% of the cash flows from the Fields, net of
capital  expenditures  for their lives. At December 31, 1999 the balance in this
escrow account was $315,000.

     We provide much smaller bonds on various  locations  for similar  purposes,
the amounts of which are not significant. All of these agreements provide for us
to receive the escrow monies back upon  satisfaction of our performance of these
obligations.

Insurance

     We maintain insurance coverage that is customary for companies our size and
engaged in the same line of business.  Our coverage  includes general  liability
insurance in the amount of $50 million for personal injury and property  damage.
We carry cost of control and operators extra expense  insurance of $5 million to
$20 million, depending on the estimated cost to drill the well for wells onshore
or in state waters,  and up to $50 million for wells in federal offshore waters.
The amounts are proportionately reduced if we own less than 100% of the well. We
also maintain $112 million in property insurance on our offshore properties.  We
also carry business interruption insurance on our significant properties,  which
covers  the  estimated   cash  flows  from  each  property  after  it  has  been
non-producing  for 21 days and  reimburses  us for those  amounts  for up to six
months.  Finally,  our officers and directors are  indemnified  by PANACO and we
maintain  insurance  of $3 million  which is designed to  reimburse us for legal
fees  incurred  in defense  costs.  We believe  that our  insurance  coverage is
adequate  and the  underwriters  of our  insurance  will be able to satisfy  any
claims  made.  However,  we can not assure you that this  insurance  or that the
underwriters  will adequately  cover all of the costs or that we will be able to
continue to purchase insurance at reasonable prices. Even one significant event,
if not adequately insured,  could  significantly  impair our financial condition
and results of operations.

Funding of Business Activities

Credit Facility

     Our primary source of capital beyond discretionary cash flows is our Credit
Facility.  Our Credit Facility is secured by a first mortgage on most of our oil
and natural gas  properties,  and is used  primarily as  development  capital on
properties  that we own. We may also use the Credit Facility for working capital
support, to provide letters of credit and general corporate purposes.

     In  September  1999 we put in place a new Credit  Facility,  with  Foothill
Capital  Corp.  as the Agent,  along with  Foothill  Partners,  L.P.  and Ableco
Finance, a subsidiary of Cereberus Capital Management, L.P. This Credit Facility
is a $60  million  line,  with a term of two  years  to  October  1,  2001,  and
extendable for an additional year at our option.  Borrowings under this Facility
bear  interest  at rates  ranging  from  prime  plus .5% up to prime  plus  3.0%
depending on the amounts borrowed.  We had $36.7 million outstanding at December
31, 1999.  We will continue to use this Facility in 2000 to fund part of our $30
million capital budget.

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<PAGE>


     The Credit  Facility is a  revolving  credit  agreement  subject to monthly
borrowing base  determinations.  These  determinations  are made from internally
prepared engineering reports, using a two year average of NYMEX future commodity
prices  and  are  based  on  our  semi-annual   third  party  reserve   reports.
Indebtedness  under this Credit Facility  constitutes  senior  indebtedness with
respect to the Senior Notes.

     Under  the  terms of this  Credit  Facility,  we must  maintain  a ratio of
trailing twelve-month EBITDA to net interest expense of not less than 1.0 to 1.0
through  December  31, 1999 and 1.5 to 1.0 from January 1, 2000 through the term
of the Facility.  We must also maintain a working  capital ratio,  as defined in
the agreement,  of not less than .25 to 1.0. Also, the Credit Facility  contains
certain limitations on mergers,  additional indebtedness and pledging or selling
assets. We were in compliance at December 31, 1999 with the covenants  contained
in the Credit Facility.

Senior Notes

     In October 1997 we issued $100 million of Senior Notes which bear  interest
at 10 5/8% and are due October 1, 2004. These Senior Notes are general unsecured
obligations and rank pari passu with any  unsubordinated  indebtedness  and rank
senior  to any  subordinated  indebtedness.  In  effect,  the  Senior  Notes are
subordinated to all secured indebtedness,  such as the Credit Facility, but only
up to the value of the assets that are secured.

     We can redeem all or part of the Senior Notes, at our option, after October
1, 2001, at certain  prices,  which are specified in the indenture  plus accrued
interest  to date.  We can also  redeem up to 35% of the  Senior  Notes any time
after  October 1, 2000 at a price of 110.625%  of the  principal,  plus  accrued
interest to date, with the proceeds of an equity offering.

     If a Change in  Control  occurs,  as it is defined  in the  Indenture,  the
holders of the Senior Notes can require PANACO to repurchase those notes at 101%
of the principal amounts plus accrued interest to date. We must maintain a total
Adjusted  Consolidated  Net Tangible  Asset Value,  as defined in the Indenture,
("ACNTA") equal to 125% of our  indebtedness at the end of each quarter.  If our
ACNTA falls below this percentage of indebtedness  for two succeeding  quarters,
we must redeem an amount of the Senior Notes sufficient to maintain this ratio.

     The Indenture  contains  certain  restrictive  covenants  that limit us 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 and incur liens.  The Indenture also restricts us
from merging or consolidating with any other person or sell,  assign,  transfer,
lease, convey or otherwise dispose of all or substantially all of our assets. In
addition, under certain circumstances,  we 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.  We were in compliance at December 31, 1999
with the covenants contained in the Indenture.

Common and Preferred Stock

     On December  31, 1999 we had issued and  outstanding  23,986,521  shares of
$.01 par value common stock.  You will find a more detailed  description  of our
common  stock and the rights of  ownership in Part II, Item 5 of this Form 10-K.
We are  authorized to issue 100 million  shares of common stock for a variety of
purposes with board of director approval. In the past, we have issued new common
stock for property acquisitions, raising additional capital and for compensation
to our  directors  and  employees.  We have an  Employee  Stock  Ownership  Plan
("ESOP")  that we contribute  shares to for the account of  employees.  The ESOP
plan was  established  in 1994 and is funded  annually at the  discretion of the
board of directors.

     We are  authorized to issue up to 5 million  shares of preferred  stock the
details of which you can also find in Part II, Item 5 of this Form 10-K. We have
not issued any shares of preferred stock.

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

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<PAGE>

natural  gas  producing  properties  and  securing  experienced  personnel.   We
encounter  competition from various independent oil companies in raising capital
and in acquiring  producing  properties.  Many of our competitors have financial
resources and staffs considerably larger than ours.

     Markets.  Our ability to produce and market oil and natural gas  profitably
is dependent upon on numerous  factors  beyond our control.  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.  At various times during
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  during  those
periods.

     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. We 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 that we produce  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, we are unable to predict future oil
and natural gas prices.  In order to minimize these  uncertainties  we have from
time to time hedged prices on a portion of our 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.  We sell our natural gas on the spot market
based upon published index prices.  Historically  our net price received for our
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 $.12 below the index price.

     Environmental   and  Other   Regulation.   Our   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.  These rules and regulations include
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 our
business.  In view of the many  uncertainties  with  respect to current  law and
regulations,  including their applicability to us, we cannot predict the overall
effect of such laws and regulations on future operations.

     We believe that our  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 our method of operations than on
other similar  companies in the  industry.  The  following  discussion  contains
summaries only of certain laws and regulations.

     Various  aspects of our 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

                                       10

<PAGE>

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 us are not
regulated and are made at market  prices.  The price we receive from the sale of
these products is affected by the cost of  transporting  the products to market.
Effective  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. We are not able to predict with certainty
the effect, if any, these regulations will have on our business.

     Additional  proposals and proceedings that might affect the oil and natural
gas industry are pending  before  Congress,  the FERC and the courts.  We 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 our
capital expenditures, earnings or competitive position.

     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 we are subject  relating to
protection of the  environment  may, in certain  circumstances,  impose  "strict
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
"Superfund"  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  we are  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 our operations and costs. Furthermore, we 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 us.  While  compliance  with
environmental requirements generally could have a material adverse effect on our
capital  expenditures,  earnings or  competitive  position we believe that other
independent energy companies in the oil and natural gas industry likely would be
similarly affected.  We also believe that we are 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
us.

     Offshore operations 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,  we do not expect  these costs to be material.
See "Risk Factors - Environmental and Other Regulations."

Employees

     We have 34 full time employees, five of whom are officers. Additionally, we
utilize  approximately 40 contract personnel in the operation of our properties,
and use numerous outside geologists,  production engineers, reservoir engineers,
geophysicists and other professionals on a consulting basis.

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Risk Factors

Finding and Acquiring Additional Reserves; Depletion

     Our future  success and growth  depends upon the ability to find or acquire
additional  oil and  natural gas  reserves  that are  economically  recoverable.
Except to the  extent  that we conduct  successful  exploration  or  development
activities  or  acquires  properties  containing  Proved  Reserves,  our  Proved
Reserves will  generally  decline as they are produced.  The decline rate varies
depending upon reservoir  characteristics and other factors.  Our future oil and
natural gas reserves and production,  and,  therefore,  cash flow and income are
highly  dependent upon the level of success in exploiting  our 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,  our ability to make the necessary capital  investments to maintain
or expand  this asset base of oil and natural gas  reserves  could be  impaired.
There can be no assurance that our planned development  projects and acquisition
activities  will  result in  additional  reserves  or that we will have  success
drilling  productive wells at economic returns sufficient to replace our current
and future production.

Substantial Leverage; Ability to Service Debt

     We have incurred  significant losses in 1999 and 1998 and are significantly
leveraged.  Our long-term  debt balance at December 31, 1999 was $138.9  million
and our stockholders' deficit was ($26.9 million). A large part of our losses in
each year was due to depletion and impairment of property costs based  primarily
on low  commodity  prices.  This level of  indebtedness  has  several  important
effects on our operations,  including (i) a substantial portion of our cash flow
from  operations  is  dedicated  to  interest on our  long-term  debt and is not
available for other purposes,  (ii) the covenants in our Credit Facility and our
Senior Notes can be very  restrictive as to how we conduct  business,  (iii) our
ability to obtain additional financing may be restricted,  (iv) the market price
for our common stock may be lower than  companies in our peer group.  We can not
give you assurance that we will continue to find financing on acceptable  terms,
or at  all.  If  sufficient  capital  is not  available,  we may  not be able to
continue to implement our business strategy.

     The Credit  Facility  lenders  have the  ultimate  decision,  at their sole
discretion,  as to the amounts  available  to borrow  under the line.  If oil or
natural gas prices decline significantly, the availability under this line could
be  severely  reduced.  The  Credit  Facility  requires  us to  satisfy  certain
financial ratios in the future. The failure to satisfy these covenants or any of
the other covenants in the Credit Facility would  constitute an event of default
thereunder and may permit the lenders to accelerate the indebtedness outstanding
under the Credit Facility and demand immediate repayment. See "Credit Facility."

Volatility of Oil and Natural Gas Prices

     Our revenues,  profitability  and the carrying value of 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.  Our ability to maintain or increase 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 our 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.   Our
production is weighted  toward natural gas,  making  earnings and cash flow more
sensitive to natural gas price fluctuations.  Historically, we have attempted to
mitigate these risks by oil and natural gas hedging transactions.  See "Business
- Marketing of Production."

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<PAGE>

Uncertainty of Estimates of Reserves and Future Net Cash Flows

     The basis for the success and long-term  continuation of our Company is the
prices that we receive for our oil and natural gas. These prices are the primary
factors for all aspects of our business  including  reserve  values,  future net
cash  flows,  borrowing  availability  and  results of  operations.  The reserve
valuations  are prepared  semi-annually  by independent  petroleum  consultants,
including the Pretax PV-10 values included in this Form 10-K. However, there are
many  uncertainties  inherent  in  preparing  these  reports and the third party
consultants  rely on information we provide them. The Pretax PV-10  calculations
assume  constant  oil and  natural gas prices,  operating  expenses  and capital
expenditures over the lives of the reserves. They also assume certain timing for
completion  of projects and that we will have the  financial  ability to conduct
operations and capital expenditures without regard to factors independent of the
reserve  report.  The  actual  results we realize  from  these  properties  have
historically  varied from these reports and may do so in the future. The volumes
estimated in these  reports may also vary due to a variety of reasons  including
incorrect assumptions,  unsuccessful drilling and the actual oil and natural gas
prices that we receive.

     You should not assume that the Pretax PV-10 values of our reserves that are
included in this Form 10-K represent the market value for those reserves.  These
values are prepared in  accordance  with strict  guidelines  imposed by the SEC.
These  valuations  are the estimated  discounted  future net cash flows from our
Proved  Reserves.  These  estimates  use prices  that we  received or would have
received  on  December  31,  1999  and  use  costs  for  operating  and  capital
expenditures in effect at that same time. The average prices used in calculating
the Pretax  PV-10 value at  December  31, 1999 were $2.43 per Mcf of natural gas
and  $24.99 per  barrel of oil.  These  prices  are  adjusted  on a property  by
property basis for the quality of the oil and natural gas and for transportation
to the  appropriate  location.  These  assumptions  are then used to calculate a
future cash flow stream, that is discounted at a rate of 10%.

Acquisition Risks

     As our business  strategy is to grow  primarily  through  acquisitions  and
subsequent development of those acquired properties,  you should know that there
are risks  involved in  acquiring  oil and gas  reserves.  We perform  extensive
reviews  of  properties  that we  intend  to  acquire  based on the  information
available to us. With a limited  staff,  we may use  consultants to assist us in
our review and we may rely on third party  information  available to us.  Again,
these are inherent  uncertainties  in the review process.  Consistent with other
companies in our peer group, we focus our review on the properties with the most
significant  values and spend  less time on less  significant  properties.  This
could leave  undetected a problem or issue that did not  initially  appear to be
significant to us.

     We have typically  focused our  acquisition  efforts on larger assets being
sold such as our BP Acquisition  and Amoco  Acquisition.  By doing so, we are at
risk for  unforeseen  problems  to become  significant  both  operationally  and
financially. Variations of actual results from results we estimate in the review
process could also be more significant to us.

Exploration and Development Risks

     With our inventory of projects on our existing properties,  we have done or
plan to do more  development,  and to a lesser extent,  exploration than we have
since the inception of our Company. While we feel that this is the best approach
to implement our business  strategy,  it also involves inherent risks. The costs
of drilling all types of wells are uncertain, as are the quantity of reserves to
be found,  the prices  that we will  receive  for the oil or natural gas and the
costs to operate the well.  While we have  successfully  drilled many wells, you
should know that there are  inherent  risks in doing so, and those  difficulties
could materially affect our financial condition and results of operations. Also,
just because we complete a well and begin  producing  oil or natural gas, we can
not assure you that we will recover our investment or make a profit.

Operating Hazards and Uninsured Risks

     Our 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

                                       13

<PAGE>

of  life,  damage  to  properties  and  substantial  losses.  Although  we carry
insurance at levels we believe are reasonable,  we are not fully insured against
all risks. Losses and liabilities arising from uninsured or under-insured events
could have a material adverse effect on our financial condition and operations.

Marketing Risks

     Substantially  all of our 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, 1999,  one
natural gas purchaser accounted for approximately 39% of our revenues.  Also, in
1999 we consolidated a majority of our oil production to one oil purchaser,  who
accounted  for  37% of our  total  revenues  in  1999.  We do not  believe  that
discontinuation  of a sales arrangement with either of these purchasers would be
in any way disruptive to our marketing operations.

Hedging Risks

     Historically, we have attempted to reduce our exposure to the volatility of
crude oil and  natural gas prices by hedging a portion of our  production.  In a
typical  hedge  transaction,  we  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,  we are
required to pay the counter party all or a portion of this difference multiplied
by the quantity hedged,  regardless of whether we have 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 us to make payments under the hedge agreements even though such payments
are not offset by sales of production.  In the past, we have hedged up to 80% of
oil and natural gas production on an annualized basis.  Hedging may also prevent
us from  receiving  the full  advantage of increases in crude oil or natural gas
prices above the fixed amount  specified  in the hedge.  For the year 2000,  our
hedges are  composed  primarily  of floors for both oil and natural  gas.  These
floors set a minimum price that we will receive on a certain amount of our daily
production,  and allow us to receive  all of the  benefit of prices in excess of
these minimums.  You can find more  information  regarding our hedging  activity
beginning on Page 29.

Abandonment Costs

     Government  regulations  and lease  terms  require  all oil and natural gas
producers to plug and abandon platforms and production  facilities at the end of
the properties'  lives.  Our reserve  valuations  include the estimated costs of
plugging the wells and abandoning the platforms and equipment on our properties.
These costs are usually higher on offshore properties,  as are most expenditures
on offshore properties. As of December 31, 1999, our total estimated abandonment
costs, net of $5.6 million already in escrow,  were approximately $15.7 million.
We  account  for  those  future   liabilities   by  accruing  for  them  in  our
depreciation,  depletion  and  amortization  expense  over  the  lines  of  each
property's total Proved Reserves.

Environmental and Other Regulations

     Our  operations  are  affected  by  extensive  regulation  through  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.

     Our operations 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 us 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

                                       14

<PAGE>

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.  In the  past,  we have  agreed  to  indemnify  sellers  of  producing
properties against certain liabilities for environmental  claims associated with
those  properties.  We can not  assure  you  that new  laws or  regulations,  or
modifications of or new  interpretations of existing laws and regulations,  will
not substantially  increase the cost of compliance or otherwise adversely affect
our oil and natural gas  operations  and  financial  condition or that  material
indemnity  claims  will not arise with  respect to  properties  that we acquire.
While  we  do  not  anticipate  incurring  material  costs  in  connection  with
environmental  compliance  and  remediation,  we cannot  guarantee that material
costs will not be incurred.

Dependence Upon Key Personnel

     Our success will depend  almost  entirely upon the ability of a small group
of key executives and technical staff to manage our business. Should one or more
of these  employees  leave or become unable to perform their duties,  we can not
assure you that we will be able to attract competent new management.

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.  We encounter  competition from
various  independent oil companies in raising capital and in acquiring producing
properties.  Many  of  our  competitors  have  financial  resources  and  staffs
considerably  larger than us. See "Business - Competition,  Markets  Seasonality
and Environmental and Other Regulation."

Item 2.  Properties.

     At December 31, 1999 our Proved Reserves  totaled 135 Bcfe and had a Pretax
PV-10  value  of  $181.3  million.  Approximately  60%  of  these  reserves  are
classified as Proved Developed  Reserves and  approximately 61% are natural gas.
Our 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. We
own interests in a total of 43 producing oil wells and 98 producing  natural gas
wells.  We also own  interests in 23 federal  blocks in the Gulf of Mexico and 9
state water blocks and we operate 66% of the 114 producing offshore wells, based
upon the Pretax PV-10 value as of December 31, 1999. Our  non-operated  offshore
properties are operated by large independents and major oil companies, including
Unocal,  Newfield,  Texaco, Coastal,  Anadarko and Burlington.  Our 27 producing
onshore wells account for 18% of our total Pretax PV-10 value as of December 31,
1999. We operate 52% of our onshore  wells,  based upon such Pretax PV-10 value.
We also own  interests  in 23  offshore  production  platforms  and 109 miles of
offshore oil and natural gas pipelines with diameters of 10" or larger.

     While we review many  acquisition  opportunities  each year,  and have made
several  acquisitions under $5 million, we usually focus on larger acquisitions,
relative to the size of our company.  Gulf Coast  Region and more  specifically,
Gulf of Mexico  property  acquisitions  tend to have larger  reserves and larger
purchase  prices.  We feel they  usually  also  provide  more  exploitation  and
development  potential.  Since 1991, we have made six  acquisitions of producing
properties that had Proved Reserves of 159 Bcfe at the time of their  respective
acquisitions. We paid a total of $106.4 million for the Proved Reserve component
of those acquisitions.  By focusing on larger acquisitions,  our reserve base is
concentrated in a small number of properties.

                                       15

<PAGE>

     The following is a summary of our significant properties as of December 31,
1999. These properties  represent 80% of the aggregate Pretax PV-10 value of our
Proved Reserves.

<TABLE>
<CAPTION>

                                          Total Proved Reserves
                               -------------------------------------------
                                                                                    % of
                                                              Pretax PV-10   PANACO Total Pretax
           Field               Oi1 (MBbls)   Natural Gas(Bcf)  Value(000s)          PV-10

------------------------------------------------------------------------------------------------
        <S>                      <C>              <C>             <C>              <C>

       East Breaks 165          3,989           20.3          $ 59,730                33%
       Umbrella Point           1,255           12.9            26,841                15
       East Breaks 160            995            9.5            24,869                14
       West Delta                 553           12.1            22,467                12
       Price Lake                 116            6.7            10,814                 6
------------------------------------------------------------------------------------------------
          Total                 6,908           61.5          $144,721                80%
</TABLE>


East Breaks 165

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

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.  We own
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 5 mile oil pipeline we own to our onshore production  facility
at Cedar Point.  Gas  production is  transported  through a Midcon  Pipeline Co.
pipeline.

     We acquired this field in July 1997 as a part of the Goldking  Acquisition.
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 we announced the successful completion
of our first new 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  production  from this well peaked at 27,000 Mcf per
day of natural gas and 260  barrels of oil per day in July 1998.  It declined to
600 Mcf of natural  gas and 5 barrels of oil per day in December  1999.  In that
month, we completed a workover on the well and brought the production back up to
18,600 Mcf of natural  gas and 176 barrels of oil per day. We own an 80% working
interest in the well. The remaining 20% is owned by Peoples Energy Production.

East Breaks 160

     We 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  some  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. from 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,  we 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

                                       16

<PAGE>

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 we believe that, due to the ongoing deepwater  exploration in the Area,
our platform and pipelines  can become long term  strategic  revenue  generating
assets after the field reserves are depleted.

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 through May 1999 due to a third
party  pipeline being shut in. We are the operator and generally own 100% of the
working interest in these wells. Presently,  the properties have 36 wells, 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 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.  In
February  2000 we completed a new well in Block 54, the #30 well.  This new well
was drilled to 7500' and encountered and estimated 110' of producing  formation.
The reserves in this well are primarily natural gas, adding  approximately 6 Bcf
of net reserves.

     We have allowed  third party  operators to drill  several wells in Block 58
through farmout  agreements.  In return, we receive either a working interest or
overriding  royalty interest in their wells at our option. We also process their
oil and some of their natural gas for a fee. In February 2000, Basin Exploration
completed a well that was farmed out from us in Block 58. Their well was drilled
to a subsea true  vertical  depth of 11,300' and logged in excess of 150' of net
oil and  gas/condensate  pay in multiple  Miocene-aged  sands. We retained a 10%
overriding  royalty interest before payout with the option of either  escalating
the  overriding  royalty  interest  to 12.5%,  or  converting  to a 30%  working
interest.  In addition,  not  withstanding  the forgoing terms, in the event the
completion  is certain  sands,  our retained  overriding  royalty  interest will
triple for the period of time in which our booked reserves are being produced.

     During 1994, we 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.  We
have a 15% overriding  royalty  interest in that acreage.  The well is currently
producing  7,000  Mcf per  day  and 427  Bbls  of  condensate  per  day.  Energy
Development Corporation was subsequently acquired by Samedan Oil Corporation.

     In January 2000 we received a favorable judgement in a lawsuit we had filed
with our insurance carrier in 1996 related to the West Delta Fields. Our part of
the lawsuit was  primarily for lost revenues in 1996 from a fire at Tank Battery
#3 which was caused by a third party service company.  The judgement against the
service  companies'  insurance carrier was $1.1 million.  Currently,  we can not
estimate when we will recognize and receive the proceeds from this judgement.

Price Lake

     For  more  information  regarding  the  Price  Lake  Field,  see  "Business
Strategy-Price Lake Field."

Oil and Gas Information

     Our reserve  estimates  are prepared by third party  engineering  firms who
prepare their reports based on  information we provide them. The firms we use to
prepare  these  estimates  are  Ryder  Scott  Company,  Netherland,  Sewell  and
Associates,  Inc., W.D. Von Gonten and Co. and McCune  Engineering.  Ryder Scott
Company and Netherland,  Sewell and Associates,  Inc. prepare estimates for most
of our larger  properties and account for 77% of the Pretax PV-10 of our reserve
estimates.  Our proved oil reserves  totaled 8.7 million barrels at December 31,
1999 compared to 7.5 million  barrels at December 31, 1998.  Our proved  natural
gas  reserves  totaled  82.8 Bcf at December 31, 1999 as compared to 81.2 Bcf at
December 31, 1998. The Pretax PV-10 value of these reserves totaled $181 million

                                       17

<PAGE>

at December  31, 1999  compared to $95  million at December  31,  1998.  Despite
liquidity  and capital  resource we replaced 149% of our 1999  production  which
totaled 18.1 Bcf equivalent. For more information related to our oil and natural
gas reserves,  see  "Supplemental  Information  Related to Oil and Gas Producing
Activities (Unaudited)," which is in Part IV, Item 14(a) in this Form 10-K.

                        Production, Price, and Cost Data

     The following table presents certain production,  price, and cost data with
respect to our properties for the three years ended December 31, 1997,  1998 and
1999.

<TABLE>
<CAPTION>

                                                        For the year ended December 31,

                                                      ----------------------------------
                                                        1997             1998          1999(c)
<S>                                                       <C>              <C>            <C>


Oil and Condensate:
  Net Production (Bbls)(a)                              515,000         895,000       1,170,000
  Revenue                                          $  9,354,000    $ 10,916,000    $ 22,025,000
  Hedge gains (losses)                             $    (67,000)   $  2,034,000    $ (1,784,000)
  Average net Bbl per day                                 1,411           2,452           3,204
  Average price per Bbl before hedges              $      18.17    $      12.20    $      18.83
  Average price per Bbl including hedges           $      18.04    $      14.47    $      17.31

Natural Gas:
  Net Production (Mcf)(a)                            11,468,000      18,041,000      11,114,000
  Revenue                                          $ 29,751,000    $ 36,910,000    $ 25,267,000
  Hedge gains (losses)                             $ (1,197,000)   $    431,000    $ (2,836,000)
  Average net Mcf per day                                31,400          49,400          30,400
  Average price per Mcf before hedges              $       2.59    $       2.05    $       2.27
  Average price per Mcf including hedges           $       2.49    $       2.07    $       2.02

Total Revenues                                     $ 37,841,000    $ 50,291,000    $ 42,672,000

Production costs                                   $ 11,150,000    $ 18,148,000    $ 17,740,000
  Total Production (Mcfe)(b)                         14,557,000      23,411,000      18,132,000
  Production cost per Mcfe(b)                      $        .77    $        .78    $        .98
</TABLE>

----------------------
(a)  Production information is net of all royalty interests.  Beginning in 1999,
     the MMS began taking its royalties in-kind rather than being paid in cash.
(b)  Oil  production  is converted  to Mcfe at the rate of 6 Mcf per Bbl,  which
     represents the estimated relative energy content of natural gas to oil.
(c)  Several   projects   scheduled   for  1999  were  delayed  due  to  capital
     constraints.

                                                           Producing Wells(a)

     The  following  table  presents the number of producing oil and natural gas
wells, as of December 31, 1999, attributable to our properties.
<TABLE>
<CAPTION>

                                                        Producing Wells    Company Operated
                                                        ---------------    ----------------

        <S>                                                <C>                  <C>

       Gross producing offshore wells(b):
           Oil   .....................................        24                 24
           Natural Gas   .............................        90                 40
                                                              --                 --
                Total ................................       114                 64

       Net producing offshore wells(c):
           Oil   .....................................        24                 24
           Natural Gas   ...............                      51                 37
                                                              --                 --
                Total ................................        75                 61



                                       18

<PAGE>

       Gross producing onshore wells(b):
           Oil   .....................................        19                 16
           Natural Gas   .............................         8                  9
                                                              --                 --
                Total ................................        27                 25

       Net productive onshore wells(c):
           Oil   ...............                               9                  7
           Natural Gas   ...............                       5                  4
                                                              --                 --
                Total ...............................         14                 11

</TABLE>
----------------------
(a)  One or more  completions  in the same borehole are counted as one well.
(b)  A "gross  well" is a well in which we own a  working  interest.
(c)  A "net  well" is deemed  to exist  when the sum of the  fractional  working
     interests in gross wells equals one.
<TABLE>
<CAPTION>

                                Leasehold Acreage

     The following table presents the developed acreage as of December 31, 1999,
attributable to our properties.
                <S>                                                      <C>

        Developed onshore acreage(a):
                Gross acres(b)....................................      3,728
                Net acres(c)......................................      1,843

        Undeveloped onshore acreage(a):
                Gross acres(b)....................................      3,887
                Net acres(c)......................................      1,145

        Developed offshore acreage(a):
                Gross acres(b)....................................    113,330
                Net acres(c)......................................     49,300

        Undeveloped offshore acreage(a)(d):
                Gross acres(b)....................................      3,667
                Net acres(c)......................................      2,587
</TABLE>

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

(a)  Developed acreage is acreage assignable to producing wells.
(b)  A "gross acre" is one in which we own a working interest.
(c)  A "net  acre" is deemed  to exist  when the sum of the  fractional  working
     interests in gross acres equals one.
(d)  In addition to these acres,  our undeveloped  offshore  potential exists at
     greater depths beneath existing producing reservoirs.

                               Drilling Activities

     The following  table presents the number of gross  productive and dry wells
in which we had an  interest,  that were drilled and  completed  during the five
years ended  December 31, 1999. You should not consider this to be indicative of
our future  performance,  nor should  you assume  that there is any  correlation
between  the number of  productive  wells  drilled  and the oil and  natural gas
reserves generated from those wells or the costs of productive wells compared to
the costs 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>

 1995       --      --      --      --            --      --      --      3
 1996       --      --       2      --            --      --      --     --
 1997        6      13      --       1            --      --      --     --
 1998        1       9      --      --            --       3      --      6
 1999        1      --      --      --            --       4      --      3
           ---     ---     ---     ---           ---     ---     ---    ---
Total        8      22       2       1            --       7      --     12
</TABLE>

                                       19

<PAGE>

Title to Oil and Gas Properties

     When  we  acquire   properties  we  obtain  title  opinions  for  our  more
significant  properties.  Prior to the  commencement  of drilling  operations we
conduct a thorough  drill site title  examination  and perform any curative work
with respect to significant defects.

Item 3.  Legal Proceedings.

     An action was filed  against  us in  Louisiana,  along with 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 us and NEG,  NEG is
required to indemnify us 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 us to assert our indemnity rights against NEG
is currently stayed.  Our Counsel has prepared and may file a motion to lift the
stay so that we may assert its  indemnification  rights against NEG. But even if
we are  successful in proving our right to  indemnity,  NEG's ability to satisfy
the judgement is questionable because of the bankruptcy.

     Pursuant to another  purchase and sale  agreement,  we may owe indemnity to
Shell and Exxon,  from whom we acquired  the  property  prior to selling same to
NEG. We may have insurance coverage for the claims asserted in the petition, and
have notified all  insurance  carriers  that might  provide  coverage  under our
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.

     We are  presently  a party to several  other  legal  proceedings,  which we
consider  to be  routine  and in the  ordinary  course of  business.  We have no
knowledge of any other pending or threatened  claims that could give rise to any
litigation which would be material to the Company.

Item 4.  Submission of Matters to a Vote of Security Holders.
     None.

                                    PART II

Item 5. Market for Common Stock and Related Shareholder Matters.

     Our authorized  capital shares consists of 100,000,000  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 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 our  Certificate  of
Incorporation.

Common Shares

     We are authorized by our Certificate of Incorporation, as amended, to issue
100,000,000 Common Shares, of which 24,323,521 shares are issued and outstanding
as of March  20,  2000  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.

                                       20

<PAGE>

     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.

     Warrants and Options We also have 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  and  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 our  Certificate of  Incorporation,  we are authorized to issue
5,000,000  preferred  shares,  and the Board of Directors,  by  resolution,  may
establish one or more classes or series of preferred shares having the number of
shares,  designations,  relative voting 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 our Common
Shares is American Stock Transfer and Trust Company, 6201 15th Avenue, Brooklyn,
New York 11204.

Price Range of Common Shares

     Since  September  1999,  our  Common  Shares  have  been  traded on the OTC
Bulletin  Board under the symbol  "PANA." Prior to that,  our Common Shares were
traded on NASDAQ under the same symbol.  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.

<TABLE>
<CAPTION>
                                      1999

         1st Quarter       2nd Quarter     3rd Quarter    4th Quarter
         -----------       -----------     -----------    -----------
            <S>                 <C>             <C>               <C>

         High $ 1-3/16      $ 1-3/16        $ 1-1/32        $ 5/8
         Low  $    7/8          9/16        $  17/32        $ 5/16

                                      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
</TABLE>


     On March 20,  2000,  the last sale price of the Common  Shares was $.90 per
share.

Dividend Policy

     We have not paid any cash  dividends  on our Common  Shares.  The  Delaware
General  Corporation  Law, to which we are subject,  permits us to pay dividends
only out of our 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 Credit
Facility and the Senior Notes contain restrictions on any dividends or

                                       21

<PAGE>

distributions and on any purchases of our Common Shares. We retain our cash flow
to finance the  expansion and  development  of our business and currently do 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.

Certain Anti-takeover Provisions

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

     The provisions of the 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 their best  interests,  including  attempts
that might  result in a premium over the market price for the shares held by our
shareholders.  In addition, certain provisions of Delaware law and our Long-Term
Incentive Plan may be deemed to have a similar effect.

     Certificate of Incorporation and By-laws. Our Board of Directors is divided
into three classes. The term of office of one class of directors expires at each
annual meeting of shareholders, when their successors 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 our shareholders,  has
the right to appoint persons to fill vacancies on the Board of Directors.

     Pursuant to our Certificate of  Incorporation,  the 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 the Company.

     Our  Certificate of  Incorporation  also contains a "fair price"  provision
that requires the affirmative  vote of the holders of at least 80% of the voting
shares and the affirmative vote of at least two-thirds of our voting shares that
are not owned,  directly or  indirectly,  by the  Related  Person to approve any
merger,  consolidation,  sale or lease of all or substantially all of our assets
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 our  voting  shares  who is a party to the  Transaction  at issue,  a
director who is also an officer and is a party to the  Transaction at issue,  an
affiliate of either such person, and certain  transferees of those persons.  The
voting requirements are not applicable to certain transactions,  including those
that are approved by the Continuing  Directors (as defined in the Certificate of
Incorporation)  or that meet  certain  "fair  price"  criteria  contained in the
Certificate of Incorporation.

     Our 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.

     Our  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,  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 us 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.

                                       22

<PAGE>

     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,  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.  We are a  Delaware  corporation  and are
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  outstanding  voting  shares) from engaging in a "business
combination"  (as defined in Section 203) with us 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  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 our voting shares
outstanding  at the time the  transaction  commenced  (excluding  shares held by
directors who are also officers 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 which that person  became an  interested  shareholder,  the
business  combination  is approved by the Board of Directors 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 us 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 our
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  Long-Term
Incentive Plan may provide that,  upon a change in control (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 Credit Facility and Senior Notes may also
impede a change in control,  in that they provide  that the Credit  Facility and
Senior Notes become due if there is a change in the  management 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.
Our Credit  Facility  would  become due upon an increase in  ownership of Common
Shares outstanding to over 30% of the then outstanding Common Shares.

                                       23

<PAGE>

Item 6.  Selected Financial Data.

     The  following  historical  data is  derived  from  Consolidated  Financial
Statements  and the notes  thereto.  When reading this data, you should refer to
our audited  consolidated  financial  statements and the related notes,  both of
which are included in this Form 10-K.
<TABLE>
<CAPTION>

                                                         For the year ended December 31,
                                               1995         1996       1997          1998        1999
                                               ------------------------------------------------------
                                                   (dollars in thousands, except per share data)
<S>                                            <C>          <C>          <C>        <C>          <C>


Oil and natural gas sales                   $ 18,447     $ 20,063    $ 37,841     $ 50,291   $ 42,672
Lease operating expense                        8,055        8,186      11,150       18,148     17,740
Depreciation, depletion & amortization
   expense                                     8,064        9,022      18,866       37,500     26,439
General and administrative expense               690        1,063       1,919        4,629      4,069
Production and ad valorem taxes                1,078          559         721        1,351      1,202
Exploratory dry hole expense                   8,112           --          67        5,655      1,050
Geological and geophysical expense                --           --         286        1,927      1,429
Impairment of oil and gas properties             751           --          --       20,406     13,202
Office consolidation and severance
   expense                                        --           --          --          987         --
West Delta fire loss                              --          500
                                              ------        -----       -----       ------     ------

Operating income (loss)                     $ (8,303)     $   733    $  4,832    $ (40,312) $ (22,459)
Interest expense (net)                           987        2,514       3,930        9,639     12,437
Income taxes (benefit)                            --           --          --       (3,100)        --
Gain (loss) on investment in common
   stock                                          --         (258)         75           --         --
Extraordinary item-loss on early
   retirement of debt                             --           --        (934)          --       (131)

                                              ------        -----       -----       ------     ------
Net Income (loss)                           $ (9,290)     $(2,039)   $     43     $(46,851) $ (35,027)
                                              ======        =====       =====       ======     ======

Net income (loss) per Common Share          $  (0.81)     $ (0.16)   $     --     $  (1.96) $   (1.46)


Summary Balance Sheet Data:
Oil and gas properties (net)                $ 29,485      $50,540    $112,548     $100,723  $  88,888
Total assets                                  36,169       73,768     179,629      143,372    135,438
Long-term debt                                22,390       49,500     101,700      115,749    138,902
Stockholders' equity (deficit)                 9,174       17,498      55,188        7,902    (26,875)
Dividends per Common Share                        --           --          --           --         --
</TABLE>

Item 7. Management's  Discussion and Analysis of Financial Condition and Results
of Operations.

     When  reading  the   following   discussion,   you  should  also  read  our
Consolidated Financial statements and their notes, both of which are included in
this Form 10-K. The following  discussion is our best  assessment of our Company
and current operations.  You should not assume that these results will continue.
You should also  understand  that due to numerous  acquisitions,  the results of
operations  for the periods  presented may not be necessarily  comparative.  See
"Business  Strategy - Strategic  Acquisitions and Mergers,"  beginning on Page 2
for further discussion of our acquisitions.

General

     With the exception of historical information, the matters discussed in this
Form 10-K contain forward-looking  statements. The forward-looking statements we
make, not only in this Form 10-K, but also in press  releases,  oral  statements

                                       24

<PAGE>

and other  reports  that we file with the  Securities  and  Exchange  Commission
("SEC") are intended to be subject to the safe harbor  provisions of the Private
Securities  Litigation  Reform Act of 1995.  These  statements  relate to future
results of operations,  the ability to satisfy future capital requirements,  the
growth  of  our  Company  and  other   matters.   You  are  cautioned  that  all
forward-looking   statements   involve  risks  and   uncertainties.   The  words
"estimate," "anticipate," "expect," "predict," "believe" and similar expressions
are intended to qualify these  forward-looking  statements.  We believe that the
forward-looking  statements  that we make are based on reasonable  expectations.
However, due to the nature of the business we are in, we can not assure you that
the actual results of our Company will not differ from those expectations.

     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 those  products and other  uncertainties
in the world energy markets. You should consider the volatility of this industry
when reading the following.

Year 2000 Issue

     To address  this  issue,  we  established  a Year 2000  ("Y2K")  Compliance
Project Team consisting of representatives from Information Technology,  Finance
and Operations.  The Team designed a 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 Team contacted
third-party  suppliers and  customers to ascertain  their state of readiness and
developed contingency plans as necessary. We passed the milestone of the turn of
the century with no major issues  pertaining  to the date change,  and we do not
anticipate any in the future.  The costs to be prepared for Y2K were  immaterial
to our results of operations.

Liquidity and Capital Resources

     In  implementing  our business  strategy of increasing our reserve base and
cash flows from  operations,  we have  reinvested our cash flows from operations
into capital expenditures. Our secondary source of capital expenditure resources
is our Credit  Facility,  which is also used for  working  capital  support  and
general corporate purposes.  During 1999, our cash flows from operations totaled
$8 million and our borrowings  under the Credit  Facility  increased $23 million
for our $26 million in capital  expenditures.  This left our  balance  under the
Credit Facility at $36.7 million,  with  availability of $16 million at December
31, 1999. During 1999 we sold several of our non-core properties for $1 million.
The  properties  we sold are  non-operated,  onshore and have  relatively  small
values.  By selling  these  properties  we also became more  efficient as we can
focus our resources on our more  significant  properties.  We plan to continuing
reviewing all of our remaining similar properties for potential sale.

     For the year  2000,  our Board of  Directors  has  approved  a $30  million
capital budget.  This budget is based primarily on those resources  available to
us at this time. We believe that our cash flows from  operations  and borrowings
under our Credit Facility will fund this level of capital  expenditures and that
we will have sufficient availability under our Credit Facility to do so.

     On October 9, 1997,  we 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 our
outstanding  indebtedness  with the  remaining  $41.5  million  used for capital
expenditures including the BP Acquisition.

     On March 5, 1997,  we 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  newly  issued  shares  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). Our net
proceeds of $22 million from the offering  were used to prepay $13.5  million of
12% subordinated  debt and the remainder was used to reduce borrowings under the
existing Credit Facility.

                                       25

<PAGE>

Credit Facility

     Our primary source of capital beyond discretionary cash flows is our Credit
Facility.  Our Credit Facility is secured by a first mortgage on most of our oil
and natural gas  properties,  and is used  primarily as  development  capital on
properties  that we own. We may also use the Credit Facility for working capital
support, to provide letters of credit and general corporate purposes.

     In  September  1999 we put in place a new Credit  Facility,  with  Foothill
Capital  Corp. as the Agent,  and includes  Foothill  Partners,  L.P. and Ableco
Finance, a subsidiary of Cereberus Capital Management, L.P. This Credit Facility
is a $60  million  line,  with  a term  of  two  years,  and  extendable  for an
additional year at our option.  Borrowings  under this Facility bear interest at
rates ranging from prime plus .5% up to prime plus 3.0% depending on the amounts
borrowed.  We had $36.7  million  outstanding  at  December  31,  1999.  We will
continue to use this  Facility  in 2000 to fund part of our $30 million  capital
budget.

     The Credit  Facility is a  revolving  credit  agreement  subject to monthly
borrowing base determinations. These determinations are made based on internally
prepared engineering reports, using a two year average of NYMEX future commodity
process  and  are  based  on  our  semi-annual   third  party  reserve  reports.
Indebtedness  under this Credit Facility  constitutes  senior  indebtedness with
respect to the Senior Notes.

     Under  the  terms of this  Credit  Facility,  we must  maintain  a ratio of
trailing twelve-month EBITDA to net interest expense of not less than 1.0 to 1.0
through  December  31, 1999 and 1.5 to 1.0 from January 1, 2000 through the term
of the Facility.  We must also maintain a working  capital ratio,  as defined in
the agreement,  of not less than .25 to 1.0. Also, the Credit Facility  contains
certain limitations on mergers,  additional indebtedness and pledging or selling
assets.  We were in  compliance  with those  covenants  on December 31, 1999 and
anticipate compliance throughout the term of the loan.

     At December 31, 1999,  81% of our total assets were  represented by oil and
natural gas properties, pipelines and equipment, net of depreciation,  depletion
and amortization.

Results of Operations
<TABLE>
<CAPTION>

For the years ended December 31, 1999 and 1998:

"Oil and natural gas sales"

Production and Prices:

                                                               % Increase
                                         1999         1998     (Decrease)
                                         ----         ----     ----------
                <S>                      <C>         <C>          <C>

     Natural gas production (MMcf)      11,114       18,041      (38%)
     Average price per Mcf
      excluding hedging                $  2.27      $  2.05       11%
     Average price per Mcf
      including hedging                $  2.02$        2.07      (2%)

     Oil Production (MBbl)               1,170          895       31%
     Average price per Bbl
      excluding hedging                $ 18.83      $ 12.20       54%
     Average price per Bbl
      including hedging                $ 17.31      $ 14.47       20%
</TABLE>

     Improvements  in natural gas and oil prices during 1999 helped  support our
revenues,  while a decrease in natural gas production led to an overall  decline
in revenues.  Impairments of our unproved  properties and on the High Island 309
Fields were contributing factors to our net loss of $35 million.

                                       26

<PAGE>

     During  1999,  we hedged a total of  540,000  barrels  of oil at an average
NYMEX  equivalent  flow price of $15.34 per barrel.  These hedges were primarily
cost free collars,  with 245,000  barrels  having a floor of $15.00 and a cap of
$19.12  per  barrel and  214,000  barrels  having a floor of $15.00 and a cap of
$17.50  per  barrel.  We also  hedged  a total of 8.8 Bcf of  natural  gas at an
average NYMEX equivalent price of $2.14 per MMbtu.

     The decrease in natural gas  production  in 1999 was primarily due to three
fields, the West Delta Fields, the High Island 309 Fields and the Umbrella Point
Field.  High Island 309  production  decreased  4.5 Bcf from 1998 due to natural
production  declines,  which was further  complicated by compressor  problems on
both the High Island 309 and 310 platforms.  West Delta production decreased 1.1
Bcf due to shut-ins  earlier in 1999 while the pipeline  owned by Tennessee  Gas
Pipeline was repaired  along with the natural  production  decline of the wells.
Also,  production from the Umbrella Point Field was accelerated in 1998 with the
successful  completion of the SL 74 #10 well in January 1998. This well produced
as much as 27 MMcf per day in 1998 and has  reduced  since  then.  The change in
production  from 1998 was a reduction of 2.4 Bcf. These  decreases were somewhat
offset by an  addition  of 1.4 Bcf during  1999 from the East Breaks 165 Fields.
The Fields were acquired in May 1998 and produced for a full year in 1999.

     The significant  factor in our increased oil production was the acquisition
of the East Breaks 165 Field in May 1998, which is primarily an oil field.

     "Lease operating expense" decreased in 1999 due to several factors. We sold
a group of non-core  properties in 1999,  which lowered these expenses.  We also
implemented some cost reduction  programs on several of the offshore  properties
that we operate.  A large  percentage of the expenses  associated with operating
oil and  natural  gas leases are  fixed.  Our  decrease  in  production  in 1999
accounted for the increase in expenses per unit, or Mcf  equivalent  ("Mcfe") of
production.  We can significantly  increase production on our properties without
increasing these operating expenses.

     "Depreciation,    depletion    and    amortization    expense"    decreased
proportionately with the decrease in total production.  We also realized a lower
cost per unit of  production  in 1999,  from  $1.60 per Mcfe in 1998 to $1.46 in
1999.

     "General and  administrative  expense" was $560,000 lower in 1999 primarily
due to a larger  increase in our bad debt expense in 1998 versus  1999.  Normal,
recurring general and administrative expenses have remained relatively flat.

     "Exploratory dry hole expense" and "Geological and Geophysical expense" are
both representative of our decrease in exploratory  projects in 1999 compared to
1998.  During  2000,  we plan to  continue  some  participation  in  exploratory
projects, but we also plan to continue to do so at a modest level and percentage
of our capital budget.

     "Impairment  of oil and gas  properties"  in 1999  related to two  property
groups. We impaired most of our unproved properties in order to reflect the lack
of planned drilling activity on those properties with associated unproved costs.
We have an extensive drilling program for 2000, however, the projects identified
do not  include  those  properties  that were  impaired.  We also  impaired  the
carrying  value of our High  Island  309 Fields  due to  unsuccessful  workovers
completed during the fourth quarter.  These  unsuccessful  workovers resulted in
reserve reductions of approximately 5 Bcf.

     "Interest  expense  (net)"  increased in 1999 as we increased our borrowing
levels  over 1998.  In early  1998 and  throughout  most that  year,  our Credit
Facility  borrowing  was  relatively  low, as we had cash  available for capital
expenditures  from our Senior Note  Offering.  We increased the Credit  Facility
balance  during  1999 to $36.7  million at  December  31,  1999  compared to the
balance at December 31, 1998 of $13.5 million.

     "Extraordinary  item-loss  on early  retirement  of debt"  relates to a new
Credit  Facility  we put in place in  September  1999 and the write off of costs
associated with the previous facility, that was prepaid.

                                       27

<PAGE>
<TABLE>
<CAPTION>


For the years ended December 31, 1998 and 1997:

"Oil and natural gas sales"

Production and Prices:
                                                             % Increase
                                         1998         1997     (Decrease)
                                         ----         ----     ----------
                <S>                      <C>         <C>          <C>


     Natural gas production (MMcf)      18,041       11,468       57%
     Average price per Mcf
        excluding hedging              $  2.05      $  2.59      (21%)
     Average price per Mcf
        including hedging              $  2.07      $  2.49      (17%)

     Oil Production (MBbl)                 895          515       74%
     Average price per Bbl
        excluding hedging              $ 12.20      $ 18.17      (33%)
     Average price per Bbl
        including hedging              $ 14.47      $ 18.04      (20%)
</TABLE>

     The  decreases  in oil and  natural  gas  prices we  realized  in 1998, in
combination  with other key factors led to the significant  loss in 1998.  Price
declines led to a $20.4 million  impairment of our 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 our Kansas  City,  Missouri  office and the  related
severance expense also contributed to the net loss for the year.

     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 our  increased  natural gas  production  during  1998.  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. The primary  factors in our increased oil production in
1998  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.

     During 1998 we had natural gas hedged in quantities  ranging from 10,000 to
50,000 MMbtu per day in each month 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.

     Our 1998 oil hedge  program  improved the average net oil price we realized
by $2.27 per  barrel.  We hedged 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.

    "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 our proved reserves.  At December 31, 1998, the
average life of our proved reserves was approximately five and one-half years.

                                       28

<PAGE>

     "General and administrative  expense" increased $2.7 million in 1998 due to
acquisitions we made in July 1997, April 1998 and May 1998. We also increased an
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 that we acquired in July 1997.

     "Exploratory   dry  hole  expense"   reflects  our  increased   exploratory
activities in 1998. Of the 19 wells we drilled or  participated  in during 1998,
six of the exploratory  wells were not commercially  productive.  The wells were
operated by third parties and we owned working interests ranging from 10 to 20%.

     "Geological  and  geophysical   expense"  during  1998  resulted  from  our
non-drilling exploratory activities.

     "Impairment of oil and gas properties" represents an impairment of the book
value of our proved 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 our 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 our Senior Note
offering completed in October 1997. The increase is somewhat offset by a reduced
interest rate on a majority of long term debt. In connection  with the offering,
we 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.

Item 7a.  Qualitative and Quantitative Disclosure about Market Risks.

     We follow a hedging strategy designed to protect against the possibility of
severe price declines due to unusual market conditions.  We usually make hedging
decisions to assure a payout of a specific acquisition or development project or
to take advantage of unusual strength in the market.

     During 1997,  1998 and 1999, we hedged a portion of our oil and natural gas
production in  accordance  with our hedging  policy and as a requirement  of our
Credit Facilities.  During these periods, the hedges we entered into were either
swaps or cost free collars. The swaps were agreements to sell a certain quantity
of oil or natural gas in the future at a predetermined  price. Cost free collars
ensured that we would receive a predetermined  range of prices for our products.
Following is a summary of our historical hedging activity.
<TABLE>
<CAPTION>


                      Volume Hedged         Percentage of Actual Production
        Year   Natural Gas (Bcf) Oil (MBbl)       Natural Gas     Oil          Gain/(Loss)
        ----   ----------------------------       -----------     ---          -----------
        <S>     <C>               <C>                 <C>        <C>              <C>

        1997      5.1             263                 45%         51%         ($1.3 million)
        1998     12.0             463                 67%         52%          $2.5 million
        1999      8.8             540                 79%         46%         ($4.6 million)
</TABLE>

     For the year 2000, the Company has purchased options to put oil and natural
gas produced to a purchaser at an agreed upon price.  The natural gas put option
is for 10,000  MMbtu per day at a NYMEX  price of $2.04 per MMbtu.  The  Company
paid  $366,000 for the put option  which will be  amortized  over the period the
hedged  item is  produced,  fiscal  year  2000.  The oil put option is for 1,000
barrels of oil per day beginning March 1 and continuing through December 31 at a
NYMEX price of $20.00 per barrel. The oil put option cost $275,000 and will also
be amortized  over the period the hedge item is produced,  fiscal year 2000. The
Company  also has a small swap in place on an average of 232  barrels of oil for
each day at $17.00 per barrel. At December 31, 1999 the fair value of all of its
hedges was a loss of  $800,000.  The fair values of its hedges on  December  31,
1998 and 1997 was a gain of $1.8 million and a loss of $61,000, respectively.

                                       29

<PAGE>

     The fair value of our commodity hedging instruments is the estimated amount
we 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 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 consolidated  balance sheets
as of December  31, 1999 and 1998.  A 10% change in  commodity  prices would not
have a material change in the fair value of our hedging instruments.

     These hedge agreements  provide for the counterparty to make payments to us
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 to make
payments to the  counterparty  to the extent  market prices are greater than the
fixed prices.

     At December 31, 1998 we 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, 1999,  was $70 million.  We also had $36.7 million
outstanding  under our Credit Facility at December 31, 1999. The Credit Facility
is a floating rate facility,  with a fair value of $36.7 million. We do not have
any interest rate hedge agreements at December 31, 1999.

Item 8.  Financial Statements and Supplementary Data.

     The financial statements are included herein beginning at 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.

     None.

                                    PART III


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, 1999. 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, 1999. 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, 1999. 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, 1999. Such information is incorporated herein by reference.

                                       30

<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. No reports on Form 8-K were filed during the last
          quarter of the period covered by this report:

     (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.

          4.6***     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.

          10.17      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.

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

                                       31

<PAGE>


          10.25      New credit agreement dated September 30, 1999 filed as an
                     exhibit on the Company's Form 10-Q on November 15, 1999,
                     and incorporated herein by reference.

          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.

                                       32

<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 "slice" 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.

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.

                                       33

<PAGE>


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.

Pretax  PV-10.  The  present  value of proved  reserves  is an  estimate  of the
discounted  future net cash flows from oil and natural gas  reserves at December
31, 1999,  or as otherwise  indicated.  Net cash flow is defined as net revenues
less  production  and ad  valorem  taxes,  future  capital  costs and  operating
expenses, but before deducting federal income taxes. These 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,
1999, or as otherwise indicated.

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.

                                       34

<PAGE>


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.

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.

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.

                                       35

<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                         March 27, 2000
            -----------------------                     --------------
            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                         March 27, 2000
            ------------------------                    --------------
            Larry M. Wright,
            Chief Executive Officer and
            Director

        By: \s\ Todd R. Bart                            March 27, 2000
            ------------------------                    --------------
            Todd R. Bart
            Chief Financial Officer &
            Principal Accounting Officer

        By: \s\ Harold First                            March 27, 2000
            ------------------------                    --------------
            Harold First, Director

        By: \s\ A. Theodore Stautberg                   March 27, 2000
            ------------------------                    --------------
            A. Theodore Stautberg, Director

        By: \s\ James B. Kreamer                        March 27, 2000
            ------------------------                    --------------
            James B. Kreamer, Director

        By: \s\ Richard Lampen                          March 27, 2000
            ------------------------                    --------------
            Richard Lampen, Director

        By: ------------------------
            Felix Pardo, Director

        By: ------------------------
            Stanley Nortman, Director

        By: ------------------------
            Mark C. Barrett, Director

        By: ------------------------
            Donald Chesser, Director

                                       36

                                  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, 1999 and 1998             F-4

 Consolidated Statements of Operations for the Years Ended
     December 31, 1999, 1998 and 1997                                F-6

 Consolidated Statements of Changes in Stockholders' Equity (Deficit)
     for the Years Ended December 31, 1999, 1998 and 1997            F-7

 Consolidated Statements of Cash Flows for the Years Ended
     December 31, 1999, 1998 and 1997                                F-8

 Notes to Consolidated Financial Statements for the Years Ended
     December 31, 1999, 1998 and 1997                                F-10

                                      F-1


<PAGE>

                          Independent Auditors' Report

The Board of  Directors  and  Shareholders  PANACO,  Inc.:

We have audited the accompanying consolidated balance sheets of PANACO, Inc. and
subsidiaries  as of  December  31, 1999 and 1998,  and the related  consolidated
statements of operations,  changes in stockholders'  equity (deficit),  and cash
flows for the years 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,  1999  and  1998,  and the  results  of their
operations  and their cash flows for the years  then  ended in  conformity  with
generally accepted accounting principles.


                                                                        KPMG LLP
Houston, Texas
March 20, 2000

                                      F-2


<PAGE>

                    Report of Independent Public Accountants


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

We have audited the accompanying consolidated statements of operations,  changes
in  stockholders'  equity  (deficit) and cash flows of PANACO,  INC. (a Delaware
Corporation)  and  Subsidiaries  for the  year  ended  December  31,  1997.  The
financial  statements are the  responsibility of the Company's  management.  Our
responsibility  is to express an opinion on these 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 presents
fairly,  in all material  respects,  the results of operations and cash flows of
PANACO,  Inc.  and  Subsidiaries  for the  year  ended  December  31,  1997,  in
conformity with generally accepted accounting principles.



Arthur Andersen LLP
Kansas City, Missouri
April 7, 1998

                                      F-3
<PAGE>

                                  PANACO, Inc.
                           CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>

                                     ASSETS
                                     ------

                                                                           December 31,
                                                                           ------------

                                                                       1999            1998
                                                                       ----            ----
CURRENT ASSETS
<S>                                                                     <C>             <C>

Cash and cash equivalents                                       $   5,575,000    $   3,452,000
Accounts receivable                                                 9,675,000        8,332,000
Accounts receivable-employee                                           16,000           18,000
Prepaid and other                                                     729,000          268,000
                                                                  -----------      -----------
        Total current assets                                       15,995,000       12,070,000
                                                                  -----------      -----------

OIL AND GAS PROPERTIES, AS DETERMINED
BY THE SUCCESSFUL EFFORTS METHOD
OF ACCOUNTING
    Oil and gas properties, proved                                262,043,000      238,377,000
    Oil and gas properties, unproved                               15,672,000       15,128,000
    Less accumulated depreciation, depletion and amortization    (188,827,000)    (152,782,000)
                                                                  -----------      -----------
        Net oil and gas properties                                 88,888,000      100,723,000
                                                                  -----------      -----------

PIPELINES AND EQUIPMENT
    Pipelines and equipment                                        26,327,000       26,252,000
    Less accumulated depreciation                                  (6,130,000)      (3,415,000)
                                                                  -----------      -----------
        Net pipelines and equipment                                20,197,000       22,837,000
                                                                  -----------      -----------

OTHER ASSETS
    Restricted deposits                                             5,602,000        3,719,000
    Deferred financing costs, net                                   4,456,000        3,359,000
    Employee note receivable                                          300,000          300,000
    Other                                                                  --          364,000
                                                                  -----------      -----------
        Total other assets                                         10,358,000        7,742,000
                                                                  -----------      -----------

TOTAL ASSETS                                                    $ 135,438,000    $ 143,372,000
                                                                =============    =============

                                                                                  (Continued)
</TABLE>





          See accompanying notes to consolidated financial statements.

                                      F-4
<PAGE>

                 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

<TABLE>

<CAPTION>

                                                                             December 31,
                                                                           ------------

                                                                       1999            1998
                                                                       ----            ----
CURRENT ASSETS
<S>                                                                     <C>             <C>

CURRENT LIABILITIES
    Accounts payable                                            $  20,408,000    $  16,976,000
    Interest payable                                                3,003,000        2,745,000
    Revolving credit facility                                              --       13,500,000
                                                                  -----------      -----------
       Total current liabilities                                   23,411,000       33,221,000
                                                                  -----------      -----------


LONG-TERM DEBT                                                    138,902,000      102,249,000

COMMITMENTS AND CONTINGENCIES                                              --               --


STOCKHOLDERS' EQUITY (DEFICIT)
    Preferred Shares, $.01 par value,
       5,000,000 shares authorized; no
       shares issued and outstanding                                       --              --
    Common Shares, $.01 par value,
       100,000,000 shares authorized;
       23,986,521 and 24,009,605 shares
       issued; and 23,986,521 and 23,704,955
       outstanding, respectively                                      243,000          240,000
    Treasury stock, 304,650 shares held at cost                            --         (592,000)
    Additional paid-in capital                                     68,852,000       69,197,000
    Accumulated deficit                                           (95,970,000)     (60,943,000)
                                                                  -----------      -----------
       Total Stockholders' Equity (Deficit)                       (26,875,000)       7,902,000
                                                                  -----------      -----------



TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)            $ 135,438,000    $ 143,372,000
                                                                =============    =============


</TABLE>




           See accompanying notes to consolidated financial statements.

                                      F-5
<PAGE>

                                  PANACO, Inc.
                      CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
                                                            Year Ended December 31,
                                                            -----------------------
                                                      1999           1998            1997
                                                      ----           ----            ----
<S>                                                    <C>             <C>            <C>

REVENUES
    Oil and natural gas sales                    $ 42,672,000    $ 50,291,000    $ 37,841,000

COSTS AND EXPENSES
    Lease operating expense                        17,740,000      18,148,000      11,150,000
    Depreciation, depletion and amortization       26,439,000      37,500,000      18,866,000
    General and administrative expense              4,069,000       4,629,000       1,919,000
    Production and ad valorem taxes                 1,202,000       1,351,000         721,000
    Exploratory dry hole expense                    1,050,000       5,655,000          67,000
    Geological and geophysical expense              1,429,000       1,927,000         286,000
    Impairment of oil and gas properties           13,202,000      20,406,000              --
    Office consolidation and severance expense             --         987,000              --
                                                  -----------     -----------     -----------
          Total                                    65,131,000      90,603,000      33,009,000
                                                  -----------     -----------     -----------

OPERATING INCOME (LOSS)                           (22,459,000)    (40,312,000)      4,832,000
                                                  -----------     -----------     -----------

OTHER INCOME (EXPENSE)
    Gain on investment in common stock                     --              --          75,000
    Interest income                                   255,000         849,000         745,000
    Interest expense                              (12,692,000)    (10,488,000)     (4,675,000)
                                                  -----------     -----------     -----------
       Total                                      (12,437,000)     (9,639,000)     (3,855,000)
                                                  -----------     -----------     -----------
INCOME (LOSS) BEFORE INCOME
    TAXES AND EXTRAORDINARY ITEM                  (34,896,000)    (49,951,000)        977,000

INCOME TAXES (BENEFIT)                                     --      (3,100,000)             --
                                                  -----------     -----------     -----------
INCOME (LOSS) BEFORE
    EXTRAORDINARY ITEM                            (34,896,000)    (46,851,000)        977,000
EXTRAORDINARY ITEM - Loss on early
    retirement of debt                               (131,000)             --        (934,000)
                                                  -----------     ------------    -----------
NET INCOME (LOSS)                                $(35,027,000)  $ (46,851,000)         43,000
                                                 ============    =============    ===========

BASIC AND DILUTED EARNINGS (LOSS)
   PER SHARE
    Income (loss) before extraordinary item      $      (1.45)   $      (1.96)   $        .05
    Extraordinary item                                   (.01)             --            (.05)
                                                  -----------     -----------     -----------
    Net income (loss)                            $      (1.46)   $      (1.96)   $         --
                                                 ============    ============    ============


BASIC SHARES OUTSTANDING                           23,940,785      23,884,091      20,781,205
                                                 ============    ============    ============

DILUTED SHARES OUTSTANDING                         23,940,785      23,884,091      21,024,847
                                                 ============    ============    ============

</TABLE>




          See accompanying notes to consolidated financial statements.

                                      F-6

<PAGE>

                                  PANACO, Inc.
      CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
              FOR THE YEARS ENDED DECEMBER 31, 1997, 1998 AND 1999

<TABLE>
<CAPTION>

                                                                                                                        Total
                                                Number of      Common      Additional                                Stockholders'
                                                 Common        Share        Paid-In        Treasury   Accumulated       Equity
                                                 Shares      Par Value      Capital         Stock       Deficit        (Deficit)
                                                 ------      ---------      -------         -----        -------      -----------

<S>                                              <C>            <C>            <C>            <C>          <C>               <C>

Balances, December 31, 1996                     14,350,255   $ 143,000   $ 31,490,000     $    --    $(14,135,000)   $ 17,498,000

   Net income                                           --          --             --          --          43,000          43,000
   Exercise of warrants, shares issued under
      Employee Stock Ownership Plan and
      Director and employee stock bonuses          324,346       3,000        783,000          --              --         786,000
   Issuance of warrants to retire debt                --          --          450,000          --              --         450,000
   Acquisition of properties                     3,238,930      33,000     14,381,000          --              --      14,414,000
   Issuance of new shares                        6,000,000      60,000     21,937,000          --              --      21,997,000
                                                ----------     -------     ----------     -------      ----------      ----------
Balances, December 31, 1997                     23,913,531     239,000     69,041,000          --     (14,092,000)     55,188,000

   Net loss                                             --          --             --          --     (46,851,000)    (46,851,000)
   Shares issued under Employee
      Stock Ownership Plan and
      Director stock bonuses                        96,074       1,000        274,000          --              --         275,000
   Shareholder rights redemption                        --          --       (118,000)         --              --        (118,000)
   Purchase of treasury stock                     (304,650)         --             --    (592,000)             --        (592,000)
                                                  --------    --------     ----------     -------      ----------      ----------
Balances, December 31, 1998                     23,704,955     240,000     69,197,000   $(592,000)    (60,943,000)      7,902,000

   Net loss                                             --          --             --          --     (35,027,000)    (35,027,000)
   Shares issued under Employee
      Stock Ownership Plan                         281,566       3,000        247,000          --              --         250,000
   Cancellation of treasury stock                       --          --       (592,000)    592,000              --              --
                                                ----------     -------     ----------     -------      ----------      ----------
Balances, December 31, 1999                     23,986,521   $ 243,000    $68,852,000    $     --    $(95,970,000)   $(26,875,000)
                                                ==========    ========     ==========     =======     ===========     ===========

</TABLE>





           See accompanying notes to consolidated financial statements.

                                      F-7
<PAGE>

                                  PANACO, Inc.
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>

                                                                        Year Ended December 31,
                                                                        -----------------------
                                                                1999             1998             1997
                                                                ----             ----             ----
<S>                                                              <C>             <C>               <C>

CASH FLOWS FROM OPERATING ACTIVITIES
   Net income (loss)                                      $ (35,027,000)   $ (46,851,000)     $    43,000
   Adjustments to reconcile net income (loss)
       to net cash provided by operating activities:
     Extraordinary item                                         131,000               --          934,000
     Depreciation, depletion and amortization                26,439,000       37,500,000       18,866,000
     Impairment of oil and gas properties                    13,202,000       20,406,000               --
     Exploratory dry hole expense                             1,050,000        5,655,000           67,000
     Deferred income tax benefit                                     --       (3,100,000)              --
     Gain on investment in common stock                              --               --          (75,000)
     ESOP stock contribution expense                                 --          275,000          165,000
     Changes in operating assets and liabilities:
         Accounts receivable                                 (1,343,000)       1,403,000         (969,000)
         Related party note receivable                            2,000         (318,000)              --
         Prepaid and other                                      (97,000)         572,000          129,000
         Accounts payable                                     3,682,000         (249,000)       4,172,000
         Interest payable                                       258,000          329,000        1,822,000
                                                             ----------       ----------       ----------
     Net cash provided by operating activities                8,297,000       15,622,000       25,154,000
                                                             ----------       ----------       ----------

CASH FLOWS USED IN INVESTING ACTIVITIES
   Proceeds from the sale of oil and gas properties           1,036,000           23,000           87,000
   Proceeds from the sale of investment in common stock              --               --        1,717,000
   Capital expenditures and acquisitions                    (26,429,000)     (61,253,000)     (41,997,000)
   Increase in restricted deposits                           (1,883,000)      (1,463,000)        (141,000)
                                                             ----------       ----------       ----------
     Net cash used in investing activities                  (27,276,000)     (62,693,000)     (40,334,000)
                                                             ----------       ----------       ----------

CASH FLOWS FROM FINANCING ACTIVITIES
   Long-term debt proceeds                                   47,153,000       46,049,000      112,459,000
   Repayment of long-term debt                              (24,000,000)     (32,000,000)     (84,742,000)
   Issuance of common shares                                         --          275,000       22,636,000
   Additional deferred financing costs                       (2,051,000)              --               --
   Acquisition of treasury stock                                     --         (592,000)              --
   Shareholder rights redemption                                     --         (118,000)              --
                                                             ----------       ----------       ----------
     Net cash provided by financing activities               21,102,000       13,614,000       50,353,000
                                                             ----------       ----------       ----------

NET INCREASE (DECREASE) IN CASH                           $   2,123,000    $ (33,457,000)   $  35,173,000

CASH AT BEGINNING OF YEAR                                     3,452,000       36,909,000        1,736,000
                                                             ----------       ----------       ----------

CASH AT END OF YEAR                                       $   5,575,000    $   3,452,000    $  36,909,000
                                                             ==========       ==========       ==========

</TABLE>




          See accompanying notes to consolidated financial statements.

                                      F-8

<PAGE>

      SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:

For the year ended December 31, 1999:
-------------------------------------

The Company  issued  281,566  common shares valued at $250,000 to the ESOP.  The
change in accounts  payable from December 31, 1998 to December 31, 1999 excludes
this non-cash reduction of the liability.

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.

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

Cash paid during the year ended December 31:
<TABLE>
<CAPTION>


                                             1999          1998         1997
                                             ----          ----         ----
<S>                                           <C>           <C>         <C>

Interest                                 $12,978,000   $11,338,000   $3,297,000
                                         ===========   ===========   ==========

Income taxes                             $        --   $        --   $       --
                                         ===========   ===========   ==========
</TABLE>


                                      F-9

<PAGE>
                                  PANACO, Inc.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

              FOR THE YEARS ENDED DECEMBER 31, 1999, 1998, AND 1997


Note 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature  of  Business
------------------
PANACO,  Inc. and subsidiaries (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.  The
Company's subsidiaries are consolidated as wholly-owned subsidiaries.

Revenue Recognition
-------------------
The Company  recognizes  its  ownership  interest in oil and gas  production  as
revenue.  Gas  balancing  arrangements  with  partners  in natural gas wells are
accounted for by the entitlements method. At December 31, 1999 and 1998 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 swap  contracts and put options  within the normal course of
its  business.  The Company  uses swap  contracts  and put options to reduce the
effects of  fluctuations  in oil and natural gas prices (see Note 7). To qualify
as  hedging  instruments,  swaps or put  options  must be highly  correlated  to
anticipated  future  sales  such  that  the  Company's  exposure  to the risk of
commodity  price  changes  is  reduced.  Changes  in the  market  value  of swap
contracts  or put  options  that are  designated  as  hedges  are  deferred  and
subsequent gains and losses are recognized monthly as adjustments to revenues in
the same production period as the hedged  production.  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
initially  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.



                                      F-10
<PAGE>

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
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
approved  reserves.  The Company  recorded an asset  impairment in 1999 of $13.2
million for unproved  properties  that the Company did not have current plans to
develop and for a reserve  reduction in the High Island 309 Fields.  The Company
also  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 1999, 1998 and 1997 was $544,000, $936,000
and $513,000, 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.


                                      F-11

<PAGE>

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.  In 1999 and 1998 the  Company  had options
outstanding that were  exercisable at prices above the market.  Due to losses in
1999 these shares are not considered  dilutive and are not included in per share
calculations.

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, 1999 and 1998  accounts  receivable  are net of an allowance of
$830,000  and $1 million,  respectively.  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
         ------------

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.

                                      F-12

<PAGE>

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.

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

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
$337,000,  $275,000 and $165,000 in costs for the years ended December 31, 1999,
1998 and 1997, 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 RLI,  Underwriter's
Indemnity.  This trust required an initial funding of $846,720 in December 1996,
and  remaining  deposits of $250,000  due at the end of each  quarter  until the
balance  in  the  account  reaches  $5.4  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.

                                      F-13

<PAGE>


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

<TABLE>
<CAPTION>
                                        1999           1998
                                        ----           ----
<S>                                     <C>              <C>

10 5/8 % Senior Notes due 2004(a)   $100,000,000   $100,000,000
Revolving credit facility due 2001(b) 36,653,000     13,500,000
Production payment(c)                  2,249,000      2,249,000
                                     -----------    -----------
                                     138,902,000    115,749,000

Less current portion                          --     13,500,000
  Long-term debt                    ------------   ------------
                                    $138,902,000   $102,249,000
                                    ============   ============
</TABLE>

------------
(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
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 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.  The  holders  of  the  Senior  Notes  have
acceleration  rights,  subject to certain  grace  periods,  if the Company is in
default under the credit facility.

(b) In October 1999 the Company put in place a new credit facility.  The loan is
a reducing  revolver  which will  provide  the Company  with up to $60  million,
depending on the borrowing  base.  The Company's  borrowing base at December 31,
1999 was $55.1 million, with availability of $16.2 million. The principal amount
of the loan is due  September  30, 2001,  and may be extended for an  additional
year.  Interest on the loan is computed at Wells  Fargo's prime rate plus .5% to
3.0%,  depending  on the  percentage  of the  facility  being  used.  The Credit
Facility is collateralized by a first mortgage on the Company's properties.  The
loan agreement contains certain covenants including an EBITDA (as defined in the
agreement)  to  interest  expense  ratio  of at least  1.5 to 1.0 and a  working
capital  ratio (as defined in the  agreement)  of at least .25 to 1.0.  The loan
agreement also contains limitations on additional debt,  dividends,  mergers and
sales of assets.

The  Company's  previous  credit  facility  was more  restrictive  and  included
covenants  that the Company was not in  compliance  with at December  31,  1998.
These covenant violations were remedied by waivers,  but the Company most likely
would not have been in  compliance  with  them for the  entire  year had the new
credit  facility  not been put in place.


                                      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 1999 the Company replaced its credit facility, see Note 5. In connection with
the  prepayment  of the  previous  credit  facility,  the Company  wrote off the
remaining deferred financing costs associated with the previous facility.

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

During 1997,  1998 and 1999, the Company hedged a portion of its oil and natural
gas production in accordance with its hedging policy and as a requirement of its
credit facilities.  During these periods, the hedges entered into by the Company
were either  swaps or cost free  collars.  The swaps were  agreements  to sell a
certain  quantity of oil or natural gas in the future at a predetermined  price.
Cost free collars ensured that the Company would receive a  predetermined  range
of prices for its products.

<TABLE>
<CAPTION>

                    Volume Hedge            Percentage of Actual Production
        Year   Natural Gas (BCF) Oil (MBbl)       Natural Gas   Oil             Gain/(Loss)
        ----   ----------------------------       ------------------            -----------

        <S>      <C>               <C>               <C>         <C>                <C>

        1997        5.1             263              45%         51%           ($1.3 million)
        1998       12.0             463              67%         52%            $2.5 million
        1999        8.8             540              79%         46%           ($4.6 million)
</TABLE>

For the year 2000, the Company has purchased  options to put oil and natural gas
produced to a purchaser  at an agreed upon price.  The natural gas put option is
for 10,000  MMbtu per day at a NYMEX price of $2.04 per MMbtu.  The Company paid
$366,000 for the put option  which will be amortized  over the period the hedged
item is produced,  fiscal year 2000.  The oil put option is for 1,000 barrels of
oil per day  beginning  March 1 and  continuing  through  December 31 at a NYMEX
price of $20.00 per barrel.  The oil put option cost  $275,000  and will also be
amortized  over the period the hedge item is  produced,  fiscal  year 2000.  The
Company  also has a small swap in place on an average of 232  barrels of oil for
each day at $17.00 per barrel. At December 31, 1999 the fair value of all of its
hedges was a loss of  $800,000.  The fair values of its hedges on  December  31,
1998 and 1997 was a gain of $1.8 million and a loss of $61,000, respectively.


                                      F-15

<PAGE>

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, 1999
and 1998. A 10% change in commodity  prices would not have a material  change in
the fair value of our hedging instruments.

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 when the exercise  price is equal to or greater than the market value of
the Company's  common stock on the date of an options  grant.  On June 18, 1997,
1.2 million  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.

<TABLE>
<CAPTION>
                                             1999                    1998                       1997
                                     ---------------------   ----------------------    ---------------------

                                                    Wtd.                     Wtd.                      Wtd.
                                                    Avg.                     Avg.                      Avg.
                                      Shares     Ex. Price    Shares      Ex. Price     Shares      Ex. Price
                                      ------     ---------    ------      ---------     ------      ---------
<S>                                     <C>          <C>       <C>           <C>         <C>          <C>
Outstanding at beginning of year     1,150,000    $  4.45    1,190,000    $  4.45       289,365    $  2.21
Granted                                      0         --            0         --     1,200,000       4.45
Exercised                                    0         --            0         --      (289,365)      2.21
Forfeited                                   --       4.45      (40,000)      4.45       (10,000)      4.45
                                     ---------      -----    ---------      -----     ---------      -----
Outstanding at end of year           1,150,000       4.45    1,150,000       4.45     1,190,000       4.45

                                     ---------               ---------                ---------
Exercisable at end of year           1,150,000    $  4.45    1,150,000     $ 4.45     1,190,000    $  4.45
Fair value of options granted              N/A                     N/A                  $  1.42

</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-year              3
                               Risk-free interest rate              6.1%
                               Dividend yield                         0%
                               Volatility                          38.4%


                                      F-16

<PAGE>

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 1999 and 1998
would have been as shown below:
<TABLE>
<CAPTION>
                                                  1999               1998
                                              ------------       ------------
        <S>                                     <C>                    <C>

     Net loss                As reported      $(35,027,000)      $(46,851,000)
     --------                Pro forma        $(35,311,000)      $(47,133,000)

     Net per share:          As reported      $      (1.46)      $      (1.96)
     -------------           Pro forma        $      (1.47)      $      (1.97)
</TABLE>


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

In 1999, the purchaser for a majority of the Company's oil production  accounted
for 37% of total  revenues in 1999,  while the  purchaser  for a majority of the
Company's  gas  production  accounted  for 39% of total  revenues  in 1999.  One
purchaser accounted for 42% and 62% of revenues in 1998 and 1997,  respectively.
These transactions represented spot sales of natural gas to one customer.

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

At December  31, 1999,  the Company had net  operating  loss carry  forwards for
federal income tax purposes of approximately $104 million which are available to
offset future federal  taxable income through 2019. The Company's  timing of its
utilization of a portion of its 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's common stock.

Significant  components of the Company's deferred tax assets (liabilities) as of
December 31 are as follows:
<TABLE>
<CAPTION>
                                                     1999             1998
                                                  ----------       -----------
        <S>                                     <C>                    <C>
Deferred tax assets (liabilities)
    Fixed asset basis differences               $(10,119,000)     $  (388,000)
    Net operating loss carry forwards             36,309,000       14,207,000
    State Taxes                                    2,486,000        1,461,000
    Other                                            297,000          410,000
                                                 -----------      -----------
        Total deferred tax assets (liabilities)   28,973,000       15,690,000
                                                 -----------      -----------
Valuation allowance for deferred
    tax assets                                   (28,973,000)     (15,690,000)
                                                 -----------      -----------
        Total deferred tax assets (liabilities)  $        --      $        --
                                                 ===========      ===========
</TABLE>

At December 31, 1999 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 $13,283,000.


                                      F-17
<PAGE>

Total  income  taxes were  different  than the amounts  computed by applying the
statutory  income tax rate to income before  income taxes.  The sources of these
differences are as follows:
<TABLE>
<CAPTION>
                                                   1999            1998
                                                  ------          ------
<S>                                                <C>              <C>

Before any valuation allowance
   Statutory federal income tax rate              (35.00%)       (35.00%)
   State income taxes, net of federal benefit      (2.92)         (2.92)
   Other                                            0.00           0.31
   Adjustments to valuation allowance              37.92          31.40
                                                   -----          -----
                                                    0.00%         (6.21%)
                                                   =====          =====
</TABLE>

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

An action was filed against the Company in Louisiana,  along with 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  indemnity
rights against NEG is currently  stayed.  The Company's Counsel has 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  ability to satisfy  the  judgement  is
questionable because of the bankruptcy.

Pursuant to another  purchase and sale agreement,  the Company may owe indemnity
to Shell and Exxon,  from whom it acquired the property prior to selling same to
NEG.  The Company may have  insurance  coverage  for the claims  asserted in the
petition,  and has notified all insurance  carriers that might provide  coverage
under its 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.

The Company is subject to various other 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, 1999, the future minimum rental payments due under the lease are
as follows:

                  2000                              $  336,000
                  2001                              $  389,000
                  2002                              $  102,000
                                                    ----------
                  Total                             $  827,000
                                                    ==========

                                      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:
<TABLE>
<CAPTION>

                                            1999          1998          1997
                                         ---------     ----------    ----------
<S>                                         <C>             <C>          <C>

Property acquisition costs, proved     $        --    $ 9,877,000   $39,384,000

Property acquisition costs, unproved       544,000      1,245,000     6,026,000

Exploration expenses                     2,479,000      7,582,000       353,000

Development costs                       24,777,000     29,957,000    29,276,000
</TABLE>


Quantities of Oil and Gas Reserves
----------------------------------
The estimates of proved reserve  quantities at December 31, 1999, 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.

<TABLE>
<CAPTION>
Proved developed and undeveloped reserves:                    Oil           Gas
                                                             (BBLS)        (MCF)
                                                             ------        -----
<S>                                                           <C>           <C>

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

   Production                                             (1,170,000)   (11,114,000)
   Extensions and discoveries                                123,000     13,975,000
   Sale of minerals in-place                                 (50,000)      (700,000)
   Revisions of previous estimates                         2,336,000       (642,000)
                                                          ----------     ----------
Estimated reserves as of December 31, 1999                 8,693,000     82,768,000
                                                          ==========     ==========



                                      F-19

<PAGE>

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

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

   December 31, 1999                                       5,351,000     40,627,000
                                                          ==========     ==========
</TABLE>

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, 1999 averaged $24.99 per barrel of
oil and $2.43 per Mcf 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>
                                                    1999             1998             1997
                                                 ----------       ----------       ----------
<S>                                             <C>                <C>              <C>

Future cash inflows                            $ 420,060,000    $ 259,071,000    $ 269,141,000
Future development and production costs         (167,631,000)    (129,744,000)    (102,114,000)
                                               -------------    -------------    -------------
Future net cash flows                            252,429,000      129,327,000      167,027,000
10% annual discount                              (71,163,000)     (34,747,000)     (37,995,000)
--                                             -------------    -------------    -------------
Pretax PV-10 value                               181,266,000       94,580,000      129,032,000
Future income taxes, discounted
 at 10%                                                   --               --       (8,160,000)
                                               -------------    -------------    -------------
Standardized measure after income taxes        $ 181,266,000    $  94,580,000    $ 120,872,000
                                               =============    =============    =============

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:

                                                    1999             1998             1997
                                                 -----------      -----------      -----------

Beginning balance                               $ 94,580,000    $ 120,872,000    $  99,841,000
Sales of oil and gas, net of production costs    (23,632,000)     (30,692,000)     (25,815,000)
Net change in income taxes                                --        8,160,000        5,465,000
Changes in price and production costs             59,928,000      (42,711,000)     (32,461,000)
Purchases of minerals in-place                            --       23,657,000       40,027,000
Sale of minerals in-place                         (1,037,000)        (514,000)              --
Revision of previous estimates, extensions &
 discoveries, net                                 51,427,000       15,808,000       33,815,000
                                                ------------    -------------    -------------
Ending balance                                  $181,266,000    $  94,580,000    $ 120,872,000
                                                ============    =============    =============

                                      F-20
</TABLE>


<PAGE>