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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, 2000

           [   ] 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 $40,873,355 as of March 19, 2001.

         24,323,521  shares of the registrant's  Common Stock were outstanding
         as of March 19, 2001.

                      Documents Incorporated by Reference

     Portions of the registrant's annual proxy statement, to be filed within 120
days after December 31, 2000, are incorporated by reference into Part III.

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PANACO, Inc.

Annual Report on Form 10-K
For the Fiscal Year Ended December 31, 2000

Table of Contents

Part I

Item 1.  Business.                                                             2
Item 2.  Properties.                                                          17
Item 3.  Legal Proceedings.                                                   22
Item 4.  Submission of Matters to a Vote of Security Holders.                 23

Part II

Item 5.  Market for Common Stock and Related Shareholder Matters.             23
Item 6.  Selected Financial Data.                                             27
Item 7.  Management's Discussion and Analysis of Financial Condition
          and Results of Operations.                                          27
Item 7a.  Qualitative and Quantitative Disclosure About Market Risks.         34
Item 8.  Financial Statements and Supplementary Data.                         35
Item 9.  Changes in and Disagreements with Accountants on Accounting
          and Financial Disclosure.                                           36

Part III

Item 10.  Directors and Executive Officers of the Registrant.                 36
Item 11.  Executive Compensation.                                             36
Item 12.  Security Ownership of Certain Beneficial Owners and Management.     36
Item 13.  Certain Relationships and Related Transactions.                     36

Part IV

Item 14.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K.   36

Glossary of Selected Oil and Gas Terms                                        39
Signatures                                                                    42


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                                     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.  For  information
concerning  some  of the  most  significant  risks  which  may  affect  PANACO's
operations,  see "Risk Factors." 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 cannot  assure  you that the  actual
results 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
and two former  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 39. 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  surrounding the Gulf, which we collectively refer
to as the Gulf Coast  Region.  We are in the business of selling oil and natural
gas,  produced on  properties  we lease,  to third party  purchasers.  We obtain
reserves  of crude oil and  natural  gas by either  buying  them from  others or
drilling developmental and exploratory wells on acquired properties. We acquired
our  first  property  in the Gulf of  Mexico in 1991,  and have  acquired  other
properties in the Gulf Coast Region and Gulf of Mexico in every year, except for
1999,  from 1994 through  2000. We have grown not only through  acquisitions  in
each of those  years  but also by  further  developing  the  properties  we have
acquired.  We have acquired  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 of the Goldking Companies in 1997.

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 property acquisitions which
are  described  below,  we have an  inventory  of  development  and  exploration
projects  that provide  additional  reserve  potential.  The key elements of our
objectives are outlined as follows.


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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,  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
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 ownership
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.  Below
are highlights of some of our more significant acquisitions.

Price Lake Field

     We acquired  the Price Lake Field in April 1998 for $750,000 as a potential
development  field  in  addition  to its  exploration  prospects,  that 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 spud 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.  The Sturlese  Estate #1 began  production  in September  1999 once
production  facilities  were  completed.  We  drilled  and  completed  a  second
exploratory well in the Price Lake Field, the Sturlese Estate #3, in March 2000.
The Sturlese Estate #3 also encountered producing formation in the MA-24 sand in
addition  to the MA-23  sand.  We own  51.2% of both of these  wells and are the
operator of the Field.  We are  currently  reviewing  seismic and other data for
other potential  wells to be drilled.  We currently have a new well in the Price
Lake Field in our 2001 budget.

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


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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
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.  Since 1997,  we have  developed  several of the
properties  acquired from Goldking,  the largest of which was the Umbrella Point
Field.  We drilled and completed two wells in the Field,  the State Lease #74-10
well and the State Tract #87-12 well. The first was the State Lease #74-10 well,
which was  completed in February 1998 and produced as much as 27 MMcf of natural
gas and 260 barrels of condensate  per day. We completed a workover on this well
in December  1999 and increased  production  back to over 19 MMcf of natural gas
and 176 barrels of condensate  per day. The second  development  well, the State
Tract  #87-12 well was  completed  in January 2000 and has produced as high as 6
MMcf per day of natural  gas. We own an 80% working  interest in these two wells
and a 100% working  interest in the rest of the Field.  Current  production from
the Umbrella Point Field is 6,500 Mcf and 320 barrels of oil per day.

Amoco Acquisition

     In October 1996 we acquired  interests  in six  offshore  fields from Amoco
Production  Company,  now BP Amoco  ("BP").  We paid BP $32  million in cash and
issued  them  2  million  shares  of  common  stock  in  consideration  for  the
properties.  All of the  properties  we acquired  from BP are  operated by third
parties, which are Unocal, Texaco, Coastal Oil and Gas and Newfield Exploration.

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 and 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  identified  several  developmental  and  exploratory  drilling
locations on blocks 109 and 110.  During 2000 we drilled  three new  exploratory
wells on Block 110, two of which were  completed  and  continue to produce,  the
A-11 and A-12 wells.  The initial  production from the A-11 well was 6.1 MMcf of
natural  gas and 73 barrels of  condensate  per day and began  producing  in mid
October.  The A-12 well began  producing in early December at a rate of 3.0 MMcf
of natural gas and 10 barrels of condensate  per day. The third well reached the


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targeted  zone in late December and appeared to contain  hydrocarbons.  However,
upon  preparation and completion the well was determined to be unproductive  and
was abandoned.

     In January 2001 the fourth exploratory well was drilled and completed.  The
A-7 well  began  producing  at 5.8 MMcf of  natural  gas per day.  We have  five
additional projects scheduled for 2001 in East Breaks 109 and 110, which account
for over  one-half of our  capital  budget for the year.  We own a 100%  working
interest in both blocks and we are the  operator.  Current  production  from the
entire  Field is 11,000  Mcf and 70 barrels of  condensate  per day.  Production
before the drilling program began was 2,000 Mcf and 10 barrels of condensate per
day.

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,
2000, 33% 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.

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 20 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  coastline 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.

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.
Historically  we have  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  East
Breaks 109 and 110 wells.  Our  exploratory  inventory is unique in that many of


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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 a large percentage 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 and led to several new wells completed in 2000.

Significant Operating Control

     We operate 82% 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
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  50  productive  offshore  wells  and  own  all of the  working
interests in a majority of those wells. Third party operators,  including Unocal
Corporation,  Coastal Oil & Gas Corp.,  Newfield Exploration,  Texaco,  Anadarko
Petroleum  Corporation  and  Burlington,  operate  our 48  remaining  productive
offshore  wells.  We also operate 51 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.


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     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
Geosciences  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.  We own
our own seismic  interpretation  workstations and data processing  equipment and
utilize the services of outside firms to process and interpret 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 BP. BP has a call on all of the oil production
from our properties  acquired from BP at their posted prices.  If we have a bona
fide offer from a crude oil  purchaser at a higher price than BP's posted price,
then BP must  match  that  price or  release  the  call.  Oil  from  the  Zapata
Properties  is  currently  being  sold to Unocal  and BP, 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 23% of our  total oil and  natural  gas  revenues  in 2000.  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


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this,  natural gas purchased by Enron North  America Corp.  accounted for 39% of
our total oil and natural gas revenues in 2000.  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  $20
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 and East Breaks 109 and 110 Fields

     In both the West Delta  Fields and the East Breaks 109 and 110  Fields,  we
have established an escrow in favor of the surety bond underwriter, who provides
a surety bond to the former  owners of the West Delta Fields and to the MMS. The
balance in this  escrow  account  was $3.5  million  at  December  31,  2000 and
requires  quarterly  deposits of $250,000 until the account balance reaches $6.3
million.

East Breaks 165 Fields

     In the East Breaks 165 and 209 Fields we have established an escrow account
in favor of the surety bond  underwriter,  who provides surety bonds to both the
MMS and the former owner of the Fields.  The balance in this escrow  account was
$4.4 million at December 31, 2000 and  requires  quarterly  deposits of $250,000
until the account balance reaches $6.5 million.

BP Properties

     We have also  established  an escrow  account in favor of BP under which we
will  deposit 10% of the net cash flows from the  properties,  as defined in the
agreement, from the properties acquired from BP. This escrow account balance was
$0.7 million at December 31, 2000.

     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 $100 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 $100 million for wells in federal offshore waters.
The amounts are proportionately reduced if we own less than 100% of the well. We
also maintain $147 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


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<PAGE>

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 Cerberus 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 two additional  six month  periods,  at our sole option.  We are
reviewing  alternatives  to extending this agreement,  including  replacing this
Credit  Facility  with a bank  facility.  Management  believes that if we do not
choose to renew the existing facility,  that we would be able to replace it with
one that provides acceptable terms.

     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 $19.4
million  outstanding at December 31, 2000. We will continue to use this Facility
in 2001 to fund part of our $37.1 million capital budget.

     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, 2000 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.


                                       9

<PAGE>

     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.

     In August of 2000, we were informed that High River Limited Partnership,  a
Delaware limited  partnership ("High River"),  had purchased a sufficient number
of  additional  shares  of  common  stock to be a Change  of  Control  under the
Indenture,  thus  requiring  the  Company to make a Change of Control  Offer for
Senior  Notes.  High River is an  affiliate  of Carl C. Icahn,  whose  aggregate
ownership of Company common stock with his affiliates  after the acquisition was
6,545,400  shares  or 26.9% of the  outstanding  common  stock.  Pursuant  to an
agreement  with the  Company,  in October of 2000 High River  purchased  all the
Senior  Notes  tendered,  increasing  High  River's  ownership  in the  Notes to
approximately  99%  of  the  $100  million  principal  amount  of  Senior  Notes
outstanding.

     The Indenture  contains  certain  restrictive  covenants  that limit us to,
among other  things,  incurring  additional  indebtedness,  paying  dividends or
making  certain other  restricted  payments,  consummating  certain asset sales,
entering into certain  transactions  with  affiliates and incurring  liens.  The
Indenture also restricts us from merging or consolidating  with any other person
or selling, assigning,  transferring,  leasing, conveying or otherwise disposing
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,  2000 with the
covenants contained in the Indenture.

Common and Preferred Stock

     On December  31, 2000 we had issued and  outstanding  24,323,521  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
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  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



                                       10

<PAGE>

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.

     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  the 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 BP Properties,  will generally sell their natural gas for
as much as $.12 below the index price.

     ENVIRONMENTAL  AND OTHER  REGULATION.  Governmental  laws and  regulations,
including price control, energy, environmental, conservation, tax and other laws
and regulations  relating to the petroleum  industry,  affect our business.  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 has 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
operations of federal  leases.  The Federal Energy  Regulatory  Commission  (the


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<PAGE>

"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  Minerals  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."


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<PAGE>

Employees

     We have 37 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.

Risk Factors

     The  Company's  business  and the  results of  operations  are  affected by
numerous  factors  and  uncertainties,  many of which are  beyond  our  control.
Following  is a  description  of some of the  factors  that could  cause  actual
results of operations in the future to differ  materially  from those  currently
experienced or expected.

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 acquire 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  incurred  significant  losses  in 1999 and  1998 and are  significantly
leveraged.  Our long-term  debt balance at December 31, 2000 was $121.7  million
and our  stockholders'  equity was $12.4 million.  A large part of our losses in
prior  years  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
cannot 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."


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<PAGE>

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."

Uncertainty of Estimates of Reserves and Future Net Cash Flows

     The basis for the success and long-term  continuation of our Company is the
price 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,  2000  and  use  costs  for  operating  and  capital
expenditures  in effect at that same time.  These  assumptions  are then used to
calculate a future cash flow stream that is discounted at a rate of 10%.

     The base  prices  used for the Pretax  PV-10  calculation  were public spot
prices on December 31 adjusted  by  differentials  to those spot market  prices.
These  price  adjustments  were  done on a  property-by-property  basis  for the
quality of the oil and natural  gas and for  transportation  to the  appropriate
location. The average prices in the Pretax PV-10 value at December 31, 2000 were
$9.65 per Mcf of natural  gas and $26.60  per barrel of oil.  Currently,  we are
selling our oil production  for slightly  higher than the prices at December 31,
2000 and our  natural  gas  production  for much less.  Based on current  market
conditions,  we are projecting that our 2001 average realized prices for oil and
natural gas average approximately $26.96 and $5.62, respectively.


                                       14

<PAGE>

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  Acquisitions.  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 the 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
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, 2000,  one
natural gas purchaser accounted for approximately 39% of our oil and natural gas
revenues.  Also, in 1999 we consolidated a majority of our oil production to one
oil  purchaser,  who  accounted  for 23% of our oil and natural gas  revenues in
2000. 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.
During 1999 our  largest oil  purchaser  and our largest  natural gas  purchaser
accounted  for 37% and 39%,  respectively,  of total oil and  natural gas sales.
During 1998 our largest natural gas producer  accounted for 42% of total oil and
natural gas sales.


                                       15

<PAGE>

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 counterparty all or a portion of this difference  multiplied
by the quantity hedged.

     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 2001, our hedges are composed of options to
put oil to a purchaser  at a fixed price and swaps on natural  gas. See Item 7a,
"Qualitative and Quantitative Disclosure About Market Risks."

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, 2000, our total estimated abandonment
costs, net of $8.6 million already in escrow,  were approximately $11.7 million.
We  account  for  those  future   liabilities   by  accruing  for  them  in  our
depreciation,  depletion  and  amortization  expense  over  the  lives  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
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


                                       16

<PAGE>

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 cannot
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 ours.

Item 2.  Properties.

     At December 31, 2000 our Proved Reserves  totaled 131 Bcfe and had a Pretax
PV-10  value  of  $532.9  million.  Approximately  67%  of  these  reserves  are
classified as Proved Developed  Reserves and  approximately 63% 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 78 producing oil wells and 76 producing  natural gas
wells.  We also own  interests in 20 federal  blocks in the Gulf of Mexico and 9
state water blocks and we operate 78% of the 98 producing  offshore wells, based
upon the Pretax  PV-10 value as of December  31, 2000.  Large  independents  and
major oil companies,  including Unocal, Newfield,  Texaco, Coastal, Anadarko and
Burlington,  operate our  non-operated  offshore  properties.  Our 61  producing
onshore wells account for 18% of our total Pretax PV-10 value as of December 31,
2000. We operate 97% of our onshore  wells,  based upon such Pretax PV-10 value.
We also own  interests  in 20  offshore  production  platforms  and 109 miles of
offshore oil and natural gas pipelines with diameters of 10" or larger. In 2000,
our  properties  yielded net  production to PANACO of 1,070,000  Bbls of oil and
condensate and 13,547,000 Mcf of natural gas.

     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.


                                       17

<PAGE>

     The following is a summary of our significant properties as of December 31,
2000. These properties  represent 82% of the aggregate Pretax PV-10 value of our
Proved Reserves.

<TABLE>
<CAPTION>
                                       Total Proved Reserves
                        ----------------------------------------------------           % of
                                                                Pretax PV-10       PANACO Total
   Field                Oil (MBbls)      Natural Gas (Bcf)       Value(000s)        Pretax PV-10
------------------------------------------------------------------------------------------------
<S>                        <C>               <C>                   <C>                <C>
West Delta                  527              14.1               $ 102,958               19%
East Breaks 109             111              15.5                 102,936               19
East Breaks 165           3,268              18.3                  89,537               17
Umbrella Point            1,070               6.9                  47,229                9
East Breaks 160             934               8.1                  47,175                9
Price Lake                  120               5.5                  45,242                9
------------------------------------------------------------------------------------------------
          Total           6,030              68.4               $ 435,077               82%
</TABLE>

West Delta

     PANACO  acquired the West Delta  Fields in May 1991 from  Conoco,  Atlantic
Richfield Company (now BP), Oxy USA, Inc. and Texaco  Exploration and Production
Company.  These Fields consist of 13,565 acres in Blocks 52 through 56 and Block
58 in  the  West  Delta  area  offshore  Louisiana.  The  Field  was  originally
discovered  in the mid 1950s and has  continued  to produce  hydrocarbons  since
then.  West Delta  continues to have  drilling  and other  activity in the area.
These are currently approximately 40 total wells in the Field which produce from
depths  ranging from 1,200' to 17,000'.  We operate the Field and  generally own
100% of most wells. The production  facility is a four-platform  complex located
in Block 54 in water that ranges in depth from six to fifteen feet.  During 1996
we rebuilt a  significant  portion of the  production  facilities  after  damage
caused by a third party. We spent a total of $8.5 million on rebuilding,  and we
received $3.9 in reimbursement  under our insurance  policies.  The unreimbursed
portion of the  rebuilding  related to  upgrading  the  facilities  to allow for
increased production and more efficient operations.  During 2000 we also settled
a claim for $1 million with that third party's  insurance  carriers for the time
value of the production lost during the rebuilding.

     The  geology is  characterized  by  multiple  reservoirs,  which we believe
provides more opportunities for successful drilling activities. Proved Producing
Reserves are based on establishing consistent producing history. The Behind Pipe
Reserves are generally  uphole  recompletion  with reserves  based on volumetric
estimates.  Fiscal 2000 continued to be an active year at West Delta, with three
completed  development  wells by PANACO and four exploratory wells being drilled
under a farmout agreement with Basin Exploration, three of which were completed.
The three new wells that we  completed  were  typical  for the Field in that the
wells were all set up to produce in several zones during the lives of the wells.
The wells were all drilled in Block 54 and they continue to produce.

     We have also allowed third party operators to drill on our Block 58 acreage
in West Delta under farmout  agreements.  Typically these agreements provide for
PANACO to receive an overriding royalty interest, with an optional back-in after
payout in addition to processing fees for the production and handling.

     During  2000 Basin  Exploration  drilled  four wells in Block 58,  three of
which were completed.  Generally,  we have overriding  royalty interests ranging
from 10% to  12.5%.  Under the Basin  agreement  we  received  a  prepayment  of
processing fees for the five-year term of the processing agreement.  In addition
to  the  $1.8  million   prepayment  we  receive  some   incremental   fees  and
reimbursement  of expenses as the wells produce.  During 1997 and 1994 we farmed
out other  acreage in Block 58 to El Paso Energy and Samedan,  respectively.  We
also  received  interest in these wells in addition to fees for  processing  and
handling production from their wells.


                                       18

<PAGE>

East Breaks 109

     We acquired  the East Breaks 109 and 110 Fields in July 1995 as part of the
Zapata  Acquisition,  for information  regarding the East Breaks 109 field,  see
"Business Strategy - Zapata Acquisition."

East Breaks 165

     In May  1998 we  acquired  the  East  Breaks  165  Field,  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  five-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
19,000 Mcf of natural  gas and 176 barrels of oil per day. We own an 80% working
interest in the well.  Peoples Energy Production owns the remaining 20%. Current
production from the Umbrella Point Field is 6,500 Mcf and 320 barrels of oil per
day.

     In late 2000,  we entered into an  agreement  with the owner of an adjacent
block in which both parties have agreed to farmout acreage to the other party in
order to develop a  reservoir  that  extends  under  both  blocks.  The  farmout
agreement  also  provides  us with a  partner  in order to  reduce  our costs of
drilling  the well,  which is  exploratory.  We have  budgeted  a new well to be
drilled  under this  agreement in mid-2001.  This new well will be a test of the
Vicksburg sand and will be drilled on from the block on our acreage. We will own
a 40% working interest in this well and will be the operator.

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.  Unocal  operates  the Field 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.


                                       19

<PAGE>

     We also receive processing fees from BP from 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  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,  Kerr-McGee  and
Devon 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.

Price Lake

     We  acquired  the Price  Lake  Field in April  1998,  for more  information
regarding the Price Lake Field, see "Business Strategy-Price Lake Field."


                                       20

<PAGE>

Oil and Gas Information

     Third party  engineering  firms use  information we provide them to prepare
our reserve  estimates.  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 85% of the Pretax  PV-10 of our reserve  estimates.  Our proved oil reserves
totaled 8.1 million barrels at December 31, 2000 compared to 8.7 million barrels
at December  31,  1999.  Our proved  natural gas  reserves  totaled  82.2 Bcf at
December 31, 2000 as compared to 82.8 Bcf at December 31, 1999. The Pretax PV-10
value of these  reserves  totaled $533 million at December 31, 2000  compared to
$181 million at December 31, 1999. 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.

                               Producing Wells(a)

     The  following  table  presents the number of producing oil and natural gas
wells attributable to our properties, as of December 31, 2000.

<TABLE>
<CAPTION>
                                                            Producing Wells        Company Operated
                                                            ---------------        ----------------
        <S>                                                      <C>                     <C>

    Gross producing offshore wells(b):
        Oil    .........................................         25                      25
        Natural Gas   ..................................         73                      25
                                                                ---                     ---
         Total  ........................................         98                      50
    Net producing offshore wells(c):
        Oil    .........................................         23                      23
        Natural Gas   ..................................         37                      24
                                                                ---                     ---
         Total  ........................................         60                      47
    Gross producing onshore wells(b):
        Oil    .........................................         53                      51
        Natural Gas   ..................................          8                       8
                                                                ---                     ---
         Total  ........................................         61                      59

    Net productive onshore wells(c):
        Oil    .........................................         45                      44
        Natural Gas   ..................................          4                       4
                                                                ---                     ---
         Total  ........................................         49                      48
</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.

                                Leasehold Acreage

     The following table presents the estimated  developed acreage  attributable
to our properties, as of December 31, 2000.
<TABLE>
<CAPTION>
                <S>                                                                   <C>


     Developed onshore acreage(a):
             Gross acres(b).....................................................     3,625
             Net acres(c).......................................................     1,939

     Undeveloped onshore acreage(a):
             Gross acres(b).....................................................     2,698
             Net acres(c).......................................................     1,715

                                       21

<PAGE>


     Developed offshore acreage(a):
             Gross acres(b).....................................................    99,243
             Net acres(c).......................................................    47,616

     Undeveloped offshore acreage(a)(d):
             Gross acres(b).....................................................       320
             Net acres(c).......................................................       240
</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, 2000. 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>

1996          --          --           2         --            --          --       --         --
1997           6          13          --          1            --          --       --         --
1998           1           9          --         --            --           3       --          6
1999           1          --          --         --            --           4       --          3
2000          --           6          --         --            --           2       --          1
             ---         ---         ---        ---           ---         ---      ---        ---
Total          8          28           2          1            --           9       --         10

</TABLE>

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  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 PANACO and NEG, NEG is required to indemnify us from any
damages attributable to NEG's operations on the property after the sale.

     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 believe that we have insurance  coverage for the claims  asserted in the
petition,  and have notified all insurance  carriers that might provide coverage
under our policies.  In 1999 NEG filed for chapter 11 bankruptcy  and emerged in
late 2000.  Some  discovery  has occurred in the case,  but discovery is not yet


                                       22

<PAGE>

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.

     In August 2000,  an action was filed against the Company by Coastal Oil and
Gas  Corporation  (now El Paso  Corporation)  for  nonpayment of joint  interest
billing invoices.  The suit seeks to recover unpaid costs from a well drilled on
a property  operated  by El Paso.  PANACO  counter  sued  alleging,  among other
things,  gross misconduct and negligence in drilling the well. The case is still
in discovery and it is not possible to evaluate the likelihood of an unfavorable
outcome or to estimate the amount or range of potential loss in addition to what
we have already accrued.

     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,  2001  and are  held by over  6,700  shareholders,  based  upon
information available on individual security position listings.

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

     Each Common Share is entitled to participate  equally in dividends,  as and
when declared by the Board of Directors,  and in the  distribution  of assets in
the event of  liquidation,  subject in all cases to any prior  rights of secured
creditors and 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
non-assessable.

Warrants and Options

     We also have  outstanding  options to acquire  500,000  Common  Shares at a
price of $1.92 per share and expire August 17, 2006.  These options are all held
by current 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.


                                       23

<PAGE>

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  2000,  our Common Shares have been traded on The American
Stock  Exchange  under the symbol  "PNO." Prior to that,  our Common Shares were
traded on the OTC  Bulletin  Board and on NASDAQ  under the symbol  "PANA." They
commenced  trading  September 21, 1989. The following table sets forth,  for the
periods indicated, the high and low closing prices for the Common Shares.

<TABLE>
<CAPTION>
                                                 2000
                                           ----------------

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


Low          $  0.34              $ 0.51                    $ 1.38              $ 2.38
High         $  0.96              $ 1.66                    $ 3.50              $ 3.75

                                                1999
                                          ----------------

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

Low          $ 0.88               $  0.56                   $ 0.53              $ 0.31
High         $ 1.19               $  1.19                   $ 1.03              $ 0.63

</TABLE>

     On March 19, 2001,  the last sale price of the Common  Shares was $2.62 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  requires  the  consent of the  lenders  and the Senior  Notes  contain
limitations on any dividends or 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, 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 $0.005 per Common Share.


                                       24

<PAGE>

     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 only the Board of Directors may call special meetings of shareholders,  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.

     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.



                                       25

<PAGE>

     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.  See
"Business - Senior Notes."


                                       26

<PAGE>

Item 6.  Selected Financial Data.

     The following  historical data is derived from the 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, Item 8.

<TABLE>
<CAPTION>

                                                                     For the Years ended December 31,
                                                      2000       1999        1998          1997        1996
                                                 -----------------------------------------------------------
                                                             (amounts in thousands, except per share data)

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

    Oil and natural gas sales                    $  88,550   $  42,672   $  50,291     $  37,841   $  20,063
    Gain on sale of assets                           1,938         ---         ---           ---         ---
    Lawsuit recoveries                               2,575         ---         ---           ---         ---
                                                 -----------------------------------------------------------

    Total revenues                                  93,063      42,672      50,291        37,841      20,063

    Total costs and expenses before income
       taxes and extraordinary item (1)             76,591      77,568     100,242        36,864      22,102

    Income tax benefit (2)                         (22,683)        ---      (3,100)          ---         ---

    Extraordinary item-loss on early
       retirement of debt                              ---         131         ---           934         ---
                                                 -----------------------------------------------------------

    Net income (loss) (3)                        $  39,155   $ (35,027)  $ (46,851)    $      43   $  (2,039)
                                                 ===========================================================

    Net income (loss) per Common Share           $    1.61   $   (1.46)  $   (1.96)    $     ---   $   (0.16)

    Total assets                                 $ 174,079   $ 135,438   $ 143,372     $ 179,629   $  73,768
    Long-term debt                               $ 121,693   $ 138,902   $ 115,749     $ 101,700   $  49,500
    Stockholders' equity (deficit)               $  12,408   $ (26,875)  $   7,902     $  55,188   $  17,498

</TABLE>

(1)  Results for the years ended December 31, 1999 and 1998 include  impairments
     of oil and gas properties of $13.2 million and $20.4 million, respectively.
(2)  During 2000 the deferred tax valuation allowance was reversed, resulting in
     an income tax benefit of $29  million,  see  "Management's  Discussion  and
     Analysis of Financial  Condition and Results of Operations."
(3)  No Common Share  dividends  have been paid in the  five-year  period ending
     December 31, 2000.  Results for each year presented may not  necessarily be
     comparative  due  to  numerous  acquisitions,   see  "Business  strategy  -
     Strategic Acquisitions and Mergers" for further discussion of acquisitions.

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.

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
and other  reports  that we file with the  Securities  and  Exchange  Commission


                                       27

<PAGE>

("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 cannot 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.

Liquidity and Capital Resources

     During  2000 we  focused  our  efforts  on  increasing  our cash flows from
operations  and reducing debt. Due to the short lived nature of our reserve base
and in order to implement  our strategy,  we invest a significant  amount of our
cash flows into capital  expenditures.  In addition to reducing outstanding debt
by $17.2  million in 2000,  we spent $37.2 million  drilling  developmental  and
exploratory wells and acquiring proved reserves.  We also deposited $2.4 million
into escrow  accounts,  which are held as  restricted  deposits  and are for the
eventual  plugging and abandonment of certain  offshore  properties that we own.
After the reduction of $17.2 million,  the amount  outstanding  under our credit
facility at  December  31, 2000 was $19.4  million.  We had in place  letters of
credit in the  amount of $7.5  million,  leaving  $31.8  million  available  for
capital expenditures and general corporate purposes.

     At December 31, 2000,  68% of our total assets were  represented by oil and
natural gas properties, pipelines and equipment, net of depreciation,  depletion
and amortization.

Working Capital

     To reduce  interest  costs,  we keep as little cash on hand as possible and
apply  available cash to our Credit Facility  balance.  The timing of receipt of
monies  due us,  the  payment  of  amounts  due  others  and  timing of  capital
expenditures also affect our working capital.  These factors caused us to have a
working capital deficit on December 31, 2000, of $16.6 million.  We believe that
our cash  flow from  operations  and  borrowing  availability  under our  Credit
Facility will be sufficient to fund this working  capital deficit in addition to
our ongoing operations, capital expenditures and additional reduction of debt.

     For the year 2001,  our Board of  Directors  has  approved a $37.1  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.

Financing Activities

     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. 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.


                                       28

<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,  along with  Foothill  Partners,  L.P.  and Ableco
Finance, a subsidiary of Cerberus 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 two additional  six month  periods,  at our sole option.  We are
reviewing  alternatives  to extending this agreement,  including  replacing this
Credit  Facility  with a bank  facility.  Management  believes that if we do not
choose to renew the existing  facility,  that we will be able to replace it with
one that provides acceptable terms. 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 $19.4 million outstanding at December 31, 2000.

     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, 2000 and
anticipate  compliance throughout the term of the loan.


                                       29

<PAGE>

                        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, 2000.

<TABLE>
<CAPTION>


                                                                 For the year ended December 31,
                                                     ------------------------------------------------------
                                                      2000                  1999                 1998
        <S>                                            <C>                  <C>                   <C>

   Oil and Condensate:
     Net production (Bbls)(a)                       1,070,000             1,170,000               895,000
     Revenue                                    $  32,396,000         $  22,025,000         $  10,916,000
     Hedge gains (losses)                       $    (710,000)        $  (1,784,000)        $   2,034,000
     Average net Bbl per day                            2,924                 3,204                 2,452
     Average price per Bbl before hedges        $       30.28         $       18.83         $       12.20
     Average price per Bbl including hedges     $       29.62         $       17.31         $       14.47

   Natural Gas:
     Net production (Mcf)(a)                       13,547,000            11,114,000            18,041,000
     Revenue                                    $  57,246,000         $  25,267,000         $  36,910,000
     Hedge gains (losses)                       $    (382,000)        $  (2,836,000)        $     431,000
     Average net Mcf per day                           37,000                30,400                49,400
     Average price per Mcf before hedges        $        4.23         $        2.27         $        2.05
     Average price per Mcf including hedges     $        4.20         $        2.02         $        2.07

   Total oil and natural gas sales              $  88,550,000         $  42,672,000         $  50,291,000

   Production costs                             $  20,876,000         $  17,740,000         $  18,148,000
     Total production (Mcfe)(b)                    19,966,000            18,132,000            23,411,000
     Production cost per Mcfe(b)                $        1.05         $         .98         $         .78

</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.

Results of Operations

Revenues

     One of the most  significant  factors  affecting our business is the market
price  of oil and  natural  gas  that we  produce  and  sell.  In late  1997 and
continuing  through early 1999,  both oil and natural gas prices were lower than
they had been in the proceeding years. A turnaround was seen in 1999 and through
2000 where we benefited from a steady increase in realized  prices.  The average
realized price,  net of hedges,  has increased 105% for oil and 103% for natural
gas from 1998 to 2000.

     Our oil and natural gas revenues  reached an all-time high of $88.6 million
in 2000, a 108% increase over 1999. Oil production decreased 9%, to 1,070 MBbls,
from 1,170 MBbls in 1999.  This decrease was more than offset by higher  average
realized oil prices. Including hedges, we realized a 71% increase in our average
price per barrel.  Natural gas prices also increased  dramatically in 2000, from
$2.02 per Mcf in 1999 to $4.20 per Mcf in 2000.  Coupled  with a 22% increase in
natural gas production, natural gas revenues increased to $56.9 million in 2000,
a 154% increase  over 1999.  For the first three  quarters of 1999,  our capital
spending decreased from the same periods in 1998. Once commodity prices began to
improve,  we increased spending in late 1999 and through 2000, which resulted in
increased production.


                                       30

<PAGE>


     Oil and natural gas revenues  were 15% lower in 1999 when compared to 1998.
While  average oil prices and  production  improved  20% and 31%,  respectively,
natural gas production  decreased 38% in 1999, while natural gas prices remained
relatively  flat.  As our  capital  spending  decreased  in 1999 from 1998,  our
natural gas production also decreased.

     During the fourth quarter of 2000 we sold two offshore properties resulting
in a gain of $1.9 million.

     Two lawsuits were settled during 2000 for which we received a total of $2.6
million.

Cost and Expenses

     Lease operating expenses ("LOE") totaled $20.9 million in 2000 versus $17.7
in 1999, and $18.1 million in 1998.  During 2000 we performed many workovers and
property repairs in conjunction  with our increased  capital  spending.  LOE for
2000  includes  $5.7  million  of  these   repair,   maintenance   and  workover
expenditures, as compared to $1.0 million for these same types of costs in 1999.
During 1999, LOE remained relatively flat versus 1998.

     Depletion,  depreciation and amortization  ("DD&A") increased 2% in 2000 to
$27.0  million,  compared to $26.4 million in 1999. The increase is due to a 10%
increase in total production,  upon which our depletion is calculated.  However,
this  increased  production  was  offset by a lower  depletion  rate per unit of
production,  from $1.46 per Mcf equivalent ("Mcfe") in 1999 to $1.35 per Mcfe in
2000.  The  decrease  in  depletion  per  Mcfe  is  primarily  due  to  property
impairments  in  1999  totaling  $13.2  million.  This  impairment  reduced  the
remaining  capitalized  costs to be depleted in 2000.  Likewise,  in 1999, while
total  production  decreased 23% when compared to 1998, DD&A decreased 30%, from
$37.5 million to $26.4 million.  This decrease is also due to a lower  depletion
rate per Mcfe of  production  in 1999,  of $1.46 as compared to $1.60 in 1998. A
property  impairment of $20.4 million in 1998 reduced the capitalized costs that
were depleted in 1999.

     General and administrative  expenses totaled $5.2 million, $4.1 million and
$4.6 million in 2000, 1999 and 1998, respectively.  The increase in 2000 of $1.1
million relates  primarily to $0.6 million of employee  bonuses paid in 2000, as
there were no bonuses  paid in 1999 and an increase in bad debt  expense of $0.2
million.  When  comparing  1999 to 1998,  the  decrease  is  primarily  due to a
decrease in bad debt expense of $1.0 million from 1998.

     Production and ad valorem taxes totaled $2.1 million, $1.2 million and $1.4
million in 2000, 1999 and 1998, respectively. These taxes vary from year to year
primarily  based on our production mix.  Production from offshore  properties is
not subject to production  taxes,  while onshore  properties  and those in state
waters are.  These taxes are based on the value of the sales from the production
or the number of units produced, depending on the location of the properties.

     Exploration expenses, including geological and geophysical expenses ("G&G")
increased  $3.2 million in 2000,  from $2.5 million in 1999 to $5.7 million.  As
our capital  spending  increased  in 2000,  we also  increased  our  exposure to
exploration  projects.  We believe that a balanced capital budget includes a mix
of higher  risk,  higher  reward  exploratory  projects  as well as  development
projects.  The increase of $3.2 million  relates to exploratory dry hole expense
recorded in three wells that were drilled in 2000,  the largest of which was the
A-10 well in the East Breaks 110 Field, which totaled $2.3 million. The decrease
of $5.1 million in 1999 is due to lower capital spending in that year.

     During  1999 we  recorded  an oil  and gas  property  impairment  of  $13.2
million,  which related to two property groups. Part of the impairment provision
related  to our  unproved  property  costs,  for  which we did not have  planned
development activity. The other part of the impairment provision was recorded in


                                       31

<PAGE>

connection  with a  reserve  reduction  on a  proved  property.  During  1998 we
recorded a provision for impairment of our oil and gas properties  primarily due
to historically  low market prices used in estimating the future  recoverability
of those properties' costs. During 2000 we did not record an asset impairment.

     During 2000 a former officer and director  resigned in accordance  with the
terms of his employment agreement. Under the terms of this agreement, the former
employee  received  two years of his salary in  addition to other  benefits.  We
recorded a $0.7 million charge in connection with the  resignation.  During 1998
we recorded a $1.0 million charge in connection  with the  consolidation  of our
Kansas City office into our Houston office in addition to severance  expense for
several employees that did not move to Houston.

     During  2000  net  interest  expense  increased  primarily  due  to  higher
borrowing levels under our Credit Facility.  Our weighted average interest rates
also increased due to two factors (1) a new Credit Facility put in place in late
1999 and (2)  increases  in the  prime  rate,  which is the base for our  Credit
Facility charges. Net interest expense increased in 1999 due to higher borrowing
levels under our Credit Facility.

Income Tax Benefit

     As oil and  natural  gas  prices  increased  during  2000,  we were able to
project  future  net  income  sufficient  to  utilize  our  net  operating  loss
carry-forwards.  As such,  during  2000 we recorded an income tax benefit of $29
million by reversing a valuation  allowance  recorded  against these assets.  We
also recorded an income tax expense  provision of $6.3 million during 2000 based
on pre-tax income for the year of $16.5  million,  resulting in a net income tax
benefit of $22.7  million in 2000. No income tax expense or benefit was recorded
in 1999.

Extraordinary Item

     During 1999 we recorded an  extraordinary  item for the early retirement of
long-term  debt.  This charge was recorded in connection  with the prepayment of
our Credit Facility. We put in place a new Credit Facility in September 1999.

Outlook

     As a  relatively  small,  leveraged  oil and  natural gas  exploration  and
production company, the success and outcome of our business are highly dependent
on oil and natural gas prices. Not only are our revenues, cash flows, results of
operations  and liquidity  impacted by commodity  prices,  our ability to obtain
financing for our business is also influenced by these prices. The nature of our
business is capital intensive,  typically requiring an investment up front and a
resulting  return on that  investment.  The resulting return and success of that
investment  will vary depending on the prices we receive for the oil and natural
gas. Also, due to the geographic  area that we operate in, the levels of capital
spending  are  significant  and  the  lives  of the  reserves  that  we own  are
relatively  short.  Historically,  our reserves  have a five to seven year life,
which tends to amplify oil and natural gas price fluctuations on our Company.

     For fiscal  2001,  our Board of  Directors  has  approved  a $37.1  million
capital budget. This budget includes  approximately $21.5 million of exploratory
projects,  the  majority  of which will be spent at our East  Breaks 109 and 110
Fields. To date in 2001, we have completed the first of these exploratory wells,
the A-7 well as a producing  natural gas well.  While this level of  exploratory
spending is higher than in previous years, based on current seismic and drilling
technology, we feel that these projects are also lower risk than the exploratory
projects we have historically participated in.

     In late 2000,  in  conjunction  with the  preparation  of our 2001  capital
budget,  natural gas prices were at much higher levels than had been in previous
years.  Based on a  recommendation  from  management,  the  Board  approved  the


                                       32

<PAGE>

execution of a swap agreement on approximately 40% of our estimated 2001 natural
gas production. The swap was put in place in late November 2000 and is in effect
from January 1 through December 31, 2001. We agreed to swap 18,000 MMbtu per day
at an average price for the year of $4.91.  The purpose of the swap is to ensure
a minimum level of revenues that would allow for debt service and the completion
of the entire $37.1 capital  budget.  To date in 2001, the market prices for our
natural gas have exceeded the fixed prices in the swap  agreement.  However,  by
having  approximately  60% of our natural  gas  production  "unhedged",  we have
benefited from the higher prices.  We also have in place an option to put oil to
a purchaser  for $25 per barrel on 1,000  barrels per day from January 1 through
September 30, 2001.  This  represents  approximately  39% of 2001  estimated oil
production.

     The  estimates  of the future net cash flows from our oil and  natural  gas
reserves  were  made by third  party  petroleum  engineers  in  accordance  with
Statement of Financial  Accounting  Standards No. 69, "Disclosures about Oil and
Gas Producing  Activities."  The prices used in preparing  these  estimates were
based on spot market  prices on December 31,  2000,  which  averaged  $26.60 per
barrel of oil and $9.65 per Mcf of natural gas.  These average  prices are based
upon  spot  market  prices  on  December  31 for each  property's  location  and
differential to those market prices.  You should not assume that these estimates
represent  the market  value for those  reserves,  nor should you assume that we
will achieve those results from our reserves.

     Currently,  we are selling our oil production for slightly  higher than the
prices at December 31, 2000 and our natural gas production for much less.  Based
on current market  conditions,  we project that our 2001 average realized prices
for  oil  and  natural  gas  will  average   approximately   $26.96  and  $5.62,
respectively.

     During  the first  quarter  of 2001 we will  recognize  approximately  $3.5
million of dry hole expense for the East Breaks 110 A-4 well.  The well was spud
on January 30, 2001 and reached total depth in early March. The well reached the
targeted  objective,  however,  the sand contained an  uncommercial  quantity of
hydrocarbons.

Change in Accounting Method

     In  accordance  with our  hedging  policy,  we  expect  to  continue  using
derivative financial instruments as a means of hedging prices we receive for our
oil and natural gas production. We have generally used swaps, collars or options
with  counter  parties  that are major  financial  institutions  or  commodities
trading  institutions.  Through  December  31,  2000 gains and losses from these
financial  instruments have been recognized in revenues for the periods to which
the production covered by the derivative financial instruments relate.

     Effective  January 1, 2001,  we adopted  Statement of Financial  Accounting
Standards No. 133 ("SFAS133"), Accounting for Derivative Instruments and Hedging
Activities,  and SFAS No. 138, Accounting for Certain Derivative Instruments and
Certain  Hedging  Activities,  an amendment  of FASB  Statement  No. 133.  These
statements   establish   accounting  and  reporting   standards  requiring  that
derivative  instruments  (including certain derivative  instruments  embedded in
other  contracts)  be recorded at fair market  value and included in the balance
sheet as assets or liabilities.  The accounting for changes in the fair value of
a derivative  instrument  depends on the intended use of the  derivative and the
resulting  designation,  which is  established at the inception of a derivative.
Special  accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the statement of operations. For
derivative instruments designated as cash flow hedges, changes in fair value, to
the extent the hedge is effective,  are recognized in other comprehensive income
until the hedged item is recognized in earnings. Hedge effectiveness is measured
at least  quarterly  based on the  relative  changes in fair value  between  the
derivative  contract  and the hedged  item over  time.  Any change in fair value
resulting  from   ineffectiveness,   as  defined  by  SFAS  133,  is  recognized
immediately in earnings.  All of our derivative financial instruments subject to
SFAS 133 have been designated as cash flow hedges.


                                       33

<PAGE>

     Adoption of SFAS 133 at January 1, 2001 will result in the  recognition  of
$10 million of derivative  liabilities  included in accrued  liabilities  in the
Consolidated  Balance Sheets and $6 million,  net of taxes, of deferred  hedging
losses,  included  in  accumulated  other  comprehensive  income.  We will  also
recognize  an increase in assets of $261,000  and net income of $162,000 for the
fair value of an option to put oil to a  purchaser  as the effects of the change
in accounting principle.  Amounts were determined as of January 1, 2001 based on
quoted  market  values,  our  portfolio  of  derivative  instruments,   and  the
measurement of hedge effectiveness.

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,
to ensure  sufficient  revenues for debt service and capital  expenditures or to
take advantage of unusual strength in the market. The type of hedge agreement we
enter into varies,  based on among other factors,  the market  conditions at the
time.

     During 1998,  1999 and 2000 we hedged the following  percentages of our oil
and natural gas  production  in accordance  with our hedging  policy and/or as a
requirement  with our Credit  Facility.  During 1998 and 1999 we entered  into a
combination of options to put produced volumes to a purchaser at a predetermined
price, or swaps based on a single predetermined price or a range of high and low
predetermined  prices.  During 2000 we entered  into  agreements  to put oil and
natural gas to a purchaser at  predetermined  prices.  Following is a summary of
the results of those years' hedging activities.

<TABLE>
<CAPTION>


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

      1998          12.0            463                    67%         52%             $2.5 million
      1999           8.8            540                    79%         46%            ($4.6 million)
      2000           3.7            422                    27%         39%            ($1.1 million)

</TABLE>

     For 2001,  the we have hedged  18,000  MMbtu per day of natural gas for the
entire year.  The hedge is a swap,  based on the NYMEX  closing  prices when the
swap was put in place in November  2000.  The swap  prices  range from a high of
$6.415 per MMbtu in January to a low of $4.485 per MMbtu in October  and average
$4.914 per MMbtu for the year. The corresponding  settlement prices are based on
the last three  trading days on the NYMEX for the month to which the swap prices
relate.  If  the  swap  prices  are  higher  than  the  settlement  prices,  the
counterparty  will pay us the price  difference  for the total MMbtu  hedged for
that month. If the swap prices are less than the settlement  prices, we will pay
the counterparty the price difference for the total MMbtu hedged for that month.

     We have also  purchased  an option to put oil to a  purchaser  at an agreed
upon price.  The put option is for 1,000  barrels of oil per day from  January 1
through September 30 at a NYMEX price of $25.00 per barrel. We paid $365,000 for
the put option, of which $273,000 remained  unamortized at December 31, 2000. At
December  31,  2000 and 1999 the fair value of these  hedges was losses of $10.6
million and $1.8 million, respectively.

     The fair value of our commodity hedging instruments is the estimated amount
that  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 of our 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, 2000 and 1999. A 10%
increase in oil and natural gas prices  would  increase  the  anticipated  hedge
losses by $4.3 million on December 31, 2000.  These hedges are  accounted for as
gains  and  losses  in oil and  natural  gas  revenue  in the  month  of  hedged
production.


                                       34

<PAGE>

     At December 31, 2000 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, 2000, was approximately  $80 million.  We also had
$19.4 million  outstanding  under our Credit  Facility at December 31, 2000. The
Credit Facility is a floating rate facility, with a fair value of $19.4 million.
We do not have any interest rate hedge agreements at December 31, 2000.

Item 8.  Financial Statements and Supplementary Data.

     The Financial Statements are included beginning at F-1.

     The following unaudited  summarized quarterly financial data should be read
in  conjunction  with the Financial  Statements,  beginning on F-1 and Item 7. -
"Managements  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations." Amounts are in thousands, except per share data.

<TABLE>
<CAPTION>
                                                              2000
                                                           ---------

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

Total revenues                    $  15,619        $  21,280         $  24,911         $  26,740
Operating income                      3,853            6,939             7,784            12,787
Income before
       extraordinary item               253           30,639             2,462             5,801
Net income                        $     253        $  30,639         $   2,462         $   5,801
                                  =========        =========         =========         =========
Net income per share              $    0.01        $    1.26         $    0.10         $    0.24
                                  =========        =========         =========         =========


                                                              1999
                                                           ---------


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

Total revenues                    $   9,499        $  10,627         $  10,481         $  12,065
Operating loss                       (2,914)          (1,552)           (7,180)          (10,813)
Loss before
       extraordinary item            (5,625)          (4,249)          (10,731)          (14,290)
Net loss                          $  (5,625)       $  (4,249)        $ (10,863)        $ (14,290)
                                  =========        =========         =========         =========
Net loss per share                $   (0.24)       $   (0.18)        $   (0.45)        $   (0.60)
                                  =========        =========         =========         =========


</TABLE>

Quarterly periods ending December 31, 2000
------------------------------------------

     During the  second and fourth  quarters  we  received  lawsuit  settlements
totaling $1.0 million and $1.6 million,  respectively.  During the third quarter
of 2000 we  recorded a $0.7  million  severance  charge in  connection  with the
resignation of a former employee and director.

     During the second  quarter we also  recorded an income tax benefit of $29.0
million due to the reversal of a deferred tax asset valuation allowance.  In the
second quarter and the  subsequent two quarters of 2000 we also began  recording
income tax expense which totaled $1.1 million, $1.5 million and $3.7 million for
the second, third and fourth quarters, respectively.


                                       35

<PAGE>

     Financial  results for the first three quarters of 2000 were restated.  The
adjustments  reflect an  increase  in a gas  imbalance  payable  and  associated
reduction  of  revenues  in the  quarters to which the  imbalance  relates.  The
changes reflect  adjustments to natural gas production and revenues,  depletion,
income  before  income taxes and net income.  The  adjustments  to revenues were
$63,000,  $(744,000) and $(1,007,000) for the first,  second and third quarters,
respectively.  The adjustments to depletion,  depreciation and amortization were
$(35,000),  $(60,000) and $(293,000) for the first,  second and third  quarters,
respectively.  The  adjustments  to income  before  income  taxes were  $98,000,
$(684,000)   and  $(714,000)   for  the  first,   second  and  third   quarters,
respectively.  The  adjustments  to net  income  were  $98,000,  $(425,000)  and
$(444,000) for the first, second and third quarters, respectively.

Quarterly periods ending December 31, 1999
------------------------------------------

     During 1999 we recorded  impairments  of our oil and gas  properties in the
third and fourth quarters totaling $5.7 million and $7.5 million,  respectively.
We also  recorded an  extraordinary  item, a loss on early  retirement  of debt,
during the third quarter in the amount of $0.1 million.

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, 2000. 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, 2000. 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, 2000. 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, 2000. Such information is incorporated herein by reference.


                                     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.  Form 8-K filed  October 26, 2000 with respect to
          the Change of Control Offer for the Company's Senior Notes.

     (c)  Exhibits and Financial Statement Schedules.

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

          3.1*       Certificate of Incorporation of the Company.


                                       36

<PAGE>

          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.

          10.25      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.

          10.25.1    Second  amendment  to the  Company's  credit  agreement
                     filed as an  exhibit  on the Form  10-Q on  November  10,
                     2000,  and incorporated herein by reference.

          10.25.2**** Third amendment to the Company's credit agreement.

          10.27      Employment  agreement  between the  Company  and Robert G.
                     Wonish  filed as an exhibit on the Form 10-Q on
                     November 10, 2000, and incorporated herein by reference.

          10.28****  Form of stock option agreement between the Company and key
                     employees.


                                       37

<PAGE>

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

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

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

          ****Filed herewith.

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


                                       38

<PAGE>
                     GLOSSARY OF SELECTED OIL AND GAS TERMS

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


                                       39

<PAGE>


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.

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, 2000,  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,
2000, 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.


                                       40

<PAGE>

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

Proved  Developed  Producing  Reserves.  Reserves  that  can be  expected  to be
recovered  from  currently  producing  zones under the  continuation  of present
operating methods.

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

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

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

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.


                                       41

<PAGE>
                                 SIGNATURES

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

        PANACO, Inc.

        By: \s\ Robert G. Wonish                        March 20, 2001
            -----------------------                     --------------
            Robert G. Wonish, President and
            Chief Operating Officer and Director

     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\ Robert G. Wonish                         March 20, 2001
            -----------------------                     --------------
            Robert G. Wonish, President and
            Chief Operating Officer and Director

        By: \s\ Todd R. Bart                            March 20, 2001
            ------------------------                    --------------
            Todd R. Bart
            Chief Financial Officer and
            Principal Accounting Officer

        By: \s\ Harold First                            March 20, 2001
            ------------------------                    --------------
            Harold First, Director

        By: \s\ A. Theodore Stautberg, Jr.              March 20, 2001
            -----------------------------               --------------
            A. Theodore Stautberg, Jr., Director

        By: \s\ James B. Kreamer                        March 20, 2001
            ------------------------                    --------------
            James B. Kreamer, Director

        By: \s\ Felix A. Pardo                          March 20, 2001
            ------------------------                    --------------
            Felix A. Pardo, Director

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


        By: ------------------------
            George W. Hebard III, Director


                                       42

<PAGE>
                                  PANACO, Inc.
                          INDEX TO FINANCIAL STATEMENTS

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

 Independent Auditors' Report                                          F-2

 Consolidated Balance Sheets, December 31, 2000 and 1999               F-3

 Consolidated Statements of Operations for the Years Ended

         December 31, 2000, 1999 and 1998                              F-5

 Consolidated Statements of Changes in Stockholders' Equity (Deficit)

        for the Years Ended December 31, 2000, 1999 and 1998           F-6

 Consolidated Statements of Cash Flows for the Years Ended

         December 31, 2000, 1999 and 1998                              F-7

 Notes to Consolidated Financial Statements for the Years Ended

         December 31, 2000, 1999 and 1998                              F-9









                                      F-1

<PAGE>

                          Independent Auditors' Report


The Board of Directors and Shareholders of
PANACO, Inc.:

We have audited the accompanying  consolidated balance sheets of PANACO, Inc. as
of  December  31,  2000 and 1999,  and the related  consolidated  statements  of
operations,  changes in stockholders' equity (deficit),  and cash flows for each
of  the  years  in  the  three-year   period  ended  December  31,  2000.  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 audits.

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

In our opinion, the consolidated  financial statements referred to above present
fairly, in all material respects,  the financial position of PANACO,  Inc. as of
December 31, 2000 and 1999, and the results of its operations and its cash flows
for each of the years in the  three-year  period ended  December  31,  2000,  in
conformity with accounting principles generally accepted in the United States of
America.



                                                                KPMG LLP
Houston, Texas
March 7, 2001



                                      F-2

<PAGE>




                                  PANACO, Inc.
                           CONSOLIDATED BALANCE SHEETS



<TABLE>
<CAPTION>
                                     ASSETS
                                     ------

                                                                                  December 31,
                                                                                  ------------
                                                                          2000                  1999
                                                                          ----                  ----
<S>                                                                        <C>                   <C>

CURRENT ASSETS
Cash                                                                 $  2,878,000           $  5,575,000
Accounts receivable, net of an allowance
 of $554,000 and $830,000, respectively                                17,680,000              9,675,000
Accounts receivable-related party                                         300,000                 16,000
Prepaid and other                                                         907,000                729,000
                                                                     ------------           ------------
      Total current assets                                             21,765,000             15,995,000
                                                                     ------------           ------------

OIL AND GAS PROPERTIES, AS DETERMINED
BY THE SUCCESSFUL EFFORTS METHOD
OF ACCOUNTING
   Oil and gas properties, proved                                     289,892,000             262,043,000
   Less accumulated depreciation, depletion and amortization         (193,135,000)           (175,048,000)
   Net unproved oil and gas properties                                  2,888,000               1,893,000
                                                                     ------------            ------------
      Net oil and gas properties                                       99,645,000              88,888,000

PIPELINES AND EQUIPMENT
   Pipelines and equipment                                             26,409,000              26,327,000
   Less accumulated depreciation                                       (8,256,000)             (6,130,000)
                                                                     ------------            ------------
      Net pipelines and equipment                                      18,153,000              20,197,000
                                                                     ------------            ------------

OTHER ASSETS
   Restricted deposits                                                  8,625,000               5,602,000
   Deferred financing costs, net                                        3,128,000               4,456,000
   Employee note receivable                                                   ---                 300,000
   Deferred income taxes                                               22,763,000                     ---
                                                                     ------------            ------------
      Total other assets                                               34,516,000              10,358,000
                                                                     ------------            ------------

TOTAL ASSETS                                                        $ 174,079,000           $ 135,438,000
                                                                     ============            ============




                                                                                             (Continued)
</TABLE>



          See accompanying notes to consolidated financial statements.

                                      F-3

<PAGE>

                 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
<TABLE>
<CAPTION>

                                                                                December 31,
                                                                                ------------
                                                                         2000                 1999
                                                                         ----                 ----
<S>                                                                      <C>                   <C>

CURRENT LIABILITIES
  Accounts payable and accrued liabilities                          $ 31,963,000          $ 20,408,000
  Interest payable                                                     2,917,000             3,003,000
  Gas imbalance payable                                                2,860,000                   ---
  Restricted cash payable                                                629,000                   ---
                                                                    ------------          ------------
     Total current liabilities                                        38,369,000            23,411,000
                                                                    ------------          ------------

DEFERRED CREDITS                                                       1,609,000                   ---

LONG-TERM DEBT                                                       121,693,000           138,902,000

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;
     24,323,521 and 23,986,521 shares
     issued and outstanding, respectively                                246,000               243,000
  Additional paid-in capital                                          68,977,000            68,852,000
  Accumulated deficit                                                (56,815,000)          (95,970,000)
                                                                    ------------          ------------
     Total stockholders' equity (deficit)                             12,408,000           (26,875,000)
                                                                    ------------          ------------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)                $174,079,000          $135,438,000
                                                                    ============          ============


</TABLE>






          See accompanying notes to consolidated financial statements.

                                      F-4

<PAGE>
                                  PANACO, Inc.
                      CONSOLIDATED STATEMENTS OF OPERATIONS


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

                                                            2000                1999                  1998
                                                            ----                ----                  ----
REVENUES
  Oil and natural gas sales                          $ 88,550,000         $ 42,672,000          $ 50,291,000
  Gain on property sales                                1,938,000                  ---                   ---
  Lawsuit recoveries                                    2,575,000                 ---                   ---
                                                     ------------         ------------          ------------
     Total                                             93,063,000           42,672,000            50,291,000

COSTS AND EXPENSES
  Lease operating expense                              20,876,000           17,740,000            18,148,000
  Depreciation, depletion and amortization             27,030,000           26,439,000            37,500,000
  General and administrative expense                    5,222,000            4,069,000             4,629,000
  Production and ad valorem taxes                       2,089,000            1,202,000             1,351,000
  Exploratory dry hole expense                          4,361,000            1,050,000             5,655,000
  Geological and geophysical expense                    1,376,000            1,429,000             1,927,000
  Impairment of oil and gas properties                        ---           13,202,000            20,406,000
  Office consolidation and severance expense              746,000                  ---               987,000
                                                     ------------         ------------          ------------
     Total                                             61,700,000           65,131,000            90,603,000
                                                     ------------         ------------          ------------

OPERATING INCOME (LOSS)                                31,363,000          (22,459,000)          (40,312,000)
                                                     ------------         ------------          ------------

OTHER INCOME (EXPENSE)
  Interest income                                         497,000              255,000               849,000
  Interest expense                                    (15,388,000)         (12,692,000)          (10,488,000)
                                                     ------------         ------------          ------------
     Total                                            (14,891,000)         (12,437,000)           (9,639,000)
                                                     ------------         ------------          ------------

INCOME (LOSS) BEFORE INCOME
  TAXES AND EXTRAORDINARY ITEM                         16,472,000          (34,896,000)          (49,951,000)

INCOME TAXES (BENEFIT)                                (22,683,000)                 ---            (3,100,000)
                                                     ------------         ------------          ------------

INCOME (LOSS) BEFORE
  EXTRAORDINARY ITEM                                   39,155,000          (34,896,000)          (46,851,000)

EXTRAORDINARY ITEM - Loss on early
  retirement of debt                                          ---             (131,000)                  ---
                                                     ------------         ------------          ------------
NET INCOME (LOSS)                                    $ 39,155,000        $ (35,027,000)        $ (46,851,000)
                                                     ============         ============          ============

BASIC AND DILUTED EARNINGS (LOSS)
  PER SHARE
   Income (loss) before extraordinary item           $       1.61        $       (1.45)        $       (1.96)
   Extraordinary item                                         ---                 (.01)                  ---
                                                     ------------         ------------          ------------
   Net income (loss)                                 $       1.61        $       (1.46)        $       (1.96)
                                                     ============         ============          ============


BASIC SHARES OUTSTANDING                               24,261,830           23,940,785            23,884,091
                                                     ============         ============          ============

DILUTED SHARES OUTSTANDING                             24,317,942           23,940,785            23,884,091
                                                     ============         ============          ============

</TABLE>

          See accompanying notes to consolidated financial statements.

                                      F-5

<PAGE>
                                  PANACO, Inc.
      CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
              FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 and 1998

<TABLE>
<CAPTION>
                                         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, 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)

   Net income                                  ---         ---              ---         ---       39,155,000       39,155,000
   Shares issued under Employee
     Stock Ownership Plan                  337,000       3,000          125,000         ---              ---          128,000
                                        ----------     -------       ----------    --------       ----------       ----------
 Balances, December 31, 2000            24,323,521    $246,000      $68,977,000    $    ---     $(56,815,000)     $12,408,000
                                        ==========     =======       ==========    ========       ==========       ==========
</TABLE>






          See accompanying notes to consolidated financial statements.

                                      F-6

<PAGE>
                                  PANACO, Inc.
                      CONSOLIDATED STATEMENTS OF CASH FLOWS


<TABLE>
<CAPTION>
                                                                      Year Ended December 31,
                                                                      -----------------------
                                                            2000                1999               1998
                                                            ----                ----               ----
<S>                                                         <C>                 <C>                 <C>

CASH FLOWS FROM OPERATING ACTIVITIES
 Net income (loss)                                      $ 39,155,000       $ (35,027,000)     $ (46,851,000)
 Adjustments to reconcile net income (loss)
    to net cash provided by operating activities:
  Extraordinary item                                             ---             131,000                ---
  Depreciation, depletion and amortization                27,030,000          26,439,000         37,500,000
  Impairment of oil and gas properties                           ---          13,202,000         20,406,000
  Exploratory dry hole expense                             4,361,000           1,050,000          5,655,000
  Deferred income tax benefit                            (22,763,000)                ---         (3,100,000)
  ESOP stock contribution expense                            128,000             250,000            275,000
  Gain on property sales                                  (1,938,000)                ---                ---
  Changes in operating assets and liabilities:
     Accounts receivable                                  (8,005,000)         (1,343,000)         1,403,000
     Related party note receivable                            16,000               2,000           (318,000)
     Prepaid and other                                      (177,000)           (347,000)           572,000
     Accounts payable                                     11,555,000           3,682,000           (249,000)
     Deferred credits                                      1,609,000                 ---                ---
     Gas imbalance payable                                 2,860,000                 ---                ---
       Interest payable                                      (86,000)            258,000            329,000
                                                          ----------          ----------         ----------
  Net cash provided by operating activities               53,745,000           8,297,000         15,622,000
                                                          ----------          ----------         ----------

CASH FLOWS FROM INVESTING ACTIVITIES
 Proceeds from the sale of oil and gas properties            783,000           1,036,000             23,000
 Capital expenditures and acquisitions                   (37,192,000)        (26,429,000)       (61,253,000)
 Increase in restricted deposits                          (2,395,000)         (1,883,000)        (1,463,000)
                                                          ----------          ----------         ----------
  Net cash used in investing activities                  (38,804,000)        (27,276,000)       (62,693,000)
                                                          ----------          ----------         ----------

CASH FLOWS FROM FINANCING ACTIVITIES
 Long-term debt proceeds                                  22,791,000          47,153,000         46,049,000
 Repayment of long-term debt                             (40,000,000)        (24,000,000)       (32,000,000)
 Issuance of common shares                                       ---                 ---            275,000
 Deferred financing costs                                   (429,000)         (2,051,000)               ---
 Acquisition of treasury stock                                   ---                 ---           (592,000)
 Shareholder rights redemption                                   ---                 ---           (118,000)
                                                          ----------          ----------         ----------
  Net cash provided by (used in) financing activities    (17,638,000)         21,102,000         13,614,000
                                                          ----------          ----------         ----------

NET INCREASE (DECREASE) IN CASH                         $ (2,697,000)       $  2,123,000      $ (33,457,000)

CASH AT BEGINNING OF YEAR                                  5,575,000           3,452,000         36,909,000
                                                          ----------          ----------         ----------

CASH AT END OF YEAR                                     $  2,878,000        $  5,575,000      $   3,452,000
                                                          ==========          ==========         ==========

</TABLE>


          See accompanying notes to consolidated financial statements.

                                      F-7

<PAGE>

      SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:

For the year ended December 31, 2000:
------------------------------------

The Company  issued  337,000  common shares valued at $128,000 to the ESOP.  The
change in accounts  payable from December 31, 1999 to December 31, 2000 excludes
this non-cash reduction of the liability.

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.

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

Cash paid during the year ended December 31:

<TABLE>
<CAPTION>
                                                  2000             1999             1998
                                                  ----             ----             ----
<S>                                               <C>               <C>              <C>


Interest (gross interest paid)                $15,682,000       $12,978,000      $11,338,000
                                              ===========       ===========      ===========

Income taxes                                  $   145,000       $       ---      $       ---
                                              ===========       ===========      ===========
</TABLE>







                                      F-8

<PAGE>

                                  PANACO, Inc.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

              FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 and 1998

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

Nature of Business
------------------
PANACO,  Inc. (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. The Company operates a majority of its assets in order
to control the  operations and the timing of  expenditures.  The majority of the
Company's  properties  are  located  in state or  federal  waters of the Gulf of
Mexico,  where the costs of operations,  productions rates and reserve potential
are generally greater than properties located onshore.  The Company's assets and
operations  are  primarily  concentrated  on a small  group of  properties.  The
Company  has grown  primarily  by  acquiring  properties  that  have  additional
development  potential  and  improving  the  economics  of those  properties  by
exploiting the oil and natural reserves and reducing  operating costs and making
them more efficient.

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, 2000 the Company's
imbalance  position  was an  over-produced,  or payable  balance of 610,000  Mcf
valued at $2.9 million.  At December 31, 1999 the Company's  quantity and dollar
amount 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 9). 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.  Realized  gains and losses are  recognized
monthly as adjustments to revenues in the same  production  period as the hedged
production.  Contracts are placed with  entities 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.

Effective January 1, 2001, the Company adopted Statement of Financial Accounting
Standards No. 133 ("SFAS133"), Accounting for Derivative Instruments and Hedging
Activities,  and SFAS No. 138, Accounting for Certain Derivative Instruments and
Certain  Hedging  Activities,  an amendment  of FASB  Statement  No. 133.  These
statements   establish   accounting  and  reporting   standards  requiring  that
derivative  instruments  (including certain derivative  instruments  embedded in
other  contracts)  be recorded at fair market  value and included in the balance
sheet as assets or liabilities.  The accounting for changes in the fair value of
a derivative  instrument  depends on the intended use of the  derivative and the
resulting  designation,  which is  established at the inception of a derivative.
Special  accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the statement of operations. For
derivative instruments designated as cash flow hedges, changes in fair value, to
the extent the hedge is effective,  are recognized in other comprehensive income
until the hedged item is recognized in earnings. Hedge effectiveness is measured



                                      F-9

<PAGE>

at least  quarterly  based on the  relative  changes in fair value  between  the
derivative  contract  and the hedged  item over  time.  Any change in fair value
resulting  from   ineffectiveness,   as  defined  by  SFAS  133,  is  recognized
immediately in earnings.  All of the Company's derivative financial  instruments
subject to SFAS 133 have been designated as cash flow hedges.

Adoption  of SFAS 133 at January 1, 2001 will result in the  recognition  of $10
million  of  derivative  liabilities  included  in  accrued  liabilities  in the
Consolidated  Balance Sheets and $6 million,  net of taxes, of deferred  hedging
losses,  included in accumulated other comprehensive income, as an effect of the
change in accounting principle.  In addition,  the Company will also recognize a
$261,000  increase in assets and a $162,000  increase in net income based on the
market  value of an option to put oil to a purchaser  as an effect of the change
in accounting principle.  Amounts were determined as of January 1, 2001 based on
quoted  market  values,  our  portfolio  of  derivative  instruments,   and  the
measurement of hedge effectiveness.

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.
Non-drilling  exploratory costs,  including geological and geophysical costs and
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 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.
During 2000 the  Company  recorded a net gain of $1.9  million  from the sale of
three properties.

The Company performs a review for impairment of proved oil and gas properties on
a depletable  unit basis when  circumstances  suggest there is a need for such a
review.  For each depletable unit determined to be impaired,  an impairment loss
equal to the  difference  between the  carrying  value and the fair value of the
depletable  unit will be recognized.  Fair value, on a depletable unit basis, is
estimated  to be the  present  value of expected  future cash flows  computed by
applying  estimated future oil and gas prices,  as determined by management,  to
estimated  future  production of oil and gas reserves over the economic lives of
the reserves.  Future cash flows are based upon the Company's estimate of proved
reserves.  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
-----------------------
The  Company  accrues  for  losses  associated  with  environmental  remediation
obligations  when such  losses are  probable  and can be  reasonably  estimated.
Accruals  for  estimated  losses  from  environmental   remediation  obligations
generally  are  recognized  no  later  than the  time of the  completion  of the
remedial  feasibility study. These accruals are adjusted as further  information


                                      F-10

<PAGE>

develops or circumstances change. Costs of future expenditures for environmental
remediation obligations are not discounted to their present value. Recoveries of
environmental  remediation  costs from other parties are recorded as assets when
their receipt is deemed probable.

Capitalized Interest
--------------------
The Company capitalizes interest costs associated with unproved properties under
development.  Interest capitalized in 2000, 1999 and 1998 was $208,000, $544,000
and $936,000, 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.

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.  In part of
2000 and all of 1999 and 1998 the  Company  had  options  outstanding  that were
exercisable  at  prices  above  the  market  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 10.

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 Receivable - Related Party
-----------------------------------
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.  On  October  1,  2000  the  officer  resigned  from all of his


                                      F-11

<PAGE>

positions with the Company. As part of the severance agreement,  $300,000 of the
amount due the  employee  was  withheld by the Company and  interest on the note
stopped  accruing.  The $300,000 due the employee was used to repay this note in
January 2001.

Quarterly Financial Data
------------------------
The Company has restated its financial  results for the first three  quarters of
2000. The adjustments reflect an increase in the Company's gas imbalance payable
and  associated  reduction  of revenues in the  quarters to which the  imbalance
relates. The changes reflect adjustments to natural gas production and revenues,
depletion,  income  before  income  taxes and net  income.  The  adjustments  to
revenues were $63,000,  $(744,000) and  $(1,007,000)  for the first,  second and
third quarters,  respectively.  The adjustments to depletion,  depreciation  and
amortization were $(35,000),  $(60,000) and $(293,000) for the first, second and
third quarters, respectively. The adjustments to income before income taxes were
$98,000,  $(684,000) and $(714,000)  for the first,  second and third  quarters,
respectively.  The  adjustments  to net  income  were  $98,000,  $(425,000)  and
$(444,000) for the first, second and third quarters, respectively.

Note 2 - ACQUISITIONS
         ------------

During 2000 the Company acquired an additional 33% working interest in the North
Coward's  Gully Field onshore in Louisiana from a  non-operating  owner for $1.1
million.  The Company  operates the Field and the  acquisition  gave the Company
essentially 100% ownership of the Field.  During 2000 the Company also purchased
an additional  6.2% working  interest in the Price Lake Field from several small
non-operating partners for $0.9 million.

On May 26, 1998 the Company  purchased  a 100%  working  interest in East Breaks
Blocks 165 and 209 and 75% working  interest  in High  Island  Block 587 from BP
Exploration  and Oil, Inc.  ("BP").  The acquisition was accounted for using the
purchase  method.  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 was 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.

The  following  unaudited  pro  forma  financial   information  assumes  the  BP
acquisition  had been  consummated  January  1,  1998.  The pro forma  financial
information  does not purport to be indicative of the results of the Company had
this transaction occurred on the data assumed, nor is it necessarily  indicative
of the future results of the Company.

<TABLE>
<CAPTION>
                    Unaudited Pro Forma Financial Information
                      For the Year Ended December 31, 1998

<S>                                                          <C>

Revenues                                                  $54,666,000

Loss before extraordinary item                            (46,177,000)

Net loss                                                  (46,177,000)

Net loss per share                                        $     (1.93)

</TABLE>

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
$330,000,  $337,000 and $275,000 in costs for the years ended December 31, 2000,
1999 and 1998, respectively.


                                      F-12

<PAGE>

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

Pursuant to existing  agreements  with former  property owners and in accordance
with  requirements  of the U.S.  Department  of Interior's  Minerals  Management
Service  ("MMS"),  the  Company  has put in place  surety  bonds  and/or  escrow
agreements to provide  satisfaction of its eventual  responsibility  to plug and
abandon wells and remove structures when certain fields are no longer in use. As

part of its agreement with the underwriter of the surety bonds,  the Company has
established  bank trust and escrow  accounts  in favor of either the surety bond
underwriter or the former owners of the particular fields.

In the West Delta  Fields and the East  Breaks 109 and 110  Fields,  the Company
established  an escrow for both Fields in favor of the surety bond  underwriter,
who provides a surety bond to the former  owners of the West Delta Fields and to
the MMS.  The balance in this escrow  account was $3.5  million at December  31,
2000 and  requires  quarterly  deposits  of $250,000  until the account  balance
reaches $6.3 million.

In the East Breaks 165 and 209 Fields the Company  established an escrow account
in favor of the surety bond  underwriter,  who provides surety bonds to both the
MMS and the former owner of the Fields.  The balance in this escrow  account was
$4.4 million at December 31, 2000 and  requires  quarterly  deposits of $250,000
until the account balance reaches $6.5 million.

The Company has also  established  an escrow  account in favor of BP under which
the  Company  will  deposit  10% of the net cash flows from the  properties,  as
defined in the  agreement,  from the  properties  acquired  from BP. This escrow
account balance was $0.7 million at December 31, 2000.

Note 5 - LAWSUIT RECOVERIES
         ------------------

During 2000 the Company settled two lawsuits it had filed, for which it received
a total of $2.6 million.  The first suit was settled with the insurance  carrier
of a third  party  that  caused a fire at the West  Delta  Fields  in 1996.  The
proceeds of $1.0 million were for the lost revenues  during the period which the
Company  was not able to produce and sell its oil and  natural  gas.  The second
suit was the recovery of net revenues  from a well based on an incorrect  payout
calculation by the operator,  resulting in a settlement  received by the Company
totaling $1.6 million.

Note 6 - LONG-TERM DEBT
         --------------

<TABLE>
<CAPTION>

                                                2000                  1999
                                            -----------           -----------
<S>                                             <C>                    <C>

10 5/8 % Senior Notes due 2004(a)          $100,000,000          $100,000,000
Revolving credit facility due 2001(b)        19,444,000            36,653,000
Production payment(c)                         2,249,000             2,249,000
                                           ------------          ------------
                                            121,693,000           138,902,000

Less current portion                                ---                   ---
                                           ------------          ------------
    Long-term debt                         $121,693,000          $138,902,000
                                           ============          ============
</TABLE>

                                      F-13

<PAGE>

(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.
     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, 2000
     was approximately $80 million 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, 2000 was $60 million,  with  availability  of $39.3 million,  of which,
     $7.5 million was reserved by a letter of credit.  The  principal  amount of
     the loan is due October 1, 2001, and may be extended for two additional six
     month periods, at the sole option of the Company.  The Company is reviewing
     alternatives to extending this agreement,  including  replacing this Credit
     Facility  with a bank  facility.  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.

(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
     upon  acquisition.  The agreement  requires  repayment of principal plus an
     amount sufficient to provide an internal rate of return of 18%.

Note 7 - EXTRAORDINARY ITEM-LOSS ON EARLY RETIREMENT OF DEBT
         ---------------------------------------------------

In 1999 the Company replaced its Credit Facility, see Note 6. In connection with
the  prepayment  of the  previous  Credit  Facility,  the Company  wrote off the
remaining deferred financing costs associated with the previous facility.

Note 8 - SEVERANCE EXPENSE
         -----------------

Effective  October 1, 2000 the Company's  President and Chief Executive  Officer
resigned his position as an employee and director of the Company. Pursuant to an
employment  contract  between the Company and the  employee,  the  employee  was
entitled to receive two years of salary and benefits.  The Company had the right
to offset  the  amounts  due the  employee  with  principal  and  interest  on a
promissory  note due the Company.  The  severance  charge  incurred in the third
quarter of 2000 relates to the  settlement of all amounts due the employee under
the agreement,  including the remaining  salary and coverage under the Company's

                                      F-14

<PAGE>

various insurance  policies.  The employee was paid a portion of this amount due
in October 2000 and the remaining amount due the employee will be offset against
the principal amount of the promissory note in January 2001.  Effective  October
15, 2000, the Company's  Chief  Operating  Officer took over as President of the
Company.

Note 9 - COMMODITY HEDGE AGREEMENTS
         --------------------------

During 2000,  1999 and 1998, 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.  The following is a summary of those years'  hedging
activities.

<TABLE>
<CAPTION>

                      Volume Hedged                Percentage of Actual Production        Realized
   Year      Natural Gas (Bcf)    Oil (MBbl)           Natural Gas       Oil              Gain/(Loss)
   ----      -------------------------------       -------------------------------        -----------
  <S>           <C>                 <C>                   <C>            <C>                  <C>
   2000           3.7               422                   27%            39%             ($1.1 million)
   1999           8.8               540                   79%            46%             ($4.6 million)
   1998          12.0               463                   67%            52%              $2.5 million
</TABLE>

For 2001,  the  Company has hedged  18,000  MMbtu per day of natural gas for the
entire year.  The hedge is a swap,  based on the NYMEX  closing  prices when the
swap was put in place in November  2000.  The swap  prices  range from a high of
$6.415 per MMbtu in January to a low of $4.485 per MMbtu in October and averages
$4.914 per MMbtu for the year. The corresponding  settlement prices are based on
the last three  trading days on the NYMEX for the month to which the swap prices
relate.  If  the  swap  prices  are  higher  than  the  settlement  prices,  the
counterparty  will pay the  Company  the price  difference  for the total  MMbtu
hedged for that month.  If the swap prices are less than the settlement  prices,
the Company will pay the  counterparty  the price difference for the total MMbtu
hedged for that month.

The Company has also  purchased an option to put oil to a purchaser at an agreed
upon price.  The put option is for 1,000  barrels of oil per day from  January 1
through  September  30 at a NYMEX price of $25.00 per barrel.  The Company  paid
$365,000 for the put option, of which $273,000 remained  unamortized at December
31,  2000.  The cost of the put  option is being  amortized  over the period the
hedged item is  produced.  At  December  31, 2000 and 1999 the fair value of the
Company's hedges was losses of $10.6 million and $1.8 million, respectively.

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

                                      F-15

<PAGE>

instruments,  primarily  swaps and options,  are off balance sheet  transactions
and, accordingly,  other than an unamortized premium of $273,000 on put options,
no  respective  carrying  amounts  for these  instruments  were  included in the
accompanying  consolidated  balance sheets as of December 31, 2000 and 1999. The
Company  accounts for the gains and losses in oil and natural gas revenue in the
month of hedged production.

Note 10 - STOCK OPTIONS
          -------------

During 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 option's 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
expired June 20, 2000.

During 2000 the Company  issued 500,000  options at $1.92 per share,  the market
closing  price on the grant date of August 16, 2000, to officers of the Company.
The  options  vest  ratably  over five years and expire six years from the grant
date.

<TABLE>
<CAPTION>
                                                  2000                            1999                         1998
                                       ---------------------------    ---------------------------    -------------------------
<S>                                        <C>             <C>             <C>           <C>              <C>           <C>

                                                           Wtd.                           Wtd.                         Wtd.
                                                           Avg.                           Avg.                         Avg.
                                         Shares         Ex. Price        Shares        Ex. Price         Shares      Ex. Price
                                         ------         ---------        ------        ---------         ------      ---------

Outstanding at beginning of year       1,150,000        $  4.45        1,150,000       $  4.45         1,190,000     $  4.45
Granted                                  500,000           1.92              ---           ---               ---         ---
Exercised                                    ---            ---              ---           ---               ---         ---
Forfeited                             (1,150,000)          4.45              ---          4.45           (40,000)       4.45
                                      ----------        -------        ---------        ------         ---------      ------
Outstanding at end of year               500,000           1.92        1,150,000          4.45         1,150,000        4.45

Exercisable at end of year                   ---         $ 1.92        1,150,000        $ 4.45         1,150,000      $ 4.45

Fair value of options granted          $    1.71                             N/A                             N/A

</TABLE>

The fair value of each option granted in 2000 was estimated at the date of grant
using  the  Black-Scholes  Modified  American  Option  Pricing  Model  with  the
following assumptions:

<TABLE>
<CAPTION>
              <S>                              <C>

             Expected option life-years            5
             Risk-free interest rate            6.13%
             Dividend yield                        0%
             Volatility                          137%
             Fair-value                        $1.71

</TABLE>

                                      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 Companys unaudited net income (loss) and earnings (loss) per share for 2000,
1999 and 1998 would have been as shown below:

<TABLE>
<CAPTION>
                                                     (Unaudited)        (Unaudited)          (Unaudited)
                                                        2000               1999                  1998
                                                     -----------        -----------         ------------
        <S>                            <C>               <C>                 <C>                  <C>

     Net income (loss)              As reported      $ 39,155,000       $(35,027,000)       $ (46,851,000)
     -----------------              Pro forma        $ 39,027,000       $(35,311,000)       $ (47,133,000)

     Net income (loss) per share:   As reported, basic
     ---------------------------    and diluted:     $       1.61       $      (1.46)       $       (1.96)

                                    Pro forma:
                                    Basic            $       1.61       $      (1.47)       $       (1.96)
                                    Diluted          $       1.60       $      (1.47)       $       (1.97)
</TABLE>

Note 11 - MAJOR CUSTOMERS
          ---------------

During  2000,  the  purchaser  of a majority  of the  Company's  oil  production
accounted  for 23% of total oil and  natural  gas sales and the  purchaser  of a
majority of the Company's natural gas production  accounted for 39% of total oil
and natural gas sales. In 1999, the purchaser of a majority of the Company's oil
production  accounted  for 37% of total oil and  natural  gas  sales,  while the
purchaser for a majority of the Company's  gas  production  accounted for 39% of
total oil and natural gas sales.  A purchaser of natural gas  production in 1998
accounted for 42% of total oil and natural gas sales.

Note 12 - INCOME TAXES
          ------------

At December  31, 2000,  the Company had net  operating  loss carry  forwards for
federal income tax purposes of approximately  $100.4 million which are available
to offset future federal  taxable  income through 2020. 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,
the purchase of common stock of an entity  acquired in 1997 and other changes in
stock ownership.

Significant  components of the Company's deferred tax assets (liabilities) as of
December 31 are as follows:

<TABLE>
<CAPTION>
                                                          2000                    1999
                                                       ----------              -----------
     <S>                                                  <C>                      <C>
Deferred tax assets (liabilities)
   Fixed asset basis differences                     $(14,733,000)            $(10,119,000)
   Net operating loss carry forwards                   35,130,000               36,309,000
   State Taxes                                          2,001,000                2,486,000
   Other                                                  365,000                  297,000
                                                      -----------              -----------
      Net deferred tax assets                          22,763,000               28,973,000
                                                      -----------              -----------
Valuation allowance for deferred
   tax assets                                                 ---              (28,973,000)
                                                      -----------              -----------
       Total net deferred tax assets (liabilities)   $ 22,763,000             $        ---
                                                      ===========              ===========
</TABLE>

                                      F-17

<PAGE>

At December 31, 2000 the Company  determined that it is more likely than not the
deferred tax assets will be realized and the  valuation  allowance was decreased
by $29  million.  This  determination  was based on the  Company's  estimates of
future  net  income   sufficient  to  utilize  the  entire  net  operating  loss
carryforwards.

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>
                                                    2000            1999              1998
                                                   ------          ------            ------
        <S>                                         <C>              <C>              <C>

  Statutory federal income tax rate                  35%             (35%)            (35%)
  State income taxes, net of federal benefit          3               (3)              (3)
  Adjustments to valuation allowance               (176)              38               32
                                                   -----            -----            -----
                                                   (138%)           0.00%              (6%)
                                                   =====            =====            =====
</TABLE>

Note 13 - 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 PANACO and NEG, NEG is required to indemnify the Company
from any damages  attributable  to NEG's  operations  on the property  after the
sale.

Pursuant to another  purchase and sale agreement,  the Company may owe indemnity
to Shell and Exxon, from whom the property was acquired prior to selling same to
NEG. The Company believes that it has insurance coverage for the claims asserted
in the  petition,  and has notified all  insurance  carriers  that might provide
coverage  under its policies.  In 1999 NEG filed for Chapter 11  bankruptcy  and
emerged in late 2000.  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.

In August 2000,  an action was filed  against the Company by Coastal Oil and Gas
Corporation  (now El Paso  Corporation) for nonpayment of joint interest billing
invoices.  The suit  seeks to  recover  unpaid  costs  from a well  drilled on a
property operated by El Paso. PANACO counter sued alleging,  among other things,
gross  misconduct  and  negligence  in drilling  the well.  The case is still in
discovery and it is not possible to evaluate the  likelihood  of an  unfavorable
outcome or to estimate the amount or range of potential loss in addition to what
has already been accrued.

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
through  November 30, 2004.  At December 31,  2000,  the future  minimum  rental
payments due under the lease are as follows:

                    2001                   $   432,000
                    2002                       459,000
                    2003                       459,000
                    2004                       421,000
                                           -----------
                    Total                  $ 1,771,000
                                           ===========

                                      F-18

<PAGE>


Note 14-SUBSEQUENT EVENTS
        -----------------

During the first quarter of 2001 the Company will recognize  approximately  $3.5
million of  exploratory  dry hole expense for the East Breaks 110 A-4 well.  The
well was spud on January 30,  2001 and  reached  total depth in early March 2001
The  well  encountered  the  objective  sand,  however,  it did  not  contain  a
commercial amount of hydrocarbons.

Note 15 - 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>

                                                   2000                1999               1998
                                                ---------           ---------           ---------
<S>                                               <C>                  <C>                 <C>

Property acquisition costs, proved            $ 3,395,000         $       ---         $ 9,877,000

Property acquisition costs, unproved              208,000             544,000           1,245,000

Exploration expenses                            5,737,000           2,479,000           7,582,000

Development costs                              28,613,000          24,777,000          29,957,000

</TABLE>



                                      F-19

<PAGE>

Quantities of Oil and Gas Reserves
----------------------------------
The estimates of proved reserve  quantities at December 31, 2000, 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, 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
  Production                                     (1,070,000)          (13,547,000)
  Extensions and discoveries                        154,000            14,807,000
  Sale of minerals in-place                             ---              (637,000)
  Purchase of minerals in-place                     650,000               658,000
  Revisions of previous estimates                  (290,000)           (1,827,000)
                                                  ---------            ----------
Estimated reserves as of December 31, 2000        8,137,000            82,222,000
                                                  =========            ==========

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

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

  December 31, 1999                               5,351,000            40,627,000
                                                  =========            ==========

  December 31, 2000                               4,460,000            49,945,000
                                                  =========            ==========
</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 base prices  used for the Pretax  PV-10  calculation  were public
market  prices on December  31 and  adjusted by  differentials  to those  market
prices.  These price adjustments were done on a  property-by-property  basis for


                                      F-20

<PAGE>

the quality of the oil and natural gas and for transportation to the appropriate
location. The average prices in the Pretax PV-10 value at December 31, 2000 were
$9.65 per Mcf of natural  gas and $26.60 per barrel of oil.  For  production  in
February  2001,  the Company  estimates  that its  realized  oil and natural gas
prices,  including the impact of hedges,  will average  $30.59 per Bbl and $6.87
per Mcf, respectively.  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>
                                                           2000                1999                 1998
                                                      -------------        ------------         ------------
<S>                                                       <C>                   <C>                 <C>

Future cash inflows                                  $1,017,214,000       $ 420,060,000        $ 259,071,000
Future costs:
    Production                                         (167,180,000)        (98,972,000)         (74,768,000)
    Development                                         (88,604,000)        (68,659,000)         (54,976,000)
                                                      -------------        ------------         ------------
      Future production and development costs          (255,784,000)       (167,631,000)        (129,744,000)
                                                      -------------        ------------         ------------

    Net cash flows-before tax                           761,430,000         252,429,000          129,327,000
Future income tax expenses                             (204,875,000)                ---                  ---
                                                      -------------        ------------         ------------
Future net cash flows                                   556,555,000         252,429,000          129,327,000
10% annual discount for estimated
    timing of cash flows                               (148,540,000)        (71,163,000)         (34,747,000)
                                                      -------------        ------------         ------------
Standardized measure of discounted
    Net cash flows                                   $  408,015,000        $181,266,000        $  94,580,000
                                                      =============        ============         ============

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:

                                                            2000                1999                 1998
                                                       -----------          ------------         -----------

Beginning balance                                   $  181,266,000         $ 94,580,000        $ 120,872,000

Sales, net of production costs                         (65,301,000)         (23,632,000)         (30,692,000)
Increase due to passage of time
    (accretion of discount)                             18,127,000            9,454,000           12,903,000
Purchase of minerals in place                           10,785,000                  ---           23,657,000
Sales of minerals in place                                (345,000)          (1,037,000)            (514,000)
Net change in sales prices, net of
    production costs                                   327,247,000           77,935,000          (42,711,000)
Revisions of quantity estimates                        (16,026,000)          24,111,000            2,280,000
Extensions and discoveries, net of future
    production and development costs                   109,442,000           17,864,000            2,082,000
Net changes in income taxes                           (124,892,000)                 ---            8,160,000
Changes in future development costs                     (9,987,000)          (7,789,000)         (19,250,000)
Changes of production rates (timing)
    and other                                          (22,302,000)         (10,179,000)          17,753,000
                                                     -------------         ------------         ------------
Net increase (decrease)                                225,540,000           86,727,000          (26,332,000)
                                                     -------------         ------------         ------------
Ending balance                                      $  408,015,000        $ 181,266,000        $  94,580,000
                                                     =============         ============         ============

</TABLE>


                                      F-21