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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, 2001

         [    ] 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 Identification Number)
incorporation or organization)

    1100 Louisiana, Suite 5100
            Houston, TX                                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 $12,512,889 as of March 25, 2002.

     24,359,695 Shares of the registrant's Common Stock were outstanding
                            as of March 25, 2002.

                       Documents Incorporated by Reference

  Portions of the registrant's annual proxy statement, to be filed within 120
days after December 31, 2001, are incorporated by reference into Part III.

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<PAGE>


                                 PANACO, Inc.
     Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2001

<TABLE>
<CAPTION>

Table of Contents                                                                                  Page Number

Part I
<S>  <C>                                                                                                    <C>
Item 1.    Business                                                                                      2
Item 2.    Properties                                                                                   17
Item 3.    Legal Proceedings                                                                            23
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        28
Item 7a.   Qualitative and Quantitative Disclosure About Market Risks                                   37
Item 8.    Financial Statements and Supplementary Data                                                  38
Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure         38

Part III
Item 10.   Directors and Executive Officers of the Registrant                                           39
Item 11.   Executive Compensation                                                                       39
Item 12.   Security Ownership of Certain Beneficial Owners and Management                               39
Item 13.   Certain Relationships and Related Transactions                                               40

Part IV
Item 14.   Exhibits, Financial Statement Schedules, and Reports on Form 8-K                             40
           Glossary of Selected Oil and Gas Terms                                                       42
           Signatures                                                                                   45
</TABLE>

                                       1
<PAGE>
                                     PART 1


Item 1.  Business.

        With the exception of historical  information,  the matters discussed in
this  Form  10-K  contain   forward-looking   statements.   The  forward-looking
statements we make, not only in this Form 10-K, but also in press releases, oral
statements  and other  reports  that we file with the  Securities  and  Exchange
Commission  ("SEC") are intended to be subject to the safe harbor  provisions of
the Private Securities Litigation Reform Act of 1995. These statements relate to
future   results  of   operations,   the  ability  to  satisfy   future  capital
requirements,  the growth of our Company and other  matters.  You are  cautioned
that  all  forward-looking  statements  involve  risks  and  uncertainties.  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 42. 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
http://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.  The Company acquires  producing  properties with a
view   toward   further   exploitation   and   development,    capitalizing   on
state-of-the-art  3-D Seismic and advanced  directional  drilling  technology to
recover reserves that were bypassed or previously  overlooked.  Emphasis is also
placed  on  pipeline  and  other   infrastructure  to  provide   transportation,
processing and tieback services to neighboring operators. 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  several  other  properties  in the Gulf Coast Region and Gulf of
Mexico over the past ten years.  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.

        Due to  substantial  losses  incurred  in 1999 and  2001  and less  than
anticipated  results  from  PANACO's  drilling  program in late 2000 and most of
2001,  the Company  accumulated  a  significant  working  capital  deficit as of
December 31, 2001. The deficit  totaled $24.4  million.  The lack of performance
from wells drilled during 2000 and 2001,  along with decreased  commodity prices
in late 2001,  reduced estimated future net cash flows to a point at which there
is  substantial  doubt about the  Company's  ability to reduce this deficit in a
timely manner. See Note 2 to our financial statements.


                                       2
<PAGE>
        In March 2002, the Credit  Facility,  with  borrowings of $32.9 million,
was  amended  in order to cure  covenants  that we were not able to  satisfy  on
December 31, 2001.  This amendment  requires a working capital ratio (as defined
in the  agreement) of 0.15 to 1.0 from January 1 to April 30, 2002,  0.20 to 1.0
from May 1 to January 1, 2003,  and 0.25 to 1.0  thereafter.  The amendment also
requires a trailing twelve-month  EBITDA/interest  coverage ratio ranging from a
monthly high of 2.0 to 1.0 to a monthly low of 0.55 to 1.0 for 2002,  and 2.0 to
1.0  thereafter.  Based  on  current  projections,  we  believe  we  will  be in
compliance  with all of the terms of the Credit  Facility  through  December 31,
2002.  However, no assurances can be given that we will be in compliance through
December 31,  2002.  PANACO's  $100 million  of  Senior  Notes  require  that we
maintain a total  Adjusted  Consolidated  Net Tangible  Asset  Value  ("ACNTA"),
as defined in the  Indenture,  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. At December 31, 2001 PANACO did not meet this ratio. Actual
results  through  March  31,  2002  are not yet  available,  however,  based  on
increased  market  prices for oil  and natural gas, we estimate that the Company
will be in  compliance  with  the  covenant  at  March  31,  2002.  However,  no
assurances can be given that we will meet this covenant or that the Company will
be able to repurchase the amount of the notes required under the Indenture.

        Given these issues,  PANACO engaged an investment  bank in early 2002 to
help the Company explore strategic financial  alternatives.  The outcome of this
process  may result in asset  sales or the sale of the  Company  as a whole.  No
assurances  can be made that the Company will be able to implement any plan that
will resolve the working capital deficit, ensure we maintain compliance with our
Credit Facility and Senior Note covenants, or that a plan will be implemented in
a timely  manner and, as a result,  the Company may not be able to continue as a
going concern.  In addition,  any of these alternatives will most likely require
approval from PANACO's Credit  Facility  lenders and may require the approval of
our Senior  Note  holders  as  well  as  Shareholder approval. See Note 2 to our
financial statements.

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.

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,  have 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.

                                       3
<PAGE>
        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  exploring  on  Gulf  Coast  Region
properties. 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.

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")
for $19.6 million in cash and accounted for the  acquisition as a purchase.  The
purchase  included  3-D Seismic  data which  covers 20 offshore  blocks.  PANACO
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 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.

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 (now El Paso  Energy
Corp.) 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 and 2001 PANACO spent  approximately $30 million
drilling a total of five new or side-tracked  wells in East Breaks Block 110 and
completed  four of the six wells.  The four new wells began  production  in late
2000 and early 2001 and  increased  production  in the Fields  from 2,000 Mcf of
natural gas and 10 barrels of condensate  per day before the drilling began to a


                                       4
<PAGE>
high of over 20,000 Mcf of natural gas and 200  barrels of  condensate  per day.
The  initial  rates  from the new  wells  were in line  with  our  expectations,
however,  production  declined  more  rapidly  than  we had  anticipated  due to
reservoir  depletion.  Current production from the Fields is approximately 5,000
Mcf of natural gas and 40 barrels of condensate per day.

        There are more prospective  drilling locations identified in both Blocks
109 and 110, however, based on the recent results, we are continuing to evaluate
the data we have. PANACO is the operator of the Fields and we own a 100% working
interest.

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,
2001, 25% 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 several  acquisitions  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 27 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 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. 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 to exploratory
projects.  However, as oil and natural gas prices began to increase in late 1999
and  continued  to mid 2001,  the  prices  for  acquisitions  began to  increase
significantly.  With those costs  escalating and a large  inventory of prospects
ready to develop, we devoted a more significant percentage of our capital budget
to both exploratory and developmental drilling.

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

                                       5
<PAGE>
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,  identified  further
development potential and led to several new wells completed in 2000 and 2001.

Significant Operating Control

        We operate 69% 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  54  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 29  remaining  productive
offshore  wells.  We also operate 44 productive  onshore wells in which we own a
majority or all of the working interest.  In addition,  we own working interests
in 54 productive onshore wells operated by others. Where properties are operated
by others,  operations are conducted pursuant to joint operating agreements that
were in effect at the time we  acquired  our  interest in these  properties.  We
consider these joint operating  agreements to be on terms  customary  within the
industry.  The compensation  paid to the operator for such services  customarily
varies from property to property,  depending on the nature,  depth, and location
of the property being operated.

Acquisition, Development, and Other Activities

        We utilize our capital  budget for (a) the  acquisition  of interests in
other producing properties, (b) recompletions of our existing wells, and (c) the
drilling of development and exploratory wells.

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

        We believe that our primary  activities will continue to be concentrated
offshore in the Gulf of Mexico and onshore in the Gulf Coast region.  The number
and type of wells we drill will vary from  period to period  depending  upon the
amount of the capital budget available for drilling,  the cost of each well, our

                                       6
<PAGE>
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
Geoscientists obtain 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 reprocess 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 18% of our  total oil and  natural  gas  revenues  in 2001.  Natural  gas is
generally sold on the spot market or under  short-term  contracts of one year or
less. There are numerous potential  purchasers for natural gas.  Notwithstanding
this,  natural gas purchased by Enron North  America Corp.  accounted for 51% of
our total oil and natural gas revenues in 2001.  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.  In fourth
quarter 2001, we wrote off a total of $3.0 million due from Enron, of which $1.8
million  was for sales of  natural  gas  production.  PANACO  currently  markets
natural gas production to Reliant Resources.

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 approximately
$22  million.  The Minerals  Management  Service of the U.S.  Department  of the
Interior ("MMS") requires operators of offshore platforms to provide evidence of

                                       7
<PAGE>
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 $5.6  million  at  December  31,  2001 and
requires  quarterly  deposits of $375,000 until the account balance reaches $7.8
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 $4.7 million at December 31, 2001 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
deposit 10% of the net cash flows from the  properties  purchased  from them, as
defined in the  agreement.  This  escrow  account  balance  was $0.7  million at
December 31, 2001.

        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 $65  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, and up to $50 million for wells in state and federal offshore
waters. The amounts are proportionately  reduced if we own less than 100% of the
well.  We also  maintain  $143  million in property  insurance  on our  offshore
properties.  We also carry business  interruption  insurance on our  significant
properties,  which covers the estimated  cash flows from each property  after it
has been non-producing for 21 days and reimburses us for those amounts for up to
six months. Finally, our officers and directors are indemnified by PANACO and we
maintain  insurance  of $3 million,  which is designed to reimburse us for legal
fees  incurred  in defense  costs.  We believe  that our  insurance  coverage is
adequate  and the  underwriters  of our  insurance  will be able to satisfy  any
claims  made.  However,  we can not assure you that this  insurance  or that the
underwriters  will adequately  cover all of the costs or that we will be able to
continue to purchase insurance at reasonable prices. Even one significant event,
if not adequately insured,  could  significantly  impair our financial condition
and results of operations.

Funding of Business Activities

Working Capital Deficit

        Due to  substantial  losses  incurred  in 1999 and  2001  and less  than
anticipated  results from our drilling program in late 2000 and most of 2001, we
accumulated a significant  working  capital deficit as of December 31, 2001. The
deficit totaled $24.4 million. The lack of performance from wells drilled during

                                       8
<PAGE>
2000 and 2001,  along with  decreased  commodity  prices in late  2001,  reduced
estimated future net cash flows and availability  under our Credit Facility to a
point at which there is substantial  doubt about the Company's ability to reduce
this deficit in a timely manner.  As a result, we may not be able to continue as
a going concern. See Note 2 to financial statements.

        Given this  situation,  we engaged an  investment  bank in early 2002 to
help us explore strategic  financial  alternatives.  The outcome of this process
may result in asset sales or the sale of the Company as a whole.  PANACO is also
in discussions to increase the amount of our Credit Facility,  which may require
a waiver from the holders of the Senior Notes. No assurances can be made that we
will be able to implement any plan that will resolve the working capital deficit
or that a plan will be  implemented  in a timely  manner.  In addition,  some of
these  alternatives may require approval from our Credit Facility lenders or the
approval of our Senior Note holders as well as Shareholder approval.

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 November  2001, we amended a Credit  Facility that was originally put
in place in September 1999. The amendment  reduced the facility from $60 million
to $40 million,  in order to reduce  interest and debt service costs  associated
with the facility.  The new facility is for two years and  borrowings  under the
facility  bear interest at either the Wells Fargo prime rate plus 0.25% to 0.75%
or at LIBOR  plus  2.25% to  2.75%,  both  depending  on the  percentage  of the
facility used, and has a minimum  interest rate of 6.75%.  At December 31, 2001,
PANACO had $32.9 million borrowed under the Credit  Facility,  with $6.1 million
of availability, of which $1.3 million was reserved by a letter of credit.

        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
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.  The  Credit  Facility  also  contains  certain
limitations on mergers, additional indebtedness and pledging or selling assets.

        In  March  2002,  the  Credit  Facility  was  amended  in  order to cure
covenants that we were not able to satisfy on December 31, 2001.  This amendment
requires a working  capital  ratio (as defined in the  agreement) of 0.15 to 1.0
from January 1 to April 30, 2002, 0.20 to 1.0 from May 1 to January 1, 2003, and
0.25 to 1.0  thereafter.  The amendment  also  requires a trailing  twelve-month
EBITDA/interest  coverage  ratio  ranging from a monthly high of 2.0 to 1.0 to a
monthly low of 0.55 to 1.0 for 2002, and 2.0 to 1.0 thereafter. In addition, the
amendment  eliminates the requirement for hedges until March 31, 2002.  Based on
current  projections,  we believe we will be in compliance with all of the terms
of the agreement through December 31, 2002.  However, no assurances can be given
that we will be in compliance through December 31, 2002. As a result, we may not
be able to continue as a going concern. See Note 2 to financial statements.

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 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.  We can also redeem all or part of the

                                       9
<PAGE>
Senior Notes, at our option, after October 1, 2001, at certain prices, which are
specified in the indenture, plus accrued interest to date.

        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  ("ACNTA"),  as defined in the
Indenture,  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.
At  December  31,  2001  PANACO  did not meet  this  ratio.  If this  deficiency
continues  through March 31, 2002, the Company will be required to make an offer
to repurchase an amount of the notes (at par plus accrued  interest)  sufficient
to meet the ratio  required in  the  agreement. Actual results through March 31,
2002 are not yet available,  however,  based on increased  market prices for oil
and natural gas, we estimate  that the Company will be in  compliance  with this
covenant  at March 31, 2002 and we will not be required to make such an offer to
the holders of the Senior Notes.  However,  no  assurances  can be given that we
will meet this  covenant  or that the  Company  will be able to  repurchase  the
amount of the notes  required under the  Indenture.  As a result,  we may not be
able to continue as a going concern. See Note 2 to financial statements.

        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.

Common and Preferred Stock

        On  December  31,  2001 there were  24,359,695  shares of $.01 par value
common stock issued and outstanding.  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.

                                       10
<PAGE>
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 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 the supply and prices 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 former 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.

                                       11
<PAGE>
        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
"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."

                                       12
<PAGE>
Employees

        We have 21 full time employees, four 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 2001 and 1999 and are  significantly
leveraged.  PANACO's  debt totaled  $135.1  million at December 31, 2001 and our
stockholders'  deficit  was $29.8  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,  and (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."

        In  March  2002,  the  Credit  Facility  was  amended  in  order to cure
covenants that we were not able to satisfy on December 31, 2001.  This amendment
requires a working  capital  ratio (as defined in the  agreement) of 0.15 to 1.0
from January 1 to April 30, 2002, 0.20 to 1.0 from May 1 to January 1, 2003, and
0.25 to 1.0  thereafter.  The amendment  also  requires a trailing  twelve-month
EBITDA/interest  coverage  ratio  ranging from a monthly high of 2.0 to 1.0 to a
monthly low of 0.55 to 1.0 for 2002, and 2.0 to 1.0 thereafter. In addition, the

                                       13
<PAGE>
amendment  eliminates the requirement for hedges until March 31, 2002.  Based on
current  projections,  we believe we will be in compliance with all of the terms
of the agreement through December 31, 2002.

        We must maintain a total Adjusted  Consolidated Net Tangible Asset Value
("ACNTA"), as defined in the Indenture, 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. At December 31, 2001 PANACO did not meet this
ratio. If this deficiency  continues through March 31, 2002, the Company will be
required  to make an offer to  repurchase  an  amount  of the notes (at par plus
accrued interest) sufficient to meet the ratio required in the agreement.  Based
on increased market prices for oil and natural gas, we estimate that the Company
will be in  compliance  with this  covenant at March 31, 2002 and we will not be
required to make such an offer to the holders of the Senior Notes.  However,  no
assurances can be given that we will meet this covenant or that the Company will
be able to repurchase the amount of the notes required under the Indenture.

        Due to  substantial  losses  incurred  in 1999 and  2001  and less  than
anticipated  results from our drilling program in late 2000 and most of 2001, we
accumulated a significant  working  capital deficit as of December 31, 2001. The
deficit totaled $24.4 million. The lack of performance from wells drilled during
2000 and 2001,  along with  decreased  commodity  prices in late  2001,  reduced
estimated future net cash flows and availability  under our Credit Facility to a
point at which there is substantial  doubt about the Company's ability to reduce
this deficit in a timely manner. See Note 2 to financial statements.

        Given this  situation,  we engaged an  investment  bank in early 2002 to
help us explore strategic  financial  alternatives.  The outcome of this process
may result in asset sales or the sale of the Company as a whole.  PANACO is also
in discussions to increase the amount of our Credit Facility,  which may require
a waiver from the holders of the Senior Notes. No assurances can be made that we
will be able to implement any plan that will resolve the working capital deficit
or that a plan will be  implemented  in a timely  manner.  In addition,  some of
these  alternatives may require approval from our Credit Facility lenders or the
approval of our Senior Note holders as well as Shareholder approval.  See Note 2
to financial statements.

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

                                       14
<PAGE>
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,
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,  2001  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, 2001 were
$2.69 per Mcf of natural gas and $18.56 per barrel of oil.

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

                                       15
<PAGE>
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, 2001, 51% of
total oil and natural gas revenue  came from our largest  natural gas  purchaser
and  18%  came  from  our  largest  oil  purchaser.   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.  For the year ended December
31, 2000, one natural gas purchaser  accounted for  approximately 39% of our oil
and natural gas  revenues.  During  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.  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.

Hedging Risks

        We typically  hedge a portion of PANACO's oil and natural gas production
during  periods  when  either  market  prices for our  products  are higher than
historical  average  prices or when we are required to do so by our lenders.  We
have hedged as much as 80% of PANACO's  oil and  natural  gas  production  on an
annualized basis. During 2001 we hedged 61% of annual natural gas production and
30% of annual oil  production.  On March 28, 2002 we put in place two hedges for
both oil and natural gas  produced  from May 1 through  October  31,  2002.  The
natural  gas hedge is a cost-free  collar on 3,000 MMbtu and  contains a minimum
price of $3.00 per MMbtu and a maximum  price of $3.45 per MMbtu to be  received
for the quantity  hedged.  The oil hedge is a swap on 500 barrels of oil per day
with prices ranging from $24.96 per barrel to $25.87 per barrel for the quantity
hedged.  The volumes hedged account for 21% and 18%,  respectively,  of PANACO's
current estimates of total production for the periods hedged.

        Typically,  we have used  swaps,  cost-free  collars  and options to put
products  to a  purchaser  at  a  specified  price  (or  a  "floor").  In  these
transactions,  we will usually have the option to receive from the  counterparty
to the  hedge a  specified  price or the  excess  of a  specified  price  over a
floating  market 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.

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,
less any cash deposited in escrow  accounts for these  obligations.  These costs
are usually higher on offshore properties,  as are most expenditures on offshore
properties.  As of December 31, 2001, our total estimated abandonment costs, net
of $11.0 million already in escrow, were approximately $11.0 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,

                                       16
<PAGE>
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 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,  2001 our Proved  Reserves  totaled 114 Bcfe and had a
Pretax PV-10 value of $89.2  million.  Approximately  75% of these  reserves are
classified as Proved Developed  Reserves and  approximately 59% 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 67 producing oil wells and 114 producing natural gas
wells.

        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 seven acquisitions of producing
properties that had Proved Reserves of 169 Bcfe at the time of their  respective
acquisitions. We paid a total of $111.2 million for the Proved Reserve component

                                       17
<PAGE>
of those acquisitions.  By focusing on larger acquisitions,  our reserve base is
concentrated in a small number of properties.  The following is a summary of our
significant  properties as of December 31, 2001. These properties  represent 78%
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>                      <C>              <C>                        <C>
East Breaks 160/161/205           1,054                    10.5             $     22,320               25%
West Delta 54                       275                    11.5                   16,068               18
Umbrella Point                    1,084                     5.0                   11,827               13
East Breaks 165                   2,635                    17.0                    8,867               10
East Breaks 109                      20                     8.4                    5,488                6
West Delta 52                       669                     1.7                    4,994                6
---------------------------------------------------------------------------------------------------------------------
          Total                   5,737                    54.1             $     69,564               78%
</TABLE>

East Breaks 160/161/205

        The East Breaks 160 Field is located offshore Texas,  approximately  100
miles south of Galveston,  in water depths of approximately  930 feet. The Field
is owned equally by PANACO, BP, and Unocal, with Unocal as the operator.

        The Field is  comprised  of two blocks,  East Breaks  Block 160 and East
Breaks Block 161,  which were  originally  leased in 1974.  Field  production is
handled on the Cervesa platform, located on Block 160. The production from which
is currently at 23,930 Mcf of natural gas per day,  3,324 barrels of oil per day
and 3,728 barrels of water per day from 12 wells.

        In the summer of 2001 PANACO participated in a two well drilling program
proposed by Unocal.  The first well, a gas well drilled in Block 205, was put on
stream in  December of 2001 at a  production  rate of 17,000  Mcfpd.  During the
month of February, 2002 this well was producing at a daily rate of 21,754 Mcf of
natural gas. The second well in the program was an oil well drilled in Block 161
and also put on production in December,  2001 producing 1,200 barrels of oil per
day.  During March 2002,  this well averaged  1,800 barrels of oil per day. Both
wells  are  sub-sea  completions  and are tied  back to the  Block  160  Cervesa
platform.

        The East Breaks 160 property has significant exploration potential.  The
operator is  scheduled  to drill two  additional  wells in the third  quarter of
2002.  Both  wells  can  be  drilled  from  the  existing   platform,   possibly
sidetracking  out  of  one  of  the  original  wellbores,  and  target  multiple
objectives in the GA1 and GA3 sands.

        Utilizing  the  Field's   existing   infrastructure,   PANACO   receives
processing fees from a former Mobil sub-sea well, now owned by BP Amoco, drilled
in Block  117.  Because  of the  platform's  strategic  location  on the edge of
deepwater,  the facility has potential for  additional  processing  and handling
fees as discoveries are made nearby and tied into the platform.

        PANACO owns 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,  as well as 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 Samedan  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 even after the Field reserves are
depleted.

                                       18
<PAGE>
West Delta 54

        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 1950's and has  continued to produce  hydrocarbons  since
then.  Drilling and other activities  continue in the West Delta area. There are
currently  approximately 40 total wells in the Field,  which produce from depths
ranging from 900' to 17,000'.  PANACO operates the Field and generally owns 100%
of most of the area's 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, a  significant  portion of the  production  facilities  was rebuilt
after being damaged by a third party

        The geology is  characterized by multiple  reservoirs,  which we believe
provide more  opportunities for successful  drilling  activities.  Both 2001 and
2000  continued  to be  active  periods  at West  Delta,  with  three  completed
development  wells by PANACO and four exploratory  wells 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 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  handling  of
production.

        In  the  three  wells  completed  by  Basin  Exploration,   PANACO  owns
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.

        West Delta Block 54 was producing 180 barrels of oil per day,  4,800 Mcf
of natural gas per day and 5,600 barrels of water per day as of February 2002.

Umbrella Point

        Umbrella  Point Field is a well defined,  low relief,  4-way  structural
closure centered on State Tracts 73, 74, 87 and 88 in the  Galveston/Trinity Bay
portion of  Chambers  County,  Texas.  It is located  three  miles from shore in
approximately ten feet of water, 32 miles east-southeast of Houston,  Texas. The
Field was  discovered  in 1957 by Sun Oil Company.  Sun,  along with  Tidewater,
initially  developed  the  Field in the late  1950's  and  early  1960's.  Field
development  continued  in the  1970's by Getty,  in the early  1990's by French
Operating Company, and in the late 1990's by PANACO, Inc. Since its discovery in
1957, 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 the leases
that encompass the Field. Oil production is gathered on a small platform complex
and  transported via PANACO's  five-mile oil pipeline to our onshore  production
facility  at Cedar  Point and gas  production  is  transported  through a Midcon
Pipeline Co. pipeline.

        On January 21, 1998 we announced the successful  completion of our first
new well in the Umbrella Point Field.  The well flowed 11,500 Mcf of natural gas
per day and 220 barrels of  condensate  per day. The  production  from this well
peaked at 27,000  Mcf per day of natural  gas and 460  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 with Peoples Energy  Production
owning the remaining 20%.
                                       19
<PAGE>
        In 2001 PANACO  drilled an exploratory  well on the property,  the State
Tract 73 No. 6 well,  to test the  Vicksburg  sand.  This  well  encountered  no
productive pay zones and was plugged and abandoned.

        Current production from the Umbrella Point Field is 1,000 Mcf of natural
gas per day and 240 barrels of oil per day.

West Delta 52

        PANACO acquired a 100% working interest in a portion of West Delta Block
52 Field in April 2001 from Delta Petroleum Corporation.

        The  acquisition  included  seven  producing oil wells,  one  salt-water
disposal well and 18 shut-in wells.  At that time a 7,600' oil sand was the only
productive sand for the property, producing approximately 180-200 barrels of oil
per day. No gas was being sold.

        The geology of the field was remapped  immediately after PANACO acquired
the  property,  resulting in  significant  dry gas  reserves  from at least four
shallower sands from 3,000'-6,500'.  Workovers performed during 2001 resulted in
three dry gas sand completions from three separate  reservoirs.  Other potential
dry gas reserves are expected when additional future workovers are completed.

        In 2001 we  completed  three new gas  wells  with  sufficient  resulting
production  to  allow  us to  maintain  operations  of  the  oil  wells  without
purchasing additional gas. PANACO currently has six oil wells producing from the
7,600' oil sand and three dry gas wells producing from intervals  between 4,780'
and  6,400'.  February 2002  production  averaged 900 Mcf of natural gas per day
and 220 barrels of oil per day.

East Breaks 165

        East Breaks  Block 165 was  acquired by Sohio  Petroleum  Company at the
Federal OCS Lease Sale in August  1983.  In mid 1984,  significant  hydrocarbons
were  discovered  in the first well on the block,  including 111 feet of gas pay
and 156 feet of oil pay. BP bought Sohio  Petroleum  in the late 1980's,  and by
January 1990 BP had drilled and completed  well number 30. PANACO  purchased the
East Breaks 165 platform (known as the "Snapper" platform) from BP in May 1998.

        The East  Breaks  165  geological  structure  is an  interdomal  faulted
paleostructure.  The shallower  horizons exhibit four-way dip closure,  while at
deeper horizons a faulted anticline is mapped.  The main reservoir sands at East
Breaks 165 are of excellent quality.  Their apparent  mineralogical and textural
maturity, within an otherwise deepwater sequence, suggests they were transported
some  distance  from a  high-energy  shelf  area  into a  slope  environment  of
disposition. The massive nature of individual beds coupled with sparsely "fining
upwards"  sands,  indicate that  sediment  transport  occurred  mainly by bottom
traction  within a major channel  feeder  system at the edge of the shelf,  with
re-deposition  in the  East  Breaks  165/209  area.  There is a  combination  of
structural  and  stratigraphic  traps in the 12 different main sands in the East
Breaks 165 area.

        3-D  Seismic  was  generated  on the East Breaks 165 area and PANACO has
recently  reprocessed  this data.  The new  reprocessed  data better defines the
structural  morphology,   improves  the  fault  resolution,  better  images  the
potentially  productive  upthrown fault block to the north, and clarifies limits
of the production.

        Presently there are 30 wells on the platform, of which 16 are producing.
The total  production per day from the platform is 1,150 barrels of oil per day,
1,600 Mcf of natural gas per day and 5,700 barrels of water per day.
                                       20
<PAGE>
        PANACO has identified three drilling prospects on the E.B. 165 structure
which are supported by 3-D Seismic amplitude anomalies.

East Breaks 109

        East  Breaks  109/110  is  located  approximately  100  miles  south  of
Galveston  Island,  offshore Texas, in water depths of  approximately  650 feet.
Blocks 109 and 110 were acquired by Texaco and Columbia Gas in July 1974 and the
companies proceeded to drill four wells on the two blocks. In early 1978, Texaco
farmed out its interest to Zapata.  The platform was  installed in 663' of water
in the  summer  of 1984 and  Zapata  and  Columbia  drilled  five  joint  wells.
Effective  January 1, 1985,  Zapata  purchased  the interest of Columbia Gas and
went on to drill five  additional  wells.PANACO  acquired  100% interest in East
Breaks  109/110  Field from  Zapata in July of 1995.  In addition to the mineral
interests acquired,  PANACO purchased 100% interest in a 31 mile 10" natural gas
pipeline  connecting  the East Breaks 110  platform to the High Island  Offshore
System as well as a 22 mile 4" oil  pipeline  that  connects  to the High Island
Pipeline System.

        During  2001  PANACO  drilled  three  new  wells  on  the  property  and
sidetracked  three others.  The drilling and sidetrack  program  increased Field
production  by 21,000 Mcf of natural  gas per day.  Currently,  four  additional
drilling  prospects have been  identified on the property.  Production  from the
Field at the  time of this  writing  is 4,900  Mcf of  natural  gas per day,  37
barrels of oil per day and 600 barrels of water per day.

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 76% of the Pretax PV-10 of our reserve estimates.

        Our proved oil reserves totaled 7.9 million barrels at December 31, 2001
compared to 8.1 million  barrels at December  31, 2000.  Our proved  natural gas
reserves  totaled  66.9 Bcf at  December  31,  2001 as  compared  to 82.2 Bcf at
December 31, 2000. The Pretax PV-10 value of these reserves  totaled $89 million
at December 31, 2001 compared to $533 million at December 31, 2000.  The largest
impact on the PV-10  value of  PANACO's  reserves  was lower  prices for oil and
natural gas.  Decreased  commodity  prices,  net of changes in production costs,
accounted  for over $400  million  of the  decrease,  which  was  offset by $125
million of lower future estimated income taxes. 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.

                                       21
<PAGE>
                               Producing Wells(a)

        The following table presents the number of producing oil and natural gas
wells attributable to our properties, as of December 31, 2001.
<TABLE>
<CAPTION>
                                                            Producing Wells             Company Operated
                                                            ---------------             -----------------
<S>     <C>    <C>    <C>    <C>    <C>
       Gross producing offshore wells(b):
           Oil    .........................................         26                          18
           Natural Gas   ..................................         57                          36
                                                                   ---                         ---
                Total  ....................................         83                          54
       Net producing offshore wells(c):
           Oil    .........................................         24                          18
           Natural Gas   ..................................         30                          36
                                                                   ---                         ---
                Total  ....................................         54                          54
       Gross producing onshore wells(b):
           Oil    .........................................         41                          31
           Natural Gas   ..................................         57                          13
                                                                   ---                         ---
                Total  ....................................         98                          44

       Net productive onshore wells(c):
           Oil    .........................................         33                          33
           Natural Gas   ..................................          3                           3
                                                                   ---                         ---
                Total  ....................................         36                          36
<FN>
----------
(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.
</FN>
</TABLE>

                                Leasehold Acreage

        The   following   table   presents  the  estimated   developed   acreage
attributable to our properties, as of December 31, 2001.
<TABLE>

<S>     <C>    <C>                                                                             <C>
        Developed onshore acreage(a):
                Gross acres(b)...........................................................      3,626
                Net acres(c).............................................................      1,940

        Undeveloped onshore acreage(a):
                Gross acres(b)...........................................................      3,838
                Net acres(c).............................................................      2,713

        Developed offshore acreage(a):
                Gross acres(b)...........................................................     83,650
                Net acres(c).............................................................     40,972

        Undeveloped offshore acreage(a)(d):
                Gross acres(b)...........................................................      1,360
                Net acres(c).............................................................        560
<FN>
----------
(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.
(d) In  addition  to these  acres, our undeveloped  offshore potential exists at
greater depths beneath existing producing reservoirs.
</FN>
</TABLE>
                                       22
<PAGE>
                               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,  2001.  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>
1997      6         13        --       1                    --        --      --      --
1998      1          9        --      --                    --         3      --       6
1999      1         --        --      --                    --         4      --       3
2000     --          6        --      --                    --         2      --       1
2001     --          3        --      --                     2         6      --       2
        ---        ---       ---     ---                   ---       ---     ---     ---
Total     8         31        --       1                     2        15      --      12
</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.

        We are presently a party to several 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  24,359,695  shares are issued and
outstanding as of March 25, 2002 and are held by over 5,500 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.

                                       23
<PAGE>

        Each Common Share is entitled to  participate  equally in dividends,  as
and when declared by the Board of Directors,  and in the  distribution of assets
in the event of liquidation, subject in all cases to any prior rights of 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 425,000 Common Shares at a
price of $1.92 per share,  which 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.

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,  59 Maiden Lane, New
York, NY 10007.

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>

                                                           2001
                                              --------------------------------

           1st Quarter                  2nd Quarter                     3rd Quarter                    4th Quarter
           -----------                  -----------                     -----------                    -----------
<S>           <C>                           <C>                            <C>                            <C>
Low          $  2.19                       $ 2.12                         $ 0.93                          $ 0.78
High         $  3.25                       $ 2.85                         $ 2.43                          $ 1.72

<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
</TABLE>

        On March 25,  2002,  the last sale price of the Common  Shares was $0.80
per share.

Potential De-listing

        Due to  significant  losses  in 1999 and  2001,  PANACO's  stockholder's
equity was reduced to a deficit of $29.8  million as of December 31, 2001.  As a
result,  the Company does not meet the requirements for continued listing on the


                                       24
<PAGE>

American Stock Exchange (the "Exchange").  Upon notification by the Exchange, we
would be  required  to present a plan that  would  bring the  Company  back into
compliance.  No  assurances  can be made that the plan would be approved or that
such a plan could be successfully executed.

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.

        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.
                                       25
<PAGE>
        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) ten days after the first public notice of
the annual meeting is sent to common  shareholders.  In general, the notice must
also contain certain information about the shareholder proposing the business or
nomination,  his interest in the business,  and (with respect to nominations for
director)  information about the nominee of the nature ordinarily required to be
disclosed  in public proxy  solicitations.  The  shareholder  must also submit a
notarized letter from each of his nominees  stating the nominee's  acceptance of
the nomination  and  indicating the nominee's  intention to serve as director if
elected.

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

        The Certificate of  Incorporation  provides that approval by the holders
of at least two-thirds of the outstanding voting shares is required to amend the
provisions  of the  Certificate  of  Incorporation  discussed  in the  preceding
paragraphs and certain other provisions,  except that approval by the holders of
at least 80% of the  outstanding  voting  shares,  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

                                       26
<PAGE>
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."

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,
                                                     2001           2000          1999           1998           1997
                                                     ----           ----          ----           ----           ----
                                                               (amounts in thousands, except per share data)
<S>                                              <C>             <C>           <C>             <C>            <C>
    Oil and natural gas sales                    $  76,246       $  88,550     $  42,672       $  50,291      $  37,841
    Gain on sale of assets                           3,967           1,938           ---             ---            ---
    Lawsuit recoveries                                 ---           2,575           ---             ---            ---
                                                 -------------------------------------------------------------------------

    Total revenues                                  80,213          93,063        42,672          50,291         37,841

    Total costs and expenses before income
       taxes and extraordinary item (1)             99,784          76,591        77,568         100,242         36,864

    Income tax expense (benefit) (2)                22,734         (22,683)          ---          (3,100)           ---

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

    Net Income (loss) (3)                        $ (42,305)      $  39,155     $ (35,027)      $ (46,851)     $      43
                                                 =========================================================================

    Net Income (loss) per Common Share           $   (1.74)      $    1.61     $   (1.46)      $   (1.96)     $     ---
    Total assets                                 $ 146,064       $ 174,079     $ 135,438       $ 143,372      $  179,629
    Long-term debt                               $ 135,120       $ 121,693     $ 138,902       $ 115,749      $  101,700
    Stockholders' equity (deficit)               $ (29,784)      $  12,408     $ (26,875)      $   7,902      $   55,188

<FN>
(1)  Results  for the years  ended  December  31,  2001,  1999 and 1998  include
     impairments  of oil and gas  properties of $9.1 million,  $13.2 million and
     $20.4 million, respectively.
(2)  During 2001 the Company  re-established a deferred tax valuation  allowance
     that had been eliminated in 2000. The change in the valuation allowance was
     primarily  due to lower  volumes and market prices for oil and natural gas,
     resulting  in lower  estimates  of future  net  income,  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, 2001.  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.
</FN>
</TABLE>

                                       27
<PAGE>

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  ("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

        As a result of much higher oil and  natural  gas prices  during 2000 and
2001,  PANACO  realized record high cash flows from operations in 2000 and 2001.
With  the  market  prices  for  acquisitions   increasing,   PANACO  focused  on
developmental and exploratory  drilling in both of these years.  During 2001, we
used all of our cash flows from  operating  activities  for  drilling new wells,
primarily  in the Gulf of Mexico,  and for the  acquisition  of an oil  property
contiguous with a property that we already owned.  While we were successful on a
percentage  completion  basis,  (85%) of total new wells  drilled,  the reserves
discovered  did not  amount  to the  level  anticipated.  The  result  was lower
production  during  2001  and  lower  reserves  in  place  at the  end of  2001.
Consequently,  the  combination  of lower  production and a decline in commodity
prices during 2001 resulted in lower than projected cash flows from operations.

        PANACO's  2001 capital  spending  totaled $45.0  million,  of which $3.9
million was for the acquisition of proved oil reserves and the remainder was for
exploratory and developmental  drilling. We also sold an offshore,  non-operated
property  in 2001 and  deposited  $2.4  million  of cash  into  restricted  cash
accounts as required under  agreements in place.  Our cash flows from operations
were  used to fund the 2001  expenditure  program,  which  also  required  a net
increase in debt of $13.4 million,  funded by PANACO's  amended Credit Facility.
At December 31, 2001,  PANACO's  balance due under the Credit Facility was $32.9
million, leaving $4.8 million available after a $1.3 million letter of credit.

        At December 31, 2001, 81% of PANACO's  total assets were  represented by
oil and natural gas  properties,  pipelines and  equipment,  net of  accumulated
depletion, depreciation 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. The timing of the receipt of monies
due us,  the  timing of  payments  we make to  vendors,  the  timing of  capital
expenditures and revenues all impact PANACO's working capital.  PANACO's working

                                       28
<PAGE>
capital  deficit  totaled $24.4 million at December 31, 2001. Due to substantial
losses  incurred  in 1999 and 2001 and less than  anticipated  results  from our
drilling  program in late 2000 and most of 2001,  we  accumulated  a significant
working  capital  deficit as of December 31,  2001.  The deficit  totaled  $24.4
million.  The lack of performance from wells drilled during 2000 and 2001, along
with decreased  commodity prices in late 2001, reduced estimated future net cash
flows and  availability  under our Credit  Facility to a point at which there is
substantial doubt about the Company's ability to reduce this deficit in a timely
manner. See Note 2 to financial statements.

        Given this  situation,  we engaged an  investment  bank in early 2002 to
help us explore strategic  financial  alternatives.  The outcome of this process
may result in asset sales or the sale of the Company as a whole.  PANACO is also
in discussions to increase the amount of our Credit Facility,  which may require
a waiver from the holders of the Senior Notes. No assurances can be made that we
will be able to implement any plan that will resolve the working capital deficit
or that a plan will be implemented in a timely manner.  As a result,  we may not
be able to continue as a going concern. In addition,  some of these alternatives
may require  approval  from our Credit  Facility  lenders or the approval of our
Senior Note holders as well as Shareholder approval.

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.

        At December 31, 2001 the Company was not in compliance  with a financial
covenant in the Senior Notes indenture.  The covenant requires a specified ratio
of assets (as  defined in the  agreement)  to total  indebtedness.  Should  this
condition continue to exist for two successive quarters, the Company is required
to make an offer to the Senior Note holders to repurchase an amount of the notes
(at par plus  accrued  interest)  sufficient  to meet the ratio  required in the
indenture. Based on increased market prices for oil and natural gas, we estimate
that the Company will be in compliance  with this covenant at March 31, 2002 and
we will not be  required  to make  such an offer to the  holders  of the  Senior
Notes.  However,  no assurances  can be given that we will meet this covenant or
that the Company  will be able to  repurchase  the amount of the notes  required
under the Indenture. As  a  result,  we may not be able to  continue  as a going
concern. See Note 2 to financial statements.

Contractual Obligations and Commercial Commitments

        The following  table sets forth PANACO's  obligations and commitments to
make future  payments under its debt  agreements,  lease  agreements,  and other
long-term obligations as of December 31, 2001.
<TABLE>
<CAPTION>
                                                                         PAYMENTS DUE BY PERIOD
                                                                         (Amounts in Thousands)
                                               ----------------------------------------------------------------------------
                                                                Less than
          Contractural Obligations                 Total         1 Year        1-3 Years      4-5 Years     After 5 Years
---------------------------------------------------------------------------------------------------------------------------
<S>                                            <C>            <C>            <C>            <C>            <C>
Principal Payments on Long-Term Debt           $     132,871  $          --  $     132,871  $          --  $          --
Interest Payments on Long-Term Debt                   35,758         12,844         22,914             --             --
Operating Leases:
Office Space                                           1,339            459            880             --             --
                                               -------------  -------------  -------------  -------------  -------------
Total Contractual Cash Obligations             $     169,968  $      13,303  $     156,665  $          --  $          --
                                               =============  =============  =============  =============  =============
</TABLE>

                                       29
<PAGE>
<TABLE>
<CAPTION>

                                                                AMOUNT OF COMMITMENT EXPIRATION BY PERIOD
                                                                         (Amounts in Thousands)
                                               ----------------------------------------------------------------------------
                                                   Total
                                                   Amount
                                                  Committed     Less than
        Other Commercial Commitments                             1 Year        1-3 Years      4-5 Years     After 5 Years
---------------------------------------------------------------------------------------------------------------------------
<S>                                            <C>            <C>            <C>            <C>            <C>
Standby Letters of Credit                      $       1,300  $          --  $          --  $          --  $        1,300
                                               -------------  -------------  -------------  -------------  --------------
Total Other Commercial Commitments             $       1,300  $          --  $          --  $          --  $        1,300
                                               =============  =============  =============  =============  ==============
</TABLE>

        Contractual obligations excludes a production payment that is a property
specific,  non-recourse,  obligation  of  PANACO.  Interest  amounts  due  under
PANACO's Credit Facility are calculated assuming the rate and balance due remain
constant over the term of the facility.

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 November  2001, we amended a Credit  Facility that was originally put
in place in September 1999. The amendment  reduced the facility from $60 million
to $40 million,  in order to reduce  interest and debt service costs  associated
with the facility.  The new facility is for two years and  borrowings  under the
facility  bear interest at either the Wells Fargo prime rate plus 0.25% to 0.75%
or at LIBOR  plus  2.25% to  2.75%,  both  depending  on the  percentage  of the
facility used, and has a minimum  interest rate of 6.75%.  At December 31, 2001,
PANACO had $32.9 million borrowed under the Credit  Facility,  with $6.1 million
of availability, of which $1.3 million was reserved by a letter of credit.

        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
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.  The  Credit  Facility  also  contains  certain
limitations on mergers, additional indebtedness and pledging or selling assets.

        In  March  2002,  the  Credit  Facility  was  amended  in  order to cure
covenants that we were not able to satisfy on December 31, 2001.  This amendment
requires a working  capital  ratio (as defined in the  agreement) of 0.15 to 1.0
from January 1 to April 30, 2002, 0.20 to 1.0 from May 1 to January 1, 2003, and
0.25 to 1.0  thereafter.  The amendment  also  requires a trailing  twelve-month
EBITDA/interest  coverage  ratio  ranging from a monthly high of 2.0 to 1.0 to a
monthly low of 0.55 to 1.0 for 2002, and 2.0 to 1.0 thereafter. In addition, the
amendment  eliminates the requirement for hedges until March 31, 2002.  Based on
current  projections,  we believe we will be in compliance with all of the terms
of the agreement through December 31, 2002.  However, no assurances can be given
that we will be in compliance through December 31, 2002. As a result, we may not
be able to continue as a going concern. See Note 2 to financial statements.

Critical Accounting Policies

        Application of generally accepted accounting principles requires the use
of estimates,  judgments  and  assumptions  that affect the reported  amounts of
assets and  liabilities as of the date of the financial  statements and revenues
and expenses during the reporting  period.  In addition,  alternatives can exist
among various accounting methods. In such cases, the choice of accounting method
can also have a significant impact on reported amounts.

        The Company's  estimates of proved oil and gas reserve  quantities,  the
application of the successful  efforts method of accounting for our  exploration


                                       30
<PAGE>

and  production  activities,  the  application  of standards of  accounting  for
hedging  activities,  and the  accounting  method used for  revenue  recognition
require management to make numerous estimates and judgments.

Successful Efforts Method of Accounting for Oil and Gas Properties

        The Company's  exploration  and production  activities are accounted for
using the successful  efforts  method.  We believe that the  successful  efforts
method  is the most  appropriate  method to use to  account  for our oil and gas
production activities while allowing for comparable analysis with our peers.

        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.

        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.

Reserves

        Estimates  of PANACO's  proved oil and gas  reserves are prepared by our
third-party  engineers in accordance  with  guidelines  established  by the SEC.
Those  guidelines  require that reserve  estimates  be prepared  under  existing
economic and operating  conditions with no provisions for increases in commodity
prices except by contractual  arrangement and assuming  continuation of existing
operating conditions. Estimation of oil and gas reserve quantities is inherently
difficult and is subject to numerous  uncertainties.  Such uncertainties include
the  projection  of future  rates of  production  and the timing of  development
expenditures.  The accuracy of the estimates depends on the quality of available
geological  and  geophysical  data and  requires  interpretation  and  judgment.
Estimates  may be  revised  either  upward  or  downward  by  results  of future
drilling, testing or production. In addition, estimates of volumes considered to
be  commercially  recoverable  fluctuate  with changes in  commodity  prices and
operating  costs.  Third  party  engineering  firms  calculate  the  quantity of
PANACO's  reserves based on information we provide them. These reserve estimates
have a significant effect on DD&A expense and on asset impairment reviews.

Revenue Recognition

        The Company  recognizes its ownership interest in oil and gas production
as revenue.  Revenues from the sales of crude oil and natural gas are recognized
when  delivery to the  customer has  occurred  and title has  transferred.  This
usually  transpires  when  production  has been  delivered to the pipeline.  The
Company may have an interest  with other  producers  in certain  properties,  in
which case the  Company  uses the  entitlements  method to account  for sales of
production and imbalances. 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, 2001 the Company's  imbalance position was an over-produced,  or
payable balance of 265,000 Mcf valued at $1.1 million.
                                       31
<PAGE>
Hedging Activities

        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.  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
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.  On March 28, 2002 we put in place two hedges for both
oil and natural gas produced  from May 1 through  October 31, 2002.  The natural
gas hedge is a cost-free  collar on 3,000 MMbtu and contains a minimum  price of
$3.00 per MMbtu and a maximum  price of $3.45 per MMbtu to be  received  for the
quantity  hedged.  The oil  hedge is a swap on 500  barrels  of oil per day with
prices  ranging  from  $24.96 per  barrel to $25.87 per barrel for the  quantity
hedged.  The volumes hedged account for 21% and 18%,  respectively,  of PANACO's
current estimates of total production for the periods hedged.

                                       32
<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, 2001.
<TABLE>
<CAPTION>

                                                                    For the year ended December 31,
                                                          2001                   2000                    1999
                                                  ------------------------------------------------------------------
<S>     <C>    <C>    <C>    <C>    <C>    <C>
   Oil and Condensate:
     Net production (Bbls)(a)                              923,000              1,070,000               1,170,000
     Revenue                                       $    23,291,000         $   32,396,000         $    22,025,000
     Hedge gains (losses)                          $           ---         $     (710,000)        $    (1,784,000)
     Average net Bbl per day                                 2,529                  2,924                   3,204
     Average price per Bbl before hedges           $         25.23         $        30.28         $         18.83
     Average price per Bbl including hedges        $         25.23         $        29.62         $         17.31

   Natural Gas:
     Net production (Mcf)(a)                            10,703,000             13,547,000              11,114,000
     Revenue                                       $    49,419,000         $   57,246,000         $    25,267,000
     Hedge gains (losses)                          $     3,536,000         $     (382,000)        $    (2,836,000)
     Average net Mcf per day                                29,300                 37,000                  30,400
     Average price per Mcf before hedges           $          4.62         $         4.23         $          2.27
     Average price per Mcf including hedges        $          4.95         $         4.20         $          2.02

   Total oil and natural gas sales                 $    76,246,000         $   88,550,000         $    42,672,000

   Production costs                                $    24,658,000         $   20,876,000         $    17,740,000
     Total production (Mcfe)(b)                         16,241,000             19,996,000              18,132,000
     Production cost per Mcfe(b)                   $          1.52         $         1.05         $           .98
<FN>
      --------------
(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.
</FN>
</TABLE>

Results of Operations

Revenues

        One of the most significant factors affecting our business is the market
price of the 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
continued  through  early  2001 where we  benefited  from a steady  increase  in
realized prices.  The average  realized price, net of hedges,  has increased 46%
for oil and 145% for natural gas from 1999 to 2001.

        Primarily due to disappointing  results from PANACO's  drilling projects
in 2001,  both oil and natural gas production  declined from the previous years'
levels.  These declines  resulted in 14% lower oil and natural gas sales,  which
totaled $76.2  million in 2001.  While oil and natural gas  production  from the
East Breaks 110 and West Delta  Fields  increased,  they did not offset  natural
production  declines on most of our other fields.  Production at our East Breaks
160 Field began to increase in December 2001 with the addition of two new wells,
which should have a more meaningful  impact on the first quarter of 2002.  While
oil prices decreased 15% from 2000,  natural gas prices continued their increase
from 1999 and averaged  $4.95 per Mcf during 2001.  The most  significant  price
gains  were  realized  in the first half of 2001,  however,  by the end of 2001,
natural gas prices had dropped drastically.

                                       33
<PAGE>
        Our oil and  natural  gas  revenues  reached an  all-time  high of $88.6
million in 2000, a 108% increase over 1999.  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.  Once  commodity
prices  began to improve in late 1999,  we  increased  spending in that year and
through 2000, which resulted in increased production.

        During  2001  PANACO  sold  its  interest  in  a  non-operated  offshore
property, which resulted in a gain of $4.0 million. During the fourth quarter of
2000 we also sold two offshore  properties  resulting in a gain of $1.9 million.
Also,  two lawsuits  were  settled  during 2000 for which we received a total of
$2.6 million.

Cost and Expenses

        Lease  operating  expenses  ("LOE"),  totaled  $24.7 million in 2001, an
increase  of $3.8  million  over the  prior  year.  The  increase  is due to the
acquisition of the West Delta 52 Field in April 2001,  which  accounted for $2.2
million of additional  LOE. Also,  workover and repair  expenses  increased $1.2
million  over  2000.  These  expenses  are those  outside of  recurring  monthly
operating  expenses  and are  typically  for well and platform  maintenance  and
repairs.  Lease operating expenses also increased in 2000 when compared to 1999,
from $17.7  million to $20.9  million.  The primary  factor in the higher LOE in
2000 was an increase in workover and repair  expenses,  which began in late 1999
as PANACO began to increase overall capital spending. LOE for 2000 includes $5.7
million of workover  and repair  expenses as compared to $1.0  million for these
same expenses in 1999.

        Depletion,  depreciation and amortization  ("DD&A"),  increased to $34.5
million in 2001, from $27.0 million in 2000.  While total  production  decreased
19% for the same period, PANACO's DD&A per Mcf equivalent ("Mcfe") of production
increased 57% to $2.12 per Mcfe in 2001,  from $1.35 in 2000.  The increase from
2000 is primarily  due to the  disappointing  results at East Breaks 110,  where
PANACO's finding cost for reserves increased significantly. DD&A increased 2% in
2000 to $27.0  million,  compared to $26.4 million in 1999. The increase was 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  Mcfe in 1999 to $1.35  per Mcfe in 2000.  The
decrease in depletion per Mcfe was primarily due to property impairments in 1999
totaling $13.2 million.  This impairment reduced the remaining capitalized costs
to be depleted in 2000.

        General and  administrative  expenses ("G&A")  decreased $0.9 million in
2001, to $4.0  million.  The 2000 G&A was higher due to bonuses paid in 2000 and
higher staffing levels in that year.  During 2001 PANACO reduced G&A expenses by
reducing the number of employees  and focusing on  controlling  costs.  We began
2001 with 37  employees  and ended  2001 with 31  employees.  G&A  totaled  $4.9
million and $3.9 million in 2000 and 1999, respectively. The increase in 2000 of
$1.0 million relates  primarily to the $0.6 million of employee  bonuses paid in
2000, as there were no bonuses paid in 1999.

        Bad debt expense increased to $3.3 million in 2001, from $0.3 million in
2000 and $0.1 million in 1999.  The increase in 2001 relates to the write-off of
a receivable from Enron of $3.0 million, $1.2 million of which was for the final
payment due under a natural gas swap  agreement and $1.8 million for natural gas
sold to Enron through early December 2001. PANACO no longer sells any production
to Enron.

        Production  and ad  valorem  taxes  remained  relatively  flat in  2001,
totaling $2.0 million,  when compared to 2000, which totaled $2.1 million.  When
comparing  2000 to 1999,  the increase of $0.9 million is due to the increase in
total  revenues.  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.

                                       34
<PAGE>
        Exploratory  dry hole expense and  geological  and  geophysical  expense
(collectively  referred to as "exploration  expenses")  totaled $9.3 million and
$5.7  million in 2001 and 2000,  respectively.  With the  increase  in  drilling
activity  by PANACO  in 2001 and  2000,  versus  acquisitions,  our  exploration
expenses also increased.  The two largest  components of exploration  expense in
2001 were  unsuccessful  wells  drilled at East  Breaks 110 ($3.9  million)  and
Umbrella  Point ($3.8  million).  The  increase of $3.2  million in  exploration
expenses in 2000 over 1999, was due to three  unsuccessful  wells  drilled,  the
largest  of which  was also in the East  Breaks  110  Field,  and  totaled  $2.3
million.

        During 2001 PANACO recognized an asset impairment of $9.1 million,  $1.9
million of which related to an unproved property, based on the unsuccessful well
at Umbrella  Point.  The balance of the  impairment  was due to lower  estimated
future net revenues for our proved properties primarily as a result of declining
oil and natural gas prices as well as reserve volume reductions.  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 connection with a reserve
reduction  on a  proved  property.  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.

        PANACO's  average  borrowings  during  most of  2001  under  the  Credit
Facility  were  equal  to or lower  than  the  levels  outstanding  in 2000.  In
addition,  as the prime rate decreased in 2001,  our average  interest rate also
decreased, resulting in a $2.3 million decrease in net interest expense in 2001.
During 2000 net interest  expense  increased  primarily due to higher  borrowing
levels  under our Credit  Facility.  During 2000 our weighted  average  interest
rates also increased due to two factors (1) the new Credit Facility put in place
in late  1999 and (2)  increases  in the prime  rate,  which is the base for our
Credit Facility interest rate.

Income Tax Expense/(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.  During  2001,  the  decrease  in oil and  natural  gas  prices had the
opposite effect. In the latter part of 2001,  future net income  projections had
decreased to a point at which we were not able to project  sufficient net income
to utilize any of the net operating  loss  carry-forwards.  As such, a valuation
allowance of $30.1 million was re-established.

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 the effect oil and natural gas price fluctuations have on
our Company.

                                       35
<PAGE>

        Due to results that were below  expectations  during 2001,  we ended the
year with lower  reserves than those at the  beginning of the year,  despite $45
million  in  capital  expenditures.  In  addition,  lower  production  and lower
commodity  prices caused our total debt and working  capital deficit to increase
by $13.4  million  and $7.8  million,  respectively.  In an effort to reduce the
working  capital  deficit,  we have  delayed most of the 2002  approved  capital
budget of $25 million  until April 1, 2002,  at which time we will  evaluate our
financial situation and decide at that point whether to proceed with the capital
projects or delay them further.  By doing so, production and cash flows for 2002
could be  negatively  impacted.  The  capital  budget  for  2002 of $25  million
consists primarily of drilling, 45% of which we estimate will be exploratory and
55% of which we estimate  will be  developmental.  The  execution of this budget
depends  on  PANACO's  ability  to pay for the  projects  with cash  flows  from
operations.

        Given these issues,  PANACO engaged an investment  bank in early 2002 to
help the Company explore strategic financial  alternatives.  The outcome of this
process  may result in asset  sales or the sale of the  Company  as a whole.  No
assurances  can be made that the Company will be able to implement any plan that
will resolve the working capital deficit, ensure we maintain compliance with our
Credit Facility and Senior Note covenants, or that a plan will be implemented in
a timely  manner and, as a result,  the Company may not be able to continue as a
going concern.  In addition,  any of these alternatives will most likely require
approval from PANACO's Credit  Facility  lenders and may require the approval of
our Senior Note holders as well as Shareholder approval.

        We were required to amend our Credit  Facility  during the first quarter
of 2002  due to the  inability  to meet  certain  covenants  contained  in those
agreements.  We believe these changes will allow PANACO to meet the requirements
of these  agreements,  however,  we cannot assure you that we will be able to do
so. In addition,  availability  under the Credit Facility will be limited due to
higher borrowings.

        In March 2002, the Credit  Facility,  with  borrowings of $32.9 million,
was  amended  in order to cure  covenants  that we were not able to  satisfy  on
December 31, 2001.  This amendment  requires a working capital ratio (as defined
in the  agreement) of 0.15 to 1.0 from January 1 to April 30, 2002,  0.20 to 1.0
from May 1 to January 1, 2003,  and 0.25 to 1.0  thereafter.  The amendment also
requires a trailing twelve-month  EBITDA/interest  coverage ratio ranging from a
monthly high of 2.0 to 1.0 to a monthly low of 0.55 to 1.0 for 2002,  and 2.0 to
1.0  thereafter.  Based  on  current  projections,  we  believe  we  will  be in
compliance  with all of the terms of the Credit  Facility  through  December 31,
2002.  However, no assurances can be given that we will be in compliance through
December 31,  2002.  PANACO's  $100 million  of  Senior  Notes  require  that we
maintain a total  Adjusted  Consolidated  Net Tangible  Asset  Value  ("ACNTA"),
as defined in the  Indenture,  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. At December 31, 2001 PANACO did not meet this ratio. Actual
results  through   March  31, 2002 are  not yet  available,  however,  based  on
increased  market  prices for oil and natural gas, we estimate  that the Company
will be in  compliance  with  the  covenant  at  March  31,  2002.  However,  no
assurances can be given that we will meet this covenant or that the Company will
be able to repurchase the amount of the notes required under the Indenture.

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 ("SFAS  133"),  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.

                                       36
<PAGE>
Impact of Recently Issued Accounting Pronouncements

        During 2001, the Financial  Accounting  Standards  Board issued four new
pronouncements:

        Statement 141,  Business  Combinations  ("SFAS 141"),  requires that the
purchase  method of accounting be used to account for all business  combinations
and applies to all business  combinations  initiated  after June 30,  2001.  The
statement also establishes  specific  criteria for the recognition of intangible
assets  separately  from goodwill.  The  provisions of this  statement  would be
applied were we to enter into any future business combination. The statement has
no impact on PANACO's historical financial statements.

        Statement  142,  Goodwill  and Other  Intangible  Assets  ("SFAS  142"),
requires that goodwill no longer be amortized but tested for impairment at least
annually.  Other  intangible  assets are to be amortized over their useful lives
and reviewed for impairment.  An intangible asset with an indefinite useful life
will not be amortized until its useful life becomes determinable.  The effective
date of this  statement is January 1, 2002.  The  provisions  of this  statement
would be  applied  if we were to  enter  into any  future  business  combination
pursuant to which  goodwill or other  intangible  assets  were  recognized.  The
statement has no impact on PANACO's historical financial statements.

        Statement 143, Accounting for Asset Retirement Obligations ("SFAS 143"),
requires  entities  to  record  the  fair  value  of a  liability  for an  asset
retirement  obligation in the period in which it is incurred and a corresponding
increase in the carrying  amount of the related  long-lived  asset.  The Company
will be required to adopt SFAS 143 effective  January 1, 2003 using a cumulative
effect   approach  to  recognize   transition   amounts  for  asset   retirement
obligations, asset retirement costs and accumulated depreciation.  Currently, we
record estimated costs of dismantlement,  removal, site reclamation, and similar
activities as part of our depreciation,  depletion, and amortization for oil and
gas properties without recording a separate liability for such amounts.  We have
not yet  completed  our  assessment  of the impact of SFAS 143 on our  financial
condition  and results of  operations.  We expect that adoption of the statement
will result in increases in the capitalized  costs of our oil and gas properties
and in the  recognition of additional  liabilities  related to asset  retirement
obligations.

        Statement  144,  Accounting for the Impairment or Disposal of Long-Lived
Assets ("SFAS 144"), retains the fundamental  provisions of SFAS 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of, for recognizing and measuring impairment losses while resolving  significant
implementation  issues associated with SFAS 121. SFAS 144 also expands the basic
provisions  of APB  Opinion  No.  30,  Reporting  the  Results of  Operations  -
Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary,
Unusual  and   Infrequently   Occurring  Events  and   Transactions,   regarding
presentation of discontinued  operations in the income statement.  The scope for
reporting a discontinued operation has been expanded to include a "component" of
an entity. A component  comprises  operations and cash flows that can be clearly
distinguished  from the rest of the entity.  It could be a segment,  a reporting
unit, a consolidated  subsidiary,  or an asset group.  We have not yet completed
our  evaluation  of SFAS 144 and it's  impact  on our  financial  condition  and
results  of  operations.  We  believe  that the  implementation  will be largely
unchanged from SFAS 121.

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 2001,  2000 and 1999 we hedged the following  percentages  of our
oil and natural gas  production.  During 2001 PANACO entered into a swap for 61%
of our natural gas production and an option to put oil to a purchaser at a fixed
price on 30% of our oil  production.  During 2000 we entered into  agreements to
put oil and natural gas to a purchaser at predetermined  prices.  During 1999 we

                                       37
<PAGE>
entered into a combination of options to put produced  volumes to a purchaser at
a predetermined price and swaps based on a single predetermined price or a range
of high and low 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>                <C>
         1999               8.8              540                      79%         46%               ($4.6 million)
         2000               3.7              422                      27%         39%               ($1.1 million)
         2001               6.6              273                      61%         30%                $3.5 million
</TABLE>

        At December  31, 2001 we had $100  million in Senior  Notes  outstanding
with a fixed  interest rate of 10 5/8%.  We also had $32.9  million  outstanding
under our Credit  Facility  at  December  31,  2001.  The Credit  Facility  is a
floating rate facility,  with a fair value of $32.9 million. We did not have any
interest rate hedge agreements at December 31, 2001. On March 28, 2002 we put in
place  two  hedges  for both oil and  natural  gas  produced  from May 1 through
October 31, 2002. The natural gas hedge is a cost-free collar on 3,000 MMbtu and
contains  a minimum  price of $3.00  per MMbtu and a maximum  price of $3.45 per
MMbtu to be received  for the  quantity  hedged.  The oil hedge is a swap on 500
barrels of oil per day with prices  ranging from $24.96 per barrel to $25.87 per
barrel for the  quantity  hedged.  The volumes  hedged  account for 21% and 18%,
respectively,  of PANACO's current estimates of total production for the periods
hedged.

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>
                                                                                 2001
                                               ----------------------------------------------------------------------
                                               1st Quarter        2nd Quarter          3rd Quarter        4th Quarter
                                               -----------        -----------          -----------        -----------
<S>                                            <C>                <C>                  <C>                <C>
Total revenues                                 $    26,316        $    24,024          $    16,685         $   13,188
Operating income (loss)                              8,272             (1,245)              (1,498)           (12,307)
Income (loss) before extraordinary item              3,366             (2,492)             (26,608)           (16,571)
Net income (loss)                              $     3,366        $    (2,492)         $   (26,608)        $  (16,571)
                                               ===========        ===========          ===========         ==========
Net income (loss) per share                    $      0.14        $     (0.10)         $     (1.10)        $    (0.68)
                                               ===========        ===========          ===========         ==========

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

Quarterly Periods Ending December 31, 2001

        During the first quarter of 2001 PANACO drilled an unsuccessful  well at
East Breaks 110,  the primary  factor in $3.9  million of  exploratory  dry hole
expense during the quarter.
                                       38
<PAGE>

        In the second  quarter of 2001,  an  impairment  of oil and  natural gas
properties totaling $6.5 million was recognized. The impairment was due to lower
estimates of future net revenues for our assets,  due primarily to lower oil and
natural gas prices.

        As oil and natural gas prices continued to decrease in the third quarter
of 2001, we were not able to project  sufficient net income to utilize  PANACO's
net  operating  loss   carry-forwards.   As  such,  a  valuation  allowance  was
re-established for our deferred tax assets,  resulting in a net charge to income
tax expense of $23 million.

        During  the  fourth  quarter  of  2001 an  additional  $3.8  million  of
exploratory dry hole expense was recorded based on an  unsuccessful  exploratory
well at  Umbrella  Point.  In  addition,  this well  required an  impairment  to
PANACO's unproved  property.  The impairment for the fourth quarter totaled $2.3
million, the majority of which is related to Umbrella Point.

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.

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, 2001. 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, 2001. 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, 2001. Such information is incorporated herein by reference.

                                       39
<PAGE>
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, 2001. 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.
                None.

         (c)    Exhibits and Financial Statement Schedules.

<TABLE>
<CAPTION>
                Exhibit
                Number             Description
<S>             <C>
                3.1*               Certificate of Incorporation of the Company.

                3.2*               Amendment to Certificate of Incorporation dated November 19, 1991.

                3.3*               By-laws of the Company.

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

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

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

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

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

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

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

                                       40
<PAGE>

                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.

                10.25.3****        Sixth amendment to the Company's credit agreement.

                10.25.4****        Seventh 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.

                *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.
</TABLE>

                                       41
<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,  and/or to find a new reservoir in a field previously found to be
productive of oil or natural gas in known reservoirs.

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.

                                       42
<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 net 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, 2001,  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,
2001, or as otherwise indicated.

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

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

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

                                       43
<PAGE>

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

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

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

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

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

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

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

Sidetrack.  A drilling  operation  involving the use of a portion of an existing
well to drill a second  hole,  in which a  milling  tool is used to grind  out a
"window"  through the side of an existing  casing string at some selected depth.
The drill  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.

                                       44
<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                                   April 15, 2002
                                                                 --------------
      Robert G. Wonish, President and
      Chief Operating Officer

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

      By: \s\ Robert G. Wonish                                   April 15, 2002
                                                                 --------------
      Robert G. Wonish, President and
      Chief Operating Officer and Director

      By: \s\ Todd R. Bart                                       April 15, 2002
                                                                 --------------
      Todd R. Bart
      Chief Financial Officer and
      Principal Accounting Officer

      By: \s\ Harold First                                       April 15, 2002
                                                                 --------------
      Harold First, Director

      By: \s\ A. Theodore Stautberg                              April 15, 2002
                                                                 --------------
      A. Theodore Stautberg, Jr., Director

      By: \s\ James B. Kreamer                                   April 15, 2002
                                                                 --------------
      James B. Kreamer, Director

      By: \s\ Felix A. Pardo                                     April 15, 2002
                                                                 --------------
      Felix A. Pardo, Director

      By: \s\ Stanley Nortman                                    April 15, 2002
                                                                 --------------
      Stanley Nortman, Director

      By: \s\ George W. Hebard III                               April 15, 2002
                                                                 --------------
      George W. Hebard III, Director



                                       45
<PAGE>

                                  PANACO, Inc.
                         INDEX TO FINANCIAL STATEMENTS

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

<S>                                                                      <C>
Independent Auditors' Report                                           F-2

Consolidated Balance Sheets, December 31, 2001 and 2000                F-3

Consolidated Statements of Operations for the Years Ended
     December 31, 2001, 2000 and 1999                                  F-5

Consolidated Statements of Changes in Stockholders' Equity (Deficit)
     for the Years Ended December 31, 2001, 2000 and 1999              F-6

Consolidated Statements of Changes in Comprehensive Income (Loss)
     for the Year Ended December 31, 2001                              F-7

Consolidated Statements of Cash Flows for the Years Ended
     December 31, 2001, 2000 and 1999                                  F-8

Notes to Consolidated Financial Statements for the Years Ended
     December 31, 2001, 2000 and 1999                                  F-9

</TABLE>

                                      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,  2001 and 2000,  and the related  consolidated  statements  of
operations,  changes in stockholders' equity (deficit), changes in comprehensive
income  (loss),  and cash flows for each of the years in the  three-year  period
ended  December  31,  2001.  These  consolidated  financial  statements  are the
responsibility of the Company's management.  Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with 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, 2001 and 2000, and the results of its operations and its cash flows
for each of the years in the  three-year  period ended  December  31,  2001,  in
conformity with accounting principles generally accepted in the United States of
America.

The  accompanying  financial  statements  have been  prepared  assuming that the
Company  will  continue  as a  going  concern.  As  discussed  in  Note 2 to the
financial statements, the Company has suffered recurring losses from operations,
has  a  net  capital  deficiency  and  restrictive  debt  covenants  that  raise
substantial doubt about its ability to continue as a going concern. Management's
plans in regard to these  matters are also  described  in Note 2. The  financial
statements do not include any adjustments  that might result from the outcome of
this uncertainty.



                                                            KPMG LLP
Houston, Texas
April 15, 2002

                                      F-2
<PAGE>
<TABLE>

                                  PANACO, Inc.
                          CONSOLIDATED BALANCE SHEETS



                                     ASSETS
                                     ------

                                                                                          December 31,
                                                                                          ------------
                                                                             2001                            2000
                                                                             ----                            ----
<S>     <C>    <C>    <C>    <C>    <C>    <C>
CURRENT ASSETS
Cash                                                                   $     5,582,000                 $     2,878,000
Accounts receivable, net of an allowance
   of $3,440,000 and $554,000, respectively                                  8,363,000                      17,680,000
Accounts receivable-related party                                                  ---                         300,000
Prepaid and other                                                              917,000                         907,000
                                                                       ---------------                 ---------------
        Total current assets                                                14,862,000                      21,765,000
                                                                       ---------------                 ---------------

OIL AND GAS PROPERTIES, AS DETERMINED
BY THE SUCCESSFUL EFFORTS METHOD
OF ACCOUNTING
    Oil and gas properties, proved                                         286,453,000                     289,892,000
    Less accumulated depreciation, depletion and amortization             (183,867,000)                   (193,135,000)
    Net unproved oil and gas properties                                        232,000                       2,888,000
                                                                       ---------------                 ---------------
        Net oil and gas properties                                         102,818,000                      99,645,000
                                                                       ---------------                 ---------------

PIPELINES AND EQUIPMENT
    Pipelines and equipment                                                 26,532,000                      26,409,000
    Less accumulated depreciation                                          (10,939,000)                     (8,256,000)
                                                                       ---------------                 ---------------
        Net pipelines and equipment                                         15,593,000                      18,153,000
                                                                       ---------------                 ---------------

OTHER ASSETS
    Restricted deposits                                                     11,011,000                       8,625,000
    Deferred financing costs, net                                            1,780,000                       3,128,000
    Deferred income taxes                                                          ---                      22,763,000
                                                                       ---------------                 ---------------
        Total other assets                                                  12,791,000                      34,516,000
                                                                       ---------------                 ---------------

TOTAL ASSETS                                                              $146,064,000                    $174,079,000
                                                                       ===============                 ===============

</TABLE>

                                                                   (Continued)








          See accompanying notes to consolidated financial statements.



                                      F-3
<PAGE>

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


                                                                                             December 31,
<S>                                                                                    <C>                  <C>
                                                                                       2001                 2000
                                                                                       ----                 ----

CURRENT LIABILITIES
    Accounts payable and accrued liabilities                                       $   35,185,000        $   31,963,000
    Interest payable                                                                    2,864,000             2,917,000
    Gas imbalance payable                                                               1,149,000             2,860,000
    Restricted cash payable                                                                25,000               629,000
                                                                                   --------------        --------------
       Total current liabilities                                                       39,223,000            38,369,000
                                                                                   --------------        --------------

DEFERRED CREDITS                                                                        1,505,000             1,609,000

LONG-TERM DEBT                                                                        135,120,000           121,693,000


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;
       24,359,695 and 24,323,521 shares
       issued and outstanding, respectively                                               247,000               246,000
    Additional paid-in capital                                                         69,089,000            68,977,000
    Accumulated deficit                                                               (99,120,000)          (56,815,000)
                                                                                   --------------        --------------
       Total stockholders' equity (deficit)                                           (29,784,000)           12,408,000
                                                                                   --------------        --------------



TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)                                $ 146,064,000         $ 174,079,000
                                                                                    =============         =============
</TABLE>














          See accompanying notes to consolidated financial statements.

                                      F-4
<PAGE>
<TABLE>

                                  PANACO, Inc.
                      CONSOLIDATED STATEMENTS OF OPERATIONS

                                                                        Year Ended December 31,
                                                                     -----------------------------
                                                           2001                  2000                  1999
<S>                                                         <C>                 <C>                      <C>
                                                           ----                  ----                  ----
REVENUES
    Oil and natural gas sales                          $   76,246,000       $   88,550,000        $   42,672,000
    Gain on property sales                                  3,967,000            1,938,000                   ---
    Lawsuit recoveries                                            ---            2,575,000                   ---
                                                       --------------       --------------        --------------
       Total                                               80,213,000           93,063,000            42,672,000

COSTS AND EXPENSES
    Lease operating expense                                24,658,000           20,876,000            17,740,000
    Depreciation, depletion and amortization               34,486,000           27,030,000            26,439,000
    General and administrative expense                      4,047,000            4,878,000             3,930,000
    Bad debt expense                                        3,348,000              344,000               139,000
    Production and ad valorem taxes                         1,997,000            2,089,000             1,202,000
    Exploratory dry hole expense                            8,375,000            4,361,000             1,050,000
    Geological and geophysical expense                        945,000            1,376,000             1,429,000
    Impairment of oil and gas properties                    9,135,000                  ---            13,202,000
    Severance expense                                             ---              746,000                   ---
                                                       --------------       --------------        --------------
       Total                                               86,991,000           61,700,000            65,131,000
                                                       --------------       --------------        --------------

OPERATING INCOME (LOSS)                                    (6,778,000)          31,363,000           (22,459,000)
                                                       --------------       --------------        --------------

OTHER INCOME (EXPENSE)
    Interest income                                           568,000              497,000               255,000
    Interest expense                                      (13,088,000)         (15,388,000)          (12,692,000)
    Other                                                    (273,000)                 ---                   ---
                                                       --------------       --------------        --------------
       Total                                              (12,793,000)         (14,891,000)          (12,437,000)
                                                       --------------       --------------        --------------

INCOME (LOSS) BEFORE INCOME
    TAXES AND EXTRAORDINARY ITEM                          (19,571,000)          16,472,000           (34,896,000)

INCOME TAXES (BENEFIT)                                     22,734,000          (22,683,000)                  ---
                                                       --------------       --------------        --------------

INCOME (LOSS) BEFORE
    EXTRAORDINARY ITEM                                    (42,305,000)          39,155,000            (34,896,000)

EXTRAORDINARY ITEM - Loss on early
    retirement of debt                                            ---                  ---               (131,000)
                                                       --------------       --------------        ---------------
NET INCOME (LOSS)                                       $ (42,305,000)       $  39,155,000        $   (35,027,000)
                                                       ==============       ==============        ===============

BASIC AND DILUTED EARNINGS (LOSS)
   PER SHARE
    Income (loss) before extraordinary item           $         (1.74)       $        1.61        $         (1.45)
    Extraordinary item                                            ---                  ---                   (.01)
                                                      ---------------       --------------        ---------------
    Net income (loss)                                 $         (1.74)      $         1.61        $         (1.46)
                                                      ===============       ==============        ===============

BASIC SHARES OUTSTANDING                                   24,349,784           24,261,830             23,940,785
                                                      ===============       ==============        ===============

DILUTED SHARES OUTSTANDING                                 24,349,784           24,317,942             23,940,785
                                                      ===============       ==============        ===============
</TABLE>

          See accompanying notes to consolidated financial statements.

                                      F-5
<PAGE>

<TABLE>
                                  PANACO, Inc.
      CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (DEFICIT)
              FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999


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

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

  Net loss                                   ---           ---               ---          ---       (42,305,000)   (42,305,000)
  Shares issued under Employee
    Stock Ownership Plan                  36,174         1,000           112,000          ---               ---        113,000
                                      ----------       -------        ----------     --------       -----------    -----------
Balances, December 31, 2001           24,359,695      $247,000       $69,089,000     $    ---      $(99,120,000)  $(29,784,000)
                                      ==========       =======        ==========     ========       ===========    ===========
</TABLE>






















          See accompanying notes to consolidated financial statements.

                                      F-6
<PAGE>
<TABLE>

                                  PANACO, Inc.
       CONSOLIDATED STATEMENTS OF CHANGES IN COMPREHENSIVE INCOME (LOSS)
                      FOR THE YEAR ENDED DECEMBER 31, 2001




<S>                                                     <C> <C>                <C>
Accumulated Other Comprehensive Income (Loss), December 31, 2000               $         --

Net Loss                                                                         (42,305,000)

Accumulated Other Comprehensive Income
  Cumulative effect of change in accounting principle - January 1, 2001           (9,881,000)
  Changes in fair value of outstanding hedging positions                          13,417,000
  Financial derivative settlements transferred from
    Accumulated Other Comprehensive Income                                        (3,536,000)
                                                                               -------------

Accumulated Other Comprehensive Income                                                    --
                                                                               -------------

Comprehensive Income (Loss)                                                    $ (42,305,000)
                                                                               =============

There were no other items in Comprehensive Income (Loss) during 2001.

</TABLE>

                                      F-7
<PAGE>

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

                                                                             Year Ended December 31,
                                                                             -----------------------
<S>                                                                <C>                <C>                <C>
                                                                   2001               2000               1999
                                                                   ----               ----               ----
CASH FLOWS FROM OPERATING ACTIVITIES
   Net income (loss)                                          $ (42,305,000)       $ 39,155,000      $ (35,027,000)
   Adjustments to reconcile net income (loss)
       to net cash provided by operating activities:
     Extraordinary item                                                 ---                 ---            131,000
     Depreciation, depletion and amortization                    34,486,000          27,030,000         26,439,000
     Impairment of oil and gas properties                         9,135,000                 ---         13,202,000
     Exploratory dry hole expense                                 8,375,000           4,361,000          1,050,000
     Deferred income tax benefit                                 22,763,000         (22,763,000)               ---
     ESOP stock contribution expense                                113,000             128,000            250,000
     Gain on property sales                                      (3,967,000)         (1,938,000)               ---
     Plug and abandoning of wells and platforms                  (6,930,000)                ---                ---
     Changes in operating assets and liabilities:
         Accounts receivable                                      9,285,000          (8,005,000)        (1,343,000)
         Related party note receivable                              300,000              16,000              2,000
         Prepaid and other                                         (501,000)           (177,000)          (347,000)
         Accounts payable                                         3,947,000          11,555,000          3,682,000
         Deferred credits                                          (104,000)          1,609,000                ---
         Gas imbalance payable                                     (348,000)          2,860,000                ---
         Interest payable                                           (53,000)            (86,000)           258,000
                                                               ------------        ------------      -------------
     Net cash provided by operating activities                   34,196,000          53,745,000          8,297,000
                                                               ------------        ------------      -------------

CASH FLOWS FROM INVESTING ACTIVITIES
   Proceeds from the sale of oil and gas properties               2,843,000             783,000          1,036,000
   Capital expenditures and acquisitions                        (45,012,000)        (37,192,000)       (26,429,000)
   Increase in restricted deposits                               (2,386,000)         (2,395,000)        (1,883,000)
                                                               ------------        ------------       ------------
     Net cash used in investing activities                      (44,555,000)        (38,804,000)       (27,276,000)
                                                               ------------        ------------       ------------

CASH FLOWS FROM FINANCING ACTIVITIES
   Long-term debt proceeds                                       24,768,000          22,791,000         47,153,000
   Repayment of long-term debt                                  (11,341,000)        (40,000,000)       (24,000,000)
   Deferred financing costs                                        (364,000)           (429,000)        (2,051,000)
                                                               ------------        ------------       ------------
     Net cash provided by (used in) financing activities         13,063,000         (17,638,000)        21,102,000
                                                               ------------        ------------       ------------

NET INCREASE (DECREASE) IN CASH                                $  2,704,000        $ (2,697,000)      $  2,123,000

CASH AT BEGINNING OF YEAR                                         2,878,000           5,575,000          3,452,000
                                                               ------------        ------------       ------------

CASH AT END OF YEAR                                            $  5,582,000        $  2,878,000       $  5,575,000
                                                               ============        ============       ============
</TABLE>




          See accompanying notes to consolidated financial statements.

                                      F-8
<PAGE>

     SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:

For the year ended December 31, 2001:
-------------------------------------

The Company  issued 36,174  common  shares  valued at $113,000 to the ESOP.  The
change in accounts  payable from December 31, 2000 to December 31, 2001 excludes
this non-cash reduction of the liability.

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.


SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

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

                                                                   2001             2000              1999
<S>                                                                   <C>            <C>              <C>
                                                                   ----             ----              ----

Interest (gross interest paid)                                $  13,257,000     $  15,682,000    $  12,978,000
                                                              =============     =============    =============

Income taxes                                                  $         ---     $     145,000    $         ---
                                                              =============     =============    =============

</TABLE>

                                      F-9
<PAGE>



                                  PANACO, Inc.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

              FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 and 1999


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, 2001 the Company's
imbalance  position  was an  over-produced,  or payable  balance of 265,000  Mcf
valued at $1.1 million.  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.

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
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. On December 31, 2001 the Company did not have any hedge
agreements in place.

                                      F-10
<PAGE>
Gains  and  losses  on  hedging   instruments   related  to  Accumulated   Other
Comprehensive   Income/Loss  and  adjustments  to  carrying  amounts  on  hedged
production are included in natural gas or crude oil  production  revenues in the
period that the related  production  is  delivered.  Gains and losses of hedging
instruments, which represent hedge ineffectiveness and changes in the time value
component of options,  are included in Other  Income/Loss in the period in which
they occur.

For the Company's  natural gas swap, on January 1, 2001, in accordance  with the
transition  provisions of SFAS 133, the Company  recorded a loss of $9.9 million
in Other  Comprehensive  Income/Loss  representing  the cumulative  effect of an
accounting  change to  recognize  the fair value of the  natural  gas swap.  The
Company also recorded cash flow hedge derivative  liabilities of $9.9 million in
accounts payable and accrued liabilities.

All hedge  transactions are subject to the Company's risk management  policy and
are  approved  by the Board of  Directors,  which  does not  permit  speculative
positions.  The Company  formally  documents all  relationships  between hedging
instruments  and hedged items,  as well as its risk  management  objectives  and
strategy   for   undertaking   the  hedge.   This  process   includes   specific
identification of the hedging instrument and the hedge  transaction,  the nature
of the risk being hedged and how the hedging instrument's  effectiveness will be
assessed.  Both at the  inception  of the hedge  and on an  ongoing  basis,  the
Company assesses  whether the derivatives that are used in hedging  transactions
are highly effective in offsetting changes in cash flows of hedged items.

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  carry-forwards.  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 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.

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.

                                      F-11
<PAGE>
During 2001 the Company recorded asset  impairments  totaling $9.1 million.  The
unsuccessful  development  of  potential  reserves in the  Umbrella  Point Field
accounted  for $1.9  million  of the  impairment  in 2001.  The  balance  of the
impairment was primarily due to lower  estimates of future net revenues from the
Company's  proved reserves caused mainly by lower prices for oil and natural gas
along with reserve  revisions.  The Company also recorded an asset impairment in
1999 of $13.2 million for unproved  properties  that the Company did not develop
and for lowered  reserve  estimates in the High Island 309 Fields.  During 2001,
the  Company  sold the High  Island  309 Fields  and  recognized  a gain of $4.0
million on the sale. The Company also recognized a net gain of $1.9 million from
the sale of three properties in 2000.

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
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 2001, 2000 and 1999 was $116,000, $208,000,
and $544,000, 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.  During all
or part of the periods presented,  the Company had options outstanding that were
exercisable  at  prices  above  the  market  and are not  included  in per share
calculations. In addition, due to losses incurred in 1999 and 2001, common stock
equivalents   would  be  anti-dilutive   and  are  not  included  in  per  share
calculations.

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

                                      F-12
<PAGE>
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
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.

Note 2 - WORKING CAPITAL DEFICIT AND RESTRICTIVE COVENANTS
         -------------------------------------------------

Due to substantial  losses  incurred in 1999 and 2001 and less than  anticipated
results  from  PANACO's  drilling  program  in late  2000 and most of 2001,  the
Company  accumulated a significant  working  capital  deficit as of December 31,
2001.  The deficit  totaled $24.4 million.  The lack of  performance  from wells
drilled  during 2000 and 2001,  along with  decreased  commodity  prices in late
2001,  reduced  estimated  future  net cash  flows  and  availability  under the
Company's  Credit Facility to a point at which there is substantial  doubt about
the Company's ability to reduce this deficit in a timely manner.

Given this  situation,  PANACO engaged an investment  bank in early 2002 to help
the  Company  explore  strategic  financial  alternatives.  The  outcome of this
process  may result in asset  sales or the sale of the  Company as a whole.  The
Company is also in  discussions  to increase the amount of its Credit  Facility,
which may require a waiver from the holders of the Senior  Notes.  No assurances
can be made  that the  Company  will be able to  implement  any plan  that  will
resolve  the working  capital  deficit or that a plan will be  implemented  in a
timely manner. In addition, some of these alternatives may require approval from
PANACO's Credit  Facility  lenders or the approval of our Senior Note holders as
well as Shareholder approval.

        In March 2002, the Credit  Facility,  with  borrowings of $32.9 million,
was  amended  in order to cure  covenants  that we were not able to  satisfy  on
December 31, 2001.  This amendment  requires a working capital ratio (as defined
in the  agreement) of 0.15 to 1.0 from January 1 to April 30, 2002,  0.20 to 1.0
from May 1 to January 1, 2003,  and 0.25 to 1.0  thereafter.  The amendment also
requires a trailing twelve-month  EBITDA/interest  coverage ratio ranging from a
monthly high of 2.0 to 1.0 to a monthly low of 0.55 to 1.0 for 2002,  and 2.0 to
1.0  thereafter.  Based  on  current  projections,  we  believe  we  will  be in
compliance  with all of the terms of the Credit  Facility  through  December 31,
2002.  However, no assurances can be given that we will be in compliance through
December 31,  2002.  PANACO's  $100 million  of  Senior  Notes  require  that we
maintain a total  Adjusted  Consolidated  Net Tangible  Asset  Value  ("ACNTA"),
as defined in the  Indenture,  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. At December 31, 2001 PANACO did not meet this ratio. Actual
results  through  December  31, 2002 are not yet  available,  however,  based on
increased  market  prices for oil and natural gas, we estimate  that the Company
will be in  compliance  with  the  covenant  at  March  31,  2002.  However,  no
assurances can be given that we will meet this covenant or that the Company will
be able to repurchase the amount of the notes required under the Indenture.

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
$195,000, $330,000, and $337,000 in costs for the years ended December 31, 2001,
2000 and 1999, respectively.

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.

                                      F-13
<PAGE>
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 $5.6  million at December  31,
2001 and  requires  quarterly  deposits  of $375,000  until the account  balance
reaches $7.8 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
$4.7 million at December 31, 2001 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, 2001.

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>

                                                             2001                        2000
                                                             ----                        ----
<S>  <C>                                               <C>                          <C>
10 5/8 % Senior Notes due 2004(a)                      $    100,000,000             $   100,000,000
Revolving credit facility due 2003(b)                        32,871,000                  19,444,000
Production payment(c)                                         2,249,000                   2,249,000
                                                       ----------------             ---------------
                                                            135,120,000                 121,693,000

Less current portion                                                ---                         ---
                                                       ----------------             ---------------
    Long-term debt                                     $    135,120,000             $   121,693,000
                                                       ================             ===============
</TABLE>

(a)  In October 1997 the Company issued $100 million of 10.625% Senior Notes due
     2004. Interest is payable semi-annually April 1 and October 1 of each year.
     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  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.  The Company  must  maintain a total  Adjusted  Consolidated  Net
     Tangible Asset Value ("ACNTA"), as defined in the Indenture,  equal to 125%
     of  indebtedness  at the end of each  quarter.  At  December  31,  2001 the
     Company did not meet this ratio.  Should this  condition  continue to exist
     for two  successive  quarters,  the Company is required to make an offer to


                                      F-14
<PAGE>


     the Senior Note holders to  repurchase  an amount of the notes (at par plus
     accrued  interest)  sufficient to meet the ratio required in the indenture.
     Based on  increased  market  prices for oil and  natural  gas,  the Company
     estimates  that it will be in  compliance  with this  covenant at March 31,
     2002 and will not be  required  to make such an offer to the holders of the
     Senior Notes.  However,  no  assurances  can be given that the Company will
     meet this covenant or that PANACO will be able to repurchase  the amount of
     the notes required under the Indenture. As a result, the Company may not be
     able to continue  as  a  going concern. See Note 2.

(b)  In November 2001, the Company amended a Credit Facility  originally entered
     into in October 1999.  The facility is for two years and provides up to $40
     million,  depending on the borrowing base as calculated in accordance  with
     the  agreement.  The  borrowing  base is  calculated as a percentage of the
     future net cash flows from its oil and natural gas reserves,  discounted at
     10%  annually.  The Company's  borrowing  base at December 31, 2001 was $40
     million,  with  availability  of $6.1  million,  of which $1.3  million was
     reserved for a letter of credit.  Interest on the loan is computed at Wells
     Fargo's  prime rate plus  0.25% to 0.75%,  or at LIBOR plus 2.25% to 2.75%,
     with the percentage  increases  depending on the percentage of the facility
     being used, and in any event, a minimum  interest rate of 6.75%. The Credit
     Facility is collateralized by a first mortgage on the Company's properties.
     In March 2002,  the Credit  Facility was amended in order to cure covenants
     that the  Company  was not able to  satisfy  on  December  31,  2001.  This
     amendment requires a working capital ratio (as defined in the agreement) of
     0.15 to 1.0 from  January  1 to April 30,  2002,  0.20 to 1.0 from May 1 to
     January 1, 2003, and 0.25 to 1.0 thereafter.  The amendment also requires a
     trailing twelve-month EBITDA/interest coverage ratio ranging from a monthly
     high of 2.0 to 1.0 to a monthly low of 0.55 to 1.0 for 2002, and 2.0 to 1.0
     thereafter.  In addition,  the amendment  eliminates  the  requirement  for
     hedges  until March 31,  2002.  Based on current  projections,  the Company
     believes it will be in  compliance  with all of the terms of the  agreement
     through  December 31, 2002.  However, no assurances can be given that the
     Company  will be  in compliance  through  December  31, 2002.  As a result,
     PANACO may not be able  to continue  as a  going concern. See  Note 2.  The
     agreement also contains limitations on dividends, mergers  and asset sales.

(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
various insurance  policies.  The employee was paid a portion of this amount due
in October 2000 and the remaining amount due the employee was offset against the
principal  amount of the promissory note in January 2001.  Effective  October 1,
2000,  the  Company's  Chief  Operating  Officer  took over as  President of the
Company.

Note 9 - ADOPTION OF SFAS 133
         --------------------

On January 1, 2001,  the Company  adopted SFAS 133  "Accounting  for  Derivative
Instruments  and Hedging  Activities" as amended by SFAS 137 and SFAS 138. Under


                                      F-15
<PAGE>
SFAS 133, all derivative  instruments  are recorded on the balance sheet at fair
value.  If the derivative  does not qualify as a hedge or is not designated as a
hedge,  the gain or loss on the derivative is recognized  currently in earnings.
To qualify for hedge  accounting,  the derivative  must qualify either as a fair
value hedge, cash flow hedge or foreign currency hedge.  Currently,  the Company
uses only cash flow hedges and the remaining  discussion will relate exclusively
to this type of derivative  instrument.  If the  derivative  qualifies for hedge
accounting,  the gain or loss on the derivative is deferred in Accumulated Other
Comprehensive Income/Loss, a component of Stockholders' Equity (Deficit), to the
extent the hedge is effective.

The  relationship  between  the hedging  instrument  and the hedged item must be
highly  effective in achieving the offset of changes in cash flows  attributable
to the  hedged  risk both at the  inception  of the  contract  and on an ongoing
basis. The Company measures effectiveness on a quarterly basis. Hedge accounting
is discontinued prospectively when a hedge instrument becomes ineffective. Gains
and losses deferred in Accumulated Other  Comprehensive  Income/Loss  related to
cash flow hedges  that become  ineffective  remain  unchanged  until the related
production is delivered.  If the Company  determines  that it is probable that a
hedged  forecasted  transaction will not occur,  deferred gains or losses on the
hedging instrument are recognized in earnings immediately.

The Company periodically enters into derivative  commodity  instruments to hedge
its exposure to price  fluctuation on natural gas and crude oil production.  For
2001, the Company  entered into an option to put 1,000 barrels of oil per day at
$25.00 per  barrel to a  purchaser  through  September  30,  2001 for a total of
273,000 barrels. In addition,  the Company entered into a natural gas price swap
covering  6.6 Bcf of  production  for the  entire  twelve  months  of 2001 at an
average price of $4.91 per MMbtu. On December 31, 2001, the Company did not have
any hedge agreements in place.

The  Company  has  historically  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, cost free collars, or put options.  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.  Put options  insured a minimum
price to be received for the Company's  oil. The following is a summary of those
years' hedging activities.
<TABLE>

<S>     <C>    <C>    <C>    <C>    <C>    <C>
                       Volume Hedged             Percentage of Actual   Production      Realized
Year        Natural Gas (Bcf)     Oil (MBbl)         Natural Gas           Oil          Gain/(Loss)
----        -----------------     ----------         -----------           ---          -----------
2001               6.6               273                61%                30%          $3.5 million
2000               3.7               422                27%                39%         ($1.1 million)
1999               8.8               540                79%                46%         ($4.6 million)
</TABLE>

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.



                                      F-16
<PAGE>
During  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>

                                           2001                      2000                     1999
                                  ------------------------  -----------------------  -----------------------
                                                  Wtd.                     Wtd.                     Wtd.
                                                  Avg.                     Avg.                     Avg.
                                   Shares       Ex. Price    Shares      Ex. Price    Shares      Ex. Price
                                   ------       ---------    ------      ---------    ------      ---------
<S>                                <C>           <C>        <C>           <C>       <C>            <C>
Outstanding at beginning of year   500,000       $ 1.92     1,150,000     $ 4.45    1,150,000      $ 4.45
Granted                                ---          ---       500,000       1.92          ---         ---
Exercised                              ---          ---           ---       ---           ---         ---
Forfeited                          (75,000)        1.92    (1,150,000)      4.45          ---        4.45
                                   -------        -----     ---------      -----    ---------       -----
Outstanding at end of year         425,000         1.92       500,000       1.92    1,150,000        4.45
Exercisable at end of year          85,000       $ 1.92           ---     $ 1.92    1,150,000      $ 4.45
Fair value of options granted          N/A                      $1.71                     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:

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

If  compensation  expense for the Company's stock option plans had been recorded
using the Black-Scholes  fair value method and the assumptions  described above,
the  Company's  unaudited  net income  (loss) and earnings  (loss) per share for
2001, 2000 and 1999 would have been as shown below:
<TABLE>

                                                   (Unaudited)        (Unaudited)         (Unaudited)
                                                       2001               2000                1999
                                                  -------------       ------------       -------------
<S>                                               <C>                <C>                 <C>
Net income (loss)             As reported         $(42,305,000)      $ 39,155,000        $(35,027,000)
-----------------
                              Pro forma           $(42,450,000)      $ 39,027,000        $(35,311,000)

Net income (loss) per share:  As reported, basic
----------------------------
                              and diluted:        $      (1.74)      $       1.61        $      (1.46)

                              Pro forma:
                              Basic               $      (1.74)      $       1.61        $      (1.47)
                              Diluted             $      (1.74)      $       1.60        $      (1.47)
</TABLE>

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

During 2001, Plains Resources,  the purchaser of a majority of the Company's oil
production,  accounted  for 18% of  total  oil and  natural  gas  sales  and the
purchaser of a majority of the  Company's  natural gas  production,  Enron North
America,  accounted for 51% of total oil and natural gas sales. In 2000,  Plains
Resources  accounted  for 23% of total oil and  natural  gas sales,  while Enron
North America accounted for 39% of total oil and natural gas sales. During 1999,
the Company's largest oil and natural gas purchasers  accounted for 37% and 39%,
respectively, of total oil and natural gas sales.

During 2001 the Company  wrote off a receivable  from Enron North  America,  the
natural gas purchaser that accounted for 51% of total oil and natural gas sales.


                                      F-17
<PAGE>

The amount  written off included  $1.8 million for natural gas sold to Enron and
$1.2 million for the final payment due under a natural gas swap agreement. Since
December 2001 the Company has replaced Enron as a natural gas purchaser.

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

At December  31, 2001,  the Company had net  operating  loss carry  forwards for
federal income tax purposes of approximately $108 million which are available to
offset future federal  taxable income through 2021. 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>

                                                                      2001                      2000
                                                              ------------------        ------------------
<S>     <C>    <C>    <C>    <C>    <C>    <C>
Deferred tax assets (liabilities)
    Fixed asset basis differences                             $      (12,474,000)       $      (14,733,000)
    Net operating loss carry forwards                                 37,675,000                35,130,000
    State Taxes                                                        2,566,000                 2,001,000
    Other                                                              2,298,000                   365,000
                                                              ------------------        ------------------
    Net deferred tax assets                                           30,065,000                22,763,000
                                                              ------------------        ------------------
Valuation allowance for deferred tax assets                          (30,065,000)                      ---
                                                              ------------------        ------------------
        Total net deferred tax assets (liabilities)           $              ---        $       22,763,000
                                                              ==================        ==================
</TABLE>

At December 31, 2001 the Company determined that it is more likely than not that
the  deferred  tax  assets  will not be  realized,  consequently  the  valuation
allowance  was  increased by $30 million.  This  determination  was based on the
Company's  estimates of future net income,  which were not sufficient to utilize
the net operating loss carry-forwards.

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>

                                                             2001                  2000                1999
                                                            ------                ------              ------
<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                      154                   (176)               38
     Effective rate                                          116%                  (138%)              0%
</TABLE>

Note 13 - COMMITMENTS AND CONTINGENCIES
          -----------------------------

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

The Company has commitments  under an operating lease agreement for office space
through  November 30, 2004.  At December 31,  2001,  the future  minimum  rental
payments due under the lease are as follows:

<TABLE>
<S>                      <C>                      <C>
                         2002                     $      459,000
                         2003                            459,000
                         2004                            421,000
                                                  --------------
                         Total                    $    1,339,000
                                                  ==============
</TABLE>
                                      F-18
<PAGE>
Note 14 - 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>

                                                    2001                     2000                     1999
                                              ---------------          ---------------          ----------------
<S>                                            <C>                      <C>                      <C>
Property acquisition costs, proved             $   3,873,000            $  3,395,000             $         ---

Property acquisition costs, unproved                 349,000                 208,000                   544,000

Exploration expenses                               9,320,000               5,737,000                 2,479,000

Development costs                                 32,292,000              28,613,000                24,777,000
</TABLE>

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

The estimates of proved reserve  quantities at December 31, 2001, 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>
Proved developed and undeveloped reserves:                     Oil                   Gas
                                                              (BBLS)                (MCF)
                                                              ------                -----
<S>                               <C> <C>                     <C>                  <C>
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
   Production                                                  (923,000)          (10,703,000)
    Extensions and discoveries                                  354,000             7,705,000
    Sale of minerals in-place                                    (3,000)           (2,191,000)
    Purchase of minerals in-place                             1,134,000               289,000
    Revisions of previous estimates                            (846,000)          (10,382,000)
                                                           ------------          ------------
Estimated reserves as of December 31, 2001                    7,853,000            66,940,000
                                                           ============          ============
</TABLE>
                                      F-19
<PAGE>
<TABLE>

Proved developed reserves:                      Oil                   Gas
                                               (BBLS)                (MCF)
                                               ------                -----
<S>          <C> <C>                          <C>                  <C>
    December 31, 1999                         5,351,000            40,627,000
                                            ===========            ==========

    December 31, 2000                        4,460,000             49,945,000
                                            ===========            ==========

    December 31, 2001                        4,247,000             33,607,000
                                            ===========            ==========
</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
the quality of the oil and natural gas and for transportation to the appropriate
location.  The average net prices in the Pretax PV-10 value at December 31, 2001
were $2.69 per Mcf of natural  gas and  $18.56 per barrel of oil.  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>
                                                             2001                 2000                1999
                                                      -----------------------------------------------------------
<S>                                                   <C>                 <C>                  <C>
Future cash inflows                                   $    326,718,000    $   1,017,214,000    $     420,060,000
Future costs:
  Production                                              (117,225,000)        (167,180,000)         (98,972,000)
  Development                                              (76,232,000)         (88,604,000)         (68,659,000)
                                                      -----------------   -------------------  ------------------
    Future production and development costs               (193,457,000)        (255,784,000)        (167,631,000)
                                                      -----------------   -------------------  ------------------

  Net cash flows-before tax                                133,261,000          761,430,000          252,429,000
Future income tax expenses                                         ---         (204,875,000)                 ---
                                                      -----------------   -------------------  ------------------
Future net cash flows                                      133,261,000          556,555,000          252,429,000
10% annual discount for estimated
  timing of cash flows                                     (44,018,000)        (148,540,000)         (71,163,000)
                                                      -----------------   -------------------  ------------------
Standardized measure of discounted
  Net cash flows                                      $     89,243,000    $     408,015,000    $     181,266,000
                                                      =================   ===================  ==================
</TABLE>

                                      F-20
<PAGE>


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

                                                         2001                  2000                  1999
                                                   -----------------     -----------------     -----------------
<S>                                                 <C>                   <C>                   <C>
Beginning balance                                   $ 408,015,000         $ 181,266,000         $  94,580,000
Sales, net of production costs                        (49,591,000)          (65,301,000)          (23,632,000)
Increase due to passage of time
     (accretion of discount)                           53,291,000            18,127,000             9,454,000
Purchase of minerals in place                           8,199,000            10,785,000                   ---
Sales of minerals in place                             (2,595,000)             (345,000)           (1,037,000)
Net change in sales prices, net of
     production costs                                (413,885,000)          327,247,000            77,935,000
Revisions of quantity estimates                       (19,647,000)          (16,026,000)           24,111,000
Extensions and discoveries, net of future
     production and development costs                  15,091,000           109,442,000            17,864,000
Net changes in income taxes                           124,892,000          (124,892,000)                  ---
Changes in future development costs                     1,006,000            (9,987,000)           (7,789,000)
Changes of production rates (timing)
     and other                                        (35,533,000)          (22,302,000)          (10,179,000)
                                                   --------------        --------------         -------------
Net increase (decrease)                              (318,772,000)          226,748,000            86,727,000
                                                   --------------        --------------         -------------
Ending balance                                      $  89,243,000         $ 408,014,000         $ 181,307,000
                                                   ==============        ==============         =============
</TABLE>


                                      F-21
<PAGE>
                                 EXHIBIT 10.25.3
                     SIXTH AMENDMENT TO AMENDED AND RESTATED
                           LOAN AND SECURITY AGREEMENT
                           ---------------------------


         THIS SIXTH AMENDMENT TO AMENDED AND RESTATED LOAN AND SECURITY
AGREEMENT (this "Amendment") is made and entered into as of November ____, 2001,
by and among: PANACO, INC., a Delaware corporation ("Borrower") which is the
sole surviving corporation of the merger by Panaco Production Company, a Texas
corporation ("PPC") and Goldking Acquisition Corporation, a Delaware corporation
("GAC"), with and into Borrower and is the successor-by-merger to PPC and GAC
thereunder; the financial institutions listed on the signature pages hereof
(such financial institutions, together with their respective successors and
assigns, are referred to hereinafter each individually as a "Lender" and
collectively as the "Lenders"); and FOOTHILL CAPITAL CORPORATION, a California
corporation, as agent for the Lenders ("Agent").

                                    RECITALS
                                    --------

         A. Borrower, PPC (prior to its merger with and into Borrower), Agent
and Lenders have entered into that certain Amended and Restated Loan and
Security Agreement, dated as of September 30, 1999, as amended by that certain
First Amendment to Amended and Restated Loan and Security Agreement, dated
November 30, 1999, as amended by that certain Second Amendment to Amended and
Restated Loan and Security Agreement, dated September 29, 2000, as amended by
that certain Third Amendment to Amended and Restated Loan and Security
Agreement, dated December 21, 2000, as amended by that certain Fourth Amendment
to Amended and Restated Loan and Security Agreement, dated September 30, 2001,
and as amended by that certain Fifth Amendment to Amended and Restated Loan and
Security Agreement, dated October 29, 2001 (as so amended, the "Loan
Agreement").

         B.       Capitalized  terms used in this  Amendment  are used as
defined in the Loan  Agreement,  as amended  hereby,  unless otherwise stated.

         C.       Borrower,  Agent and Lenders desire that: (i) the Commitments
be increased from $30,000,000 to $40,000,000;  and (ii)other modifications be
made to the Loan Agreement as set forth in this Amendment.

         D.       Borrower, Agent and Lenders desire to amend the Loan Agreement
 as hereinafter set forth.

         NOW, THEREFORE, in consideration of the premises herein contained and
other good and valuable consideration, the receipt and sufficiency of which are
hereby acknowledged, the parties, intending to be legally bound, agree as
follows:

                                    AGREEMENT
                                    ---------

                                 EXHIBIT 10.25.4
                                    ARTICLE I
                          Amendments to Loan Agreement
                          ----------------------------

         1.01 Amendment to Section 1.1 of the Loan Agreement. Effective as of
              ----------------------------------------------
the date hereof, Section 1.1 of the Loan Agreement is hereby amended by (a)
substituting the definitions below of "Business Day," "Default Margin," and
"Maximum Revolving Amount" in lieu of the definitions thereof set forth in
Section 1.1 of the Loan Agreement, (b) adding the definitions below of "Average
Outstandings," "Base LIBOR Rate," "Capital Expenditures," "Capitalized Lease

                                       1
<PAGE>
Obligation," "Funding Losses," "Interest Period," "LIBOR Deadline," "LIBOR
Notice," "LIBOR Option," "LIBOR Rate," "LIBOR Rate Loan," "LIBOR Rate Margin,"
"Reference Rate Loan," "Reference Rate Margin," and "Reserve Percentage" to
Section 1.1 of the Loan Agreement and (c) deleting the definition of "Margin"
set forth in Section 1.1 of the Loan Agreement:

              " `Average Outstandings' means, as of the last day of each
                 --------------------
         month, the sum of (i) the amount of the average Daily Balance of
         Advances (including Agent Advances and Foothill Loans) that were
         outstanding (including any amounts that the Lender Group may have paid
         for the account of Borrower pursuant to any of the Loan Documents and
         that have not been reimbursed by Borrower) during such month (the
         "Averaging Period"), plus (ii) the average Daily Balance of the Letter
         of Credit/Hedging Arrangement Usage during such month; provided,
         however, that with respect to any determinations of the Average
         Outstandings during the period beginning on the Closing Date and ending
         on the last day of the month in which the Closing Date occurs, the
         Averaging Period used for such purpose shall instead be the period
         beginning with the Closing Date and ending on the last day of such
         month.

              `Base LIBOR Rate' means the rate per annum, determined by
               ---------------
         Agent in accordance with its customary procedures, and utilizing such
         electronic or other quotation sources as it considers appropriate
         (rounded upwards, if necessary, to the next 1/16%), on the basis of the
         rates at which Dollar deposits are offered to major banks in the London
         interbank market on or about 11:00 a.m. (California time) 2 Business
         Days prior to the commencement of the applicable Interest Period, for a
         term and in amounts comparable to the Interest Period and amount of the
         LIBOR Rate Loan requested by Borrower in accordance with this
         Agreement, which determination shall be conclusive in the absence of
         manifest error.

              `Business Day' means any day that is not a Saturday, Sunday,
               ------------
         or other day on which national banks are authorized or required to
         close, except that, if a determination of a Business Day shall relate
         to LIBOR Rate Loan, the term `Business Day' also shall exclude any day
         on which banks are closed for dealings in Dollar deposits in the London
         interbank market.

              `Capital Expenditures' means expenditures made or liabilities
               --------------------
         incurred for the acquisition of any fixed assets or improvements,
         replacements, substitutions or additions thereto, which have a useful
         life of more than one year, including the total principal portion of
         Capitalized Lease Obligations.

              `Capitalized Lease Obligation' means any Indebtedness
               ----------------------------
         represented by obligations under a lease that is required to be
         capitalized for financial reporting purposes in accordance with GAAP.

              `Default Margin' means, as of any date of determination, four
               --------------
         (4) percentage points above the then applicable Reference Rate Margin,
         as the case may be and as the applicable Reference Rate Margin may
         change from time to time.

              `Funding Losses' has the meaning set forth in Section 2.14(b)(ii).
               --------------

              `Interest Period' means, with respect to each LIBOR Rate Loan,
               ---------------
         a period commencing on the date of the making of such LIBOR Rate Loan


                                       2
<PAGE>

         and ending 1, 2, or 3 months thereafter; provided, however, that (a) if
         any Interest Period would end on a day that is not a Business Day, such
         Interest Period shall be extended (subject to clauses (c)-(e) below) to
         the next succeeding Business Day, (b) interest shall accrue at the
         applicable rate based upon the LIBOR Rate from and including the first
         day of each Interest Period to, but excluding, the day on which any
         Interest Period expires, (c) any Interest Period that would end on a
         day that is not a Business Day shall be extended to the next succeeding
         Business Day unless such Business Day falls in another calendar month,
         in which case such Interest Period shall end on the next preceding
         Business Day, (d) with respect to an Interest Period that begins on the
         last Business Day of a calendar month (or on a day for which there is
         no numerically corresponding day in the calendar month at the end of
         such Interest Period), the Interest Period shall end on the last
         Business Day of the calendar month that is 1, 2, or 3 months after the
         date on which the Interest Period began, as applicable, and (e)
         Borrower may not elect an Interest Period which will end after the
         Maturity Date.

              `LIBOR Deadline' has the meaning set forth in Section 2.14(b)(i).
               --------------                                       ----------

              `LIBOR Notice' means a written notice in the form of Exhibit L-1.
               ------------                                        -----------

              `LIBOR Option' has the meaning set forth in Section 2.14(a).
               ------------                               --------------

              `LIBOR Rate' means, for each Interest Period for each LIBOR
               ----------
         Rate Loan, the rate per annum determined by Agent (rounded upwards, if
         necessary, to the next 1/16%) by dividing (a) the Base LIBOR Rate for
         such Interest Period, by (b) 100% minus the Reserve Percentage. The
         LIBOR Rate shall be adjusted on and as of the effective day of any
         change in the Reserve Percentage.

                  `LIBOR Rate Loan' means each portion of an Advance owed by
                   ---------------
         Borrower that bears interest at a rate determined by reference to the
         LIBOR Rate.

                  `LIBOR Rate Margin' means, as of any date of determination
                   -----------------
         during any month with respect to any and all LIBOR Rate Loans, which
         are outstanding during such month, the rate of interest per annum
         specified below as the `Applicable LIBOR Rate Margin' which corresponds
         to the Average Outstandings set forth below as of such date:

<TABLE>
<CAPTION>
                ------------------------------------ -----------------------------
                       Average Outstandings            Applicable LIBOR Rate Margin
                ------------------------------------ -----------------------------
<S>                          <C>                                  <C>
                         <$20,000,000                            2.25%
                ------------------------------------ -----------------------------
                ------------------------------------ -----------------------------
                         = or >$20,000,000                       2.50%
                         and <$30,000,000
                ------------------------------------ -----------------------------
                ------------------------------------ -----------------------------
                         = or >$30,000,000                       2.75%
                ------------------------------------ -----------------------------
</TABLE>

                  `Maximum Revolving Amount' means $40,000,000.
                   ------------------------

                  `Reference Rate Loan' means each portion of an Advance or
                   -------------------
         other Obligations owed by Borrower that bears interest at a rate
         determined by reference to the Reference Rate.

                                       3
<PAGE>

                  `Reference Rate Margin' means, as of any date of determination
                   ---------------------
         during any month with respect to any and all Reference Rate Loans,
         which are outstanding during such month, the rate of interest per annum
         specified below as the `Applicable Reference Rate Margin' which
         corresponds to the Average Outstandings set forth below as of such
         date:

<TABLE>
<CAPTION>
          -------------------------------- -----------------------------
                Average Outstandings           Applicable Reference
                                                   Rate Margin
          -------------------------------- -----------------------------
          -------------------------------- -----------------------------
<S>                      <C>                            <C>
                      <$20,000,000                      0.25%
          -------------------------------- -----------------------------
          -------------------------------- -----------------------------
                      = or >$20,000,000                 0.50%
                      and <$30,000,000
          -------------------------------- -----------------------------
          -------------------------------- -----------------------------
                      = or >$30,000,000                 0.75%
          -------------------------------- -----------------------------
</TABLE>

                  `Reserve Percentage' means, on any day, for any Lender, the
                   ------------------
         maximum percentage prescribed by the Board of Governors of the Federal
         Reserve System (or any successor Governmental Authority) for
         determining the reserve requirements (including any basic,
         supplemental, marginal, or emergency reserves) that are in effect on
         such date with respect to eurocurrency funding (currently referred to
         as "eurocurrency liabilities") of that Lender, but so long as such
         Lender is not required or directed under applicable regulations to
         maintain such reserves, the Reserve Percentage shall be zero."

         1.02 Amendment to Section 2.1(f)(i) of the Loan Agreement. Effective as
              ----------------------------------------------------
of the date hereof, the second sentence contained in Section 2.1(f)(i) of the
Loan Agreement is hereby amended and restated to read in its entirety as
follows:

                  "Each Foothill Loan is an Advance hereunder and shall be
         subject to all the terms and conditions applicable to other Advances,
         except that all payments on any Foothill Loan shall be payable to
         Foothill as a Lender solely for its own account (and for the account of
         the holder of any participation interest with respect to such Foothill
         Loan)."

         1.03 Amendment to Section 2.1(g)(i) of the Loan Agreement. Effective as
              ----------------------------------------------------
of the date hereof, Section 2.1(g)(i) of the Loan Agreement is hereby amended by
adding a second sentence thereto immediately following the first sentence
contained in Section 2.1(g)(i), which second sentence shall read in its entirety
as follows:

         "Each Agent Advance is an Advance hereunder and shall be subject to all
         the terms and conditions applicable to other Advances, except that no
         such Agent Advance shall be eligible for the LIBOR Option and all
         payments thereon shall be payable to Agent solely for its own account
         (and for the account of the holder of any participation interest with
         respect to such Agent Advance)."

         1.04 Amendment to Section 2.1(k) of the Loan Agreement. Effective as of
              -------------------------------------------------
the date hereof, the third sentence contained in Section 2.1(k) of the Loan
Agreement is hereby amended and restated to read in its entirety as follows:

         "The Advances and Foothill Loans, as applicable, that are made pursuant
         to this Section 2.1(k) shall be subject to the same terms and
         conditions as any other Advance or Foothill Loan, as applicable, except
         that they shall not be eligible for the LIBOR Option and the rate of


                                       4
<PAGE>

         interest applicable thereto shall be the rate applicable to Advances
         that are Reference Rate Loans under Section 2.6(c) hereof without
         regard to the presence or absence of a Default or Event of Default;
         provided, that the Required Lenders may, at any time during the
         continuance of an Event of Default or if Borrower fails to satisfy any
         other material lending condition, revoke Agent's authorization
         contained in this Section 2.1(k) to make Overadvances (except for and
         excluding amounts charged to the Loan Account for interest, fees, or
         Lender Group Expenses), any such revocation to be in writing and to
         become effective upon Agent's receipt thereof."

         1.05 Amendment to Section 2.6(a) of the Loan Agreement. Effective as of
              -------------------------------------------------
the date hereof, Section 2.6(a) of the Loan Agreement is hereby amended and
restated to read in its entirety as follows:

                  "(a) Interest Rate. Except as provided in clause (c) and
         clause (d) below, all Obligations (except for amounts undrawn under
         Letters of Credit and Hedging Arrangement Usage) shall bear interest on
         the Daily Balance as follows: (i) if the relevant Obligation is a LIBOR
         Rate Loan, at a per annum rate equal to the LIBOR Rate plus the
         applicable LIBOR Rate Margin as the applicable LIBOR Rate Margin may
         change from time to time, and (ii) otherwise, at a per annum rate equal
         to the Reference Rate plus the applicable Reference Rate Margin as the
         applicable Reference Rate Margin may change from time to time."

         1.06 Amendment to Section 2.6(d) of the Loan Agreement. Effective as of
              -------------------------------------------------
the date hereof, Section 2.6(d) of the Loan Agreement is hereby amended by
deleting "8% per annum" therefrom and substituting in its place "6.75% per
annum".

         1.07 Amendment to Section 2.11(c) of the Loan Agreement. Effective as
              --------------------------------------------------
of the date hereof, Section 2.11(c) of the Loan Agreement is hereby amended and
restated to read in its entirety as follows:

                  "(c) Annual Facility Fee. For the sole and separate account of
         Agent, on each anniversary of the Closing Date occurring after
         September 30, 2001, an annual loan facility fee in an amount equal to
         $200,000, which amount shall be fully earned and nonrefundable in
         advance on such date."

         1.08 Amendment to Section 2.11(e) of the Loan Agreement. Effective as
              --------------------------------------------------
of the date hereof, Section 2.11(e) of the Loan Agreement is hereby amended by
deleting "$10,000" therefrom and substituting in its place "$3,000".

         1.09 Amendment to Section 2.14 of the Loan Agreement. Effective as of
              -----------------------------------------------
the date hereof, Section 2.14 of the Loan Agreement is hereby added to the Loan
Agreement immediately following Section 2.13, which Section 2.14 reads in its
entirety as follows:

         "2.14    LIBOR Option.
          ---------------------

                  (a) Interest and Interest Payment Dates. In lieu of having
                      -----------------------------------
         interest charged at the rate based upon the Reference Rate, Borrower
         shall have the option (the "LIBOR Option") to have interest on all or a
         portion of the Advances be charged at the LIBOR Rate. Interest on LIBOR
         Rate Loans shall be payable on the earliest of (i) the last day of the
         Interest Period applicable thereto, (ii) the occurrence of an Event of
         Default in consequence of which the Required Lenders or Agent on behalf


                                       5
<PAGE>

         thereof elect to accelerate the maturity of the Obligations, (iii)
         termination of this Agreement pursuant to the terms hereof, or (iv) the
         first day of each month that such LIBOR Rate Loan is outstanding. On
         the last day of each applicable Interest Period, unless Borrower
         properly has exercised the LIBOR Option with respect thereto, the
         interest rate applicable to such LIBOR Rate Loan automatically shall
         convert to the rate of interest then applicable to Reference Rate Loans
         of the same type hereunder. At any time that an Event of Default has
         occurred and is continuing, Borrower no longer shall have the option to
         request that Advances bear interest at the LIBOR Rate and Agent shall
         have the right to convert the interest rate on all outstanding LIBOR
         Rate Loans to the rate then applicable to Reference Rate Loans
         hereunder.

                  (b) LIBOR Election.
                      --------------

                           (i) Borrower may, at any time and from time to time,
         so long as no Event of Default has occurred and is continuing, elect to
         exercise the LIBOR Option by notifying Agent prior to 11:00 a.m.
         (California time) at least 3 Business Days prior to the commencement of
         the proposed Interest Period (the "LIBOR Deadline"). Notice of
         Borrower's election of the LIBOR Option for a permitted portion of the
         Advances and an Interest Period pursuant to this Section shall be made
         by delivery to Agent of a LIBOR Notice received by Agent before the
         LIBOR Deadline, or by telephonic notice received by Agent before the
         LIBOR Deadline (to be confirmed by delivery to Agent of a LIBOR Notice
         received by Agent prior to 5:00 p.m. (California time) on the same
         day). Promptly upon its receipt of each such LIBOR Notice, Agent shall
         provide a copy thereof to each of the Lenders having a Commitment.

                           (ii) Each LIBOR Notice shall be irrevocable and
         binding on Borrower. In connection with each LIBOR Rate Loan, Borrower
         shall indemnify, defend, and hold Agent and the Lenders harmless
         against any loss, cost, or expense incurred by Agent or any Lender as a
         result of (a) the payment of any principal of any LIBOR Rate Loan other
         than on the last day of an Interest Period applicable thereto
         (including as a result of an Event of Default), (b) the conversion of
         any LIBOR Rate Loan other than on the last day of the Interest Period
         applicable thereto, or (c) the failure to borrow, convert, continue or
         prepay any LIBOR Rate Loan on the date specified in any LIBOR Notice
         delivered pursuant hereto (such losses, costs, and expenses,
         collectively, "Funding Losses"). Funding Losses shall, with respect to
         Agent or any Lender, be deemed to equal the amount determined by Agent
         or such Lender to be the excess, if any, of (i) the amount of interest
         that would have accrued on the principal amount of such LIBOR Rate Loan
         had such event not occurred, at the LIBOR Rate that would have been
         applicable thereto, for the period from the date of such event to the
         last day of the then current Interest Period therefor (or, in the case
         of a failure to borrow, convert or continue, for the period that would
         have been the Interest Period therefor), minus (ii) the amount of
         interest that would accrue on such principal amount for such period at
         the interest rate which Agent or such Lender would be offered were it
         to be offered, at the commencement of such period, Dollar deposits of a
         comparable amount and period in the London interbank market. A
         certificate of Agent or a Lender delivered to Borrower setting forth
         any amount or amounts that Agent or such Lender is entitled to receive
         pursuant to this Section shall be conclusive absent manifest error.

                                       6
<PAGE>

                           (iii) Borrower shall have not more than 5 LIBOR Rate
         Loans in effect at any given time. Borrower only may exercise the LIBOR
         Option for LIBOR Rate Loans of at least $1,000,000 and integral
         multiples of $500,000 in excess thereof.

                  (c) Prepayments. Borrowers may prepay LIBOR Rate Loans at any
                      -----------
         time; provided, however, that in the event that LIBOR Rate Loans are
         prepaid on any date that is not the last day of the Interest Period
         applicable thereto, including as a result of any automatic prepayment
         through the required application by Agent of proceeds of Collections in
         accordance with Section 2.4(b) or for any other reason, including early
         termination of the term of this Agreement or acceleration of the
         Obligations pursuant to the terms hereof, Borrower shall indemnify,
         defend, and hold Agent and the Lenders and their Participants harmless
         against any and all Funding Losses in accordance with clause (b) above.

                  (d) Special Provisions Applicable to LIBOR Rate.
                      -------------------------------------------

                           (i) The LIBOR Rate may be adjusted by Agent with
         respect to any Lender on a prospective basis to take into account any
         additional or increased costs to such Lender of maintaining or
         obtaining any eurodollar deposits or increased costs due to changes in
         applicable law occurring subsequent to the commencement of the then
         applicable Interest Period, including changes in tax laws (except
         changes of general applicability in corporate income tax laws) and
         changes in the reserve requirements imposed by the Board of Governors
         of the Federal Reserve System (or any successor), excluding the Reserve
         Percentage, which additional or increased costs would increase the cost
         of funding loans bearing interest at the LIBOR Rate. In any such event,
         the affected Lender shall give Borrower and Agent notice of such a
         determination and adjustment and Agent promptly shall transmit the
         notice to each other Lender and, upon its receipt of the notice from
         the affected Lender, Borrower may, by notice to such affected Lender
         (y) require such Lender to furnish to Borrower a statement setting
         forth the basis for adjusting such LIBOR Rate and the method for
         determining the amount of such adjustment, or (z) repay the LIBOR Rate
         Loans with respect to which such adjustment is made (together with any
         amounts due under clause (b)(ii) above).

                           (ii) In the event that any change in market
         conditions or any law, regulation, treaty, or directive, or any change
         therein or in the interpretation of application thereof, shall at any
         time after the date hereof, in the reasonable opinion of any Lender,
         make it unlawful or impractical for such Lender to fund or maintain
         LIBOR Rate Loans or to continue such funding or maintaining, or to
         determine or charge interest rates at the LIBOR Rate, such Lender shall
         give notice of such changed circumstances to Agent and Borrower and
         Agent promptly shall transmit the notice to each other Lender and (y)
         in the case of any LIBOR Rate Loans of such Lender that are
         outstanding, the date specified in such Lender's notice shall be deemed
         to be the last day of the Interest Period of such LIBOR Rate Loans, and
         interest upon the LIBOR Rate Loans of such Lender thereafter shall
         accrue interest at the rate then applicable to Reference Rate Loans,
         and (z) Borrowers shall not be entitled to elect the LIBOR Option until
         such Lender determines that it would no longer be unlawful or
         impractical to do so.

                  (e) No Requirement of Matched Funding. Anything to the
                      ---------------------------------
         contrary contained herein notwithstanding, neither Agent, nor any
         Lender, nor any of their Participants, is required actually to acquire
         eurodollar deposits to fund or otherwise match fund any Obligation as


                                       7
<PAGE>

         to which interest accrues at the LIBOR Rate. The provisions of this
         Section shall apply as if each Lender or its Participants had match
         funded any Obligation as to which interest is accruing at the LIBOR
         Rate by acquiring eurodollar deposits for each Interest Period in the
         amount of the LIBOR Rate Loans."

         1.10 Amendment to Section 3.4 of the Loan Agreement. Effective as of
              ----------------------------------------------
the date hereof, Section 3.4 of the Loan Agreement is hereby amended and
restated to read in its entirety as follows:

                  "3.4 Term. This Agreement shall become effective upon the
         execution and delivery hereof by Borrower and the Lender Group and
         shall continue in full force and effect for a term ending on September
         30, 2003 (the "Maturity Date"). The foregoing notwithstanding, the
         Lender Group, upon the election of the Required Lenders, shall have the
         right to terminate its obligations under this Agreement immediately and
         without notice upon the occurrence and during the continuation of an
         Event of Default."

         1.11 Amendment to Section 3.6 of the Loan Agreement. Effective as of
              ----------------------------------------------
the date hereof, Section 3.6 of the Loan Agreement is hereby amended and
restated in its entirety as follows:

                  "3.6 Early Termination by Borrower. Borrower has the option,
         at any time upon 90 days prior written notice to Agent, to terminate
         this Agreement by paying to Agent, for the ratable benefit of the
         Lender Group, in cash, the Obligations (including an amount equal to
         110% of the undrawn amount of the Letters of Credit and the Hedging
         Arrangement Usage), in full, together with a premium (the "Early
         Termination Premium") equal to the greater of (a) the total interest
         and Letter of Credit fees and Hedging Agreement Undertaking fees for
         the immediately preceding 6 months, and (b) if the termination occurs
         (i) on or before the third anniversary of the Closing Date, an amount
         equal to one percent (1%) of the Maximum Revolving Amount, and (ii) if
         the termination occurs at any time after the third anniversary of the
         Closing Date (other than the Maturity Date), an amount equal to one
         half of one percent (0.5%) of the Maximum Revolving Amount."

         1.12 Amendment to Section 6.19 of the Loan Agreement. Effective as of
              -----------------------------------------------
the date hereof, Section 6.19 of the Loan Agreement is hereby amended by
deleting "September 30, 2001" therefrom and substituting in its place "the
Maturity Date".

         1.13 Amendment to Section 7.20(b) of the Loan Agreement. Effective as
              --------------------------------------------------
of the date hereof, Section 7.20(b) of the Loan Agreement is hereby amended and
restated to read in its entirety as follows:

         "(b) Consolidated Interest Coverage Ratio. As of the last day of each
         month, a ratio of (i) Borrower's consolidated EBITDA for the 12
         consecutive fiscal month period then ended, to (ii) Borrower's
         consolidated Interest Expense for the 12 consecutive fiscal month
         period then ended, of at least 2.0 to 1.0."

         1.14 Amendment to Section 7.21 of the Loan Agreement. Effective as of
              -----------------------------------------------
the date hereof, Section 7.21 of the Loan Agreement is hereby amended and
restated to read in its entirety as follows:

                  "7.21 Capital Expenditures. Make Capital Expenditures in
                        --------------------
         excess of (a) $40,000,000 during Borrower's fiscal year ending December
         31, 2000, (b) $45,000,000 during Borrower's fiscal year ending December
         31, 2001, or (iii) $35,000,000 during any fiscal year of Borrower
         ending on or after January 1, 2002."

                                       8
<PAGE>

         1.15 Amendment of Schedule C-1 of the Loan Agreement. Effective as of
              -----------------------------------------------
the date hereof, Schedule C-1 the Loan Agreement is hereby amended and restated
to read in its entirety as set forth on Annex I to this Amendment.

         1.16 Addition of Schedule L-1 to the Loan Agreement. Effective as of
              ----------------------------------------------
the date hereof, the Loan Agreement is hereby amended to add Schedule L-1 to the
Loan Agreement, which Schedule L-1 shall read in its entirety as set forth on
Annex II to this Amendment.

                                   ARTICLE II
                              Conditions Precedent
                              --------------------

         2.01 Conditions to Effectiveness. The effectiveness of this Amendment
              ---------------------------
is subject to the satisfaction of the following conditions precedent in a manner
satisfactory to Agent, unless specifically waived in writing by Agent:

         (a)      Agent shall have received this Amendment, duly executed by
Borrower and each Lender.

         (b)      Agent shall have received the Amendment Fee described in
Section 4.11 of this Amendment.

         (c) The representations and warranties contained herein and in the Loan
Agreement and the other Loan Documents, as each is amended hereby, shall be true
and correct as of the date hereof, as if made on the date hereof.

         (d) No Default or Event of Default shall have occurred and be
continuing, unless such Default or Event of Default has been otherwise
specifically waived in writing by Agent and to the extent required by the Loan
Agreement, the Lenders.

         (e) All corporate proceedings taken in connection with the transactions
contemplated by this Amendment and all documents, instruments and other legal
matters incident thereto shall be satisfactory to Agent and its legal counsel.

                                   ARTICLE III
                  Ratifications, Representations and Warranties
                  ---------------------------------------------

         3.01 Ratifications. The terms and provisions set forth in this
              -------------
Amendment shall modify and supersede all inconsistent terms and provisions set
forth in the Loan Agreement and the other Loan Documents, and, except as
expressly modified and superseded by this Amendment, the terms and provisions of
the Loan Agreement and the other Loan Documents are ratified and confirmed and
shall continue in full force and effect. Borrower, Agent and Lenders agree that
the Loan Agreement and the other Loan Documents, as amended hereby, shall
continue to be legal, valid, binding and enforceable in accordance with their
respective terms.

         3.02 Representations and Warranties. Borrower hereby represents and
              ------------------------------
warrants to Agent and each Lender that (a) the execution, delivery and
performance of this Amendment and any and all other Loan Documents executed
and/or delivered in connection herewith have been authorized by all requisite
corporate action on the part of Borrower and will not violate the Articles of
Incorporation or Bylaws of Borrower; (b) attached hereto as Annex III is a true,
correct and complete copy of presently effective resolutions of Borrower's Board
of Directors authorizing the execution, delivery and performance of this


                                       9
<PAGE>

Amendment and any and all other Loan Documents executed and/or delivered in
connection herewith, certified by the Secretary of Borrower; (c) the
representations and warranties contained in the Loan Agreement, as amended
hereby, and any other Loan Document are true and correct on and as of the date
hereof; (d) no Default or Event of Default under the Loan Agreement, as amended
hereby, has occurred and is continuing, unless such Default or Event of Default
has been specifically waived in writing by Agent and to the extent required by
the Loan Agreement, the Lenders; (e) Borrower is in full compliance with all
covenants and agreements contained in the Loan Agreement and the other Loan
Documents, as amended hereby; and (f) Borrower has not amended its Articles of
Incorporation or its Bylaws since the Closing Date.

                                   ARTICLE IV
                            Miscellaneous Provisions
                            ------------------------

         4.01 Survival of Representations and Warranties. All representations
              ------------------------------------------
and warranties made in the Loan Agreement or any other Loan Document, including,
without limitation, any document furnished in connection with this Amendment,
shall survive the execution and delivery of this Amendment and the other Loan
Documents, and no investigation by Agent or any closing shall affect the
representations and warranties or the right of Agent and the Lenders to rely
upon them.

         4.02 Amendment to References in all Loan Documents. Effective as of the
              ---------------------------------------------
date hereof, any reference in the Loan Documents to the capitalized terms "Loan
Agreement" or "Credit Agreement" or to the Amended and Restated Loan and
Security Agreement, dated as of September 30, 1999, by and among the Borrower,
PPC (prior to its merger with and into Borrower), the Lenders and the Agent,
shall be deemed a reference to the Loan Agreement (as defined in this
Amendment), as amended hereby.

         4.03 Expenses of Agent and Lenders. As provided in the Loan Agreement,
              -----------------------------
Borrower agrees to pay on demand all costs and expenses incurred by Agent and
Lenders in connection with the preparation, negotiation, and execution of this
Amendment and the other Loan Documents executed pursuant hereto and any and all
amendments, modifications, and supplements thereto, including, without
limitation, the costs and fees of Agent's and Lenders' legal counsel, and all
costs and expenses incurred by Agent and Lenders in connection with the
enforcement or preservation of any rights under the Loan Agreement, as amended
hereby, or any other Loan Documents, including, without, limitation, the costs
and fees of Agent's and Lenders' legal counsel.

         4.04 Severability. Any provision of this Amendment held by a court of
              ------------
competent jurisdiction to be invalid or unenforceable shall not impair or
invalidate the remainder of this Amendment and the effect thereof shall be
confined to the provision so held to be invalid or unenforceable.

         4.05 Successors and Assigns. This Amendment is binding upon and shall
              ----------------------
inure to the benefit of Agent, each Lender and Borrower and their respective
successors and assigns, except that Borrower may not assign or transfer any of
its rights or obligations hereunder without the prior written consent of Agent.

         4.06 Counterparts. This Amendment may be executed in one or more
              ------------
counterparts, each of which when so executed shall be deemed to be an original,
but all of which when taken together shall constitute one and the same
instrument.

                                       10
<PAGE>

         4.07 Effect of Waiver. No consent or waiver, express or implied, by
              ----------------
Agent or any Lender to or for any breach of or deviation from any covenant or
condition by Borrower shall be deemed a consent to or waiver of any other breach
of the same or any other covenant, condition or duty.

         4.08 Headings.  The headings,  captions,  and  arrangements  used
              --------
in this Amendment are for convenience only and shall not affect the
interpretation of this Amendment.

         4.09 Applicable Law. THIS AMENDMENT AND ALL OTHER LOAN DOCUMENTS
              --------------
EXECUTED PURSUANT HERETO SHALL BE DEEMED TO HAVE BEEN MADE AND TO BE PERFORMABLE
IN AND SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE
STATE OF NEW YORK.

         4.10 Final Agreement. THE LOAN AGREEMENT AND THE OTHER LOAN DOCUMENTS,
              ---------------
EACH AS AMENDED HEREBY, REPRESENT THE ENTIRE EXPRESSION OF THE PARTIES WITH
RESPECT TO THE SUBJECT MATTER HEREOF ON THE DATE THIS AMENDMENT IS EXECUTED. THE
LOAN AGREEMENT AND THE OTHER LOAN DOCUMENTS, AS AMENDED HEREBY, MAY NOT BE
CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS
OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. NO
MODIFICATION, RESCISSION, WAIVER, RELEASE OR AMENDMENT OF ANY PROVISION OF THIS
AMENDMENT SHALL BE MADE, EXCEPT BY A WRITTEN AGREEMENT SIGNED BY EACH BORROWER
AND AGENT.

         4.11 Amendment Fee. In consideration of the execution of this
              -------------
Amendment, Borrower agrees to pay to Agent on the date of this Amendment, for
the sole and separate account of Agent, an amendment fee of $50,000, which fee
shall be fully earned and non-refundable as of the date of this Amendment.

     [remainder of page intentionally left blank; signature page follows]


                                       11
<PAGE>


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

                                  BORROWER:
                                  --------

                                  PANACO, INC.

                                  By:
                                         --------------------------------------
                                  Name:
                                         --------------------------------------
                                  Title:
                                         --------------------------------------



                                  AGENT:
                                  -----

                                  FOOTHILL CAPITAL CORPORATION,
                                  as Agent for the Lenders

                                  By:
                                         --------------------------------------
                                         Jeffrey Stanek
                                         Vice President


                                  LENDERS:
                                  -------

                                  FOOTHILL CAPITAL CORPORATION, as a Lender

                                  By:
                                         --------------------------------------
                                         Jeffrey Stanek
                                         Vice President





                                       12
<PAGE>





                                     ANNEX I
                                       TO
                     SIXTH AMENDMENT TO AMENDED AND RESTATED
                           LOAN AND SECURITY AGREEMENT


                                  "EXHIBIT C-1

                                   COMMITMENTS
                                   -----------


             Name of Lender                              Commitment
             --------------                              ----------

             Foothill Capital Corporation                $40,000,000"





                                       13
<PAGE>
                                    ANNEX II
                                       TO
                     SIXTH AMENDMENT TO AMENDED AND RESTATED
                           LOAN AND SECURITY AGREEMENT


                                  "EXHIBIT L-1

                              FORM OF LIBOR NOTICE
                              --------------------

Foothill Capital Corporation, as Agent for the Lenders
2450 Colorado Avenue
Suite 3000 West
Santa Monica, California 90404
Attention:  Jeff Stanek

Ladies and Gentlemen:

         Reference hereby is made to that certain Amended and Restated Loan and
Security Agreement, dated as of September 30, 1999 (the "Loan Agreement"), by
and among PANACO, INC., a Delaware corporation ("Borrower") which is the sole
surviving corporation of the merger by Panaco Production Company, a Texas
corporation ("PPC") and Goldking Acquisition Corporation, a Delaware corporation
("GAC"), with and into Borrower and is the successor-by-merger to PPC and GAC
thereunder; the financial institutions signatory thereto (together with their
successors and assigns, individually, "Lender" and, collectively, "Lenders"),
and FOOTHILL CAPITAL CORPORATION, a California corporation, as agent for the
Lenders (in such capacity, together with its successors, if any, "Agent") (as
amended, restated or otherwise modified from time to time, the "Loan
Agreement"). Any and all initially capitalized terms which are used but not
specifically defined herein shall have the meanings ascribed to them in the Loan
Agreement.

         This LIBOR Notice represents Borrower's request to elect the LIBOR
Option with respect to outstanding Advances in the amount of $__________ (the
"LIBOR Rate Loan")[, and is a written confirmation of the telephonic notice of
such election given to Agent].

         Such LIBOR Rate Loan will have an Interest Period of [1, 2 or 3]
month(s) commencing on ________________.

         This LIBOR Notice further confirms Borrower's acceptance, for purposes
of determining the rate of interest based on the LIBOR Rate under the Loan
Agreement, of the LIBOR Rate as determined pursuant to the Loan Agreement.

         Borrower represents and warrants that (i) as of the date hereof, each
representation or warranty contained in or pursuant to any Loan Document, any
agreement, instrument, certificate, document or other writing furnished at any
time under or in connection with any Loan Document, and as of the effective date
of any advance, continuation or conversion requested above is true and correct
in all material respects (except to the extent any representation or warranty
expressly related to an earlier date), (ii) each of the covenants and agreements
contained in any Loan Document have been performed (to the extent required to be
performed on or before the date hereof or each such effective date), and (iii)
no Default or Event of Default has occurred and is continuing on the date
hereof, nor will any thereof occur after giving effect to the request above.

                                       14
<PAGE>

Dated:   ________________        PANACO, INC.

                                 By:
                                       ----------------------------------------
                                 Name:
                                       ----------------------------------------
                                 Title:
                                       ----------------------------------------




Acknowledged by:

FOOTHILL CAPITAL CORPORATION,
as Agent for the Lenders

By:
      ---------------------------------------
Name:
      ---------------------------------------
Title:
      ---------------------------------------



                                       15
<PAGE>




                                   ANNEX III
                   TO SIXTH AMENDMENT TO AMENDED AND RESTATED
                           LOAN AND SECURITY AGREEMENT

           CERTIFIED RESOLUTIONS OF PANACO, INC.'S BOARD OF DIRECTORS
           ----------------------------------------------------------

         RESOLVED: That any officer of Panaco, Inc., a Delaware corporation (the
"Corporation"), acting alone, by his signature be, and the same hereby is,
authorized and directed, in the name of and on behalf of the Corporation (a) to
amend that certain Amended and Restated Loan and Security Agreement by and among
the Corporation, Panaco Production Company, Lenders signatory thereto and
Foothill Capital Corporation, a California corporation, as agent for Lenders
("Agent"), as amended by that certain First Amendment to Amended and Restated
Loan and Security Agreement, dated November 30, 1999, by and among the same
parties, as amended by that certain Second Amendment to Amended and Restated
Loan and Security Agreement, dated September 29, 2000, by and among the same
parties, as amended by that certain Third Amendment to Amended and Restated Loan
and Security Agreement, dated December 21, 2000, by and among the same parties,
as amended by that certain Fourth Amendment to Amended and Restated Loan and
Security Agreement, dated September 30, 2001, by and among the same parties, and
as amended by that certain Fifth Amendment to Amended and Restated Loan and
Security Agreement, dated October 29, 2001, by and among the same parties, (b)
to execute and deliver to Agent with such changes in the terms and provisions
thereof as the officer executing same shall, in his sole discretion, deem
advisable, (i) a certain proposed Sixth Amendment to Amended and Restated Loan
and Security Agreement to be executed by Corporation, Lenders and Agent, a draft
of which has been reviewed and discussed by the Board of Directors of the
Corporation, and (ii) such other Loan Documents, instruments, statements and
writings as the officer or officers executing the same may deem desirable or
necessary in connection therewith, and (c) to perform such other acts as the
officer or officers performing such acts on behalf of the Corporation may deem
desirable or necessary in connection therewith; and be it

         FURTHER  RESOLVED:  That said  agreements  will benefit the
Corporation,  both directly and  indirectly,  and are in the best interests of
the Corporation; and be it

         FURTHER  RESOLVED:  That  said  agreements  and  other  statements  in
writing  executed  in the  name and on  behalf  of the Corporation  by any
officer of the  Corporation  shall be presumed  conclusively  to be the
instruments,  the  execution  of which is authorized by these resolutions; and
be it

         FURTHER RESOLVED: That the officers of the Corporation be, and the same
hereby are, authorized and directed to execute, in the name of and on behalf of
the Corporation, security agreements, financing statements, mortgages, deeds of
trust, assignments, collateral reports, loan statements, confirmations of
delivery, lien statements, pledge certificates, release certificates, removal
reports, guaranties, cross-collateralization agreements and such other writings
and to take such other actions as are necessary in their dealings with Agent,
and any such papers executed and any such actions taken by any of them prior to
this time are approved, ratified and confirmed; and be it

         FURTHER RESOLVED: That the Secretary or any Assistant Secretary of the
Corporation, by the signature of any one or more of them, be, and the same
hereby are, authorized and directed to attest the execution by the Corporation
of the papers signed pursuant to these resolutions, to affix the seal of the
Corporation thereto, if required by Agent, and to certify to Agent the adoption
of these resolutions.

                                  CERTIFICATION
                                  -------------

         The undersigned hereby certifies that the within and foregoing
resolutions are in effect as of the date hereof, without modification, and that
the person signing the within and foregoing Amendment on behalf of the
Corporation is the duly elected officer stated below his name, that he is
authorized to sign such Amendment, and that his signature thereon is genuine.

         DATED:  November  ___, 2001

                                        ---------------------------------------
                                        Assistant] Secretary of the Corporation

                                       16
<PAGE>
                             SEVENTH AMENDMENT TO
                AMENDED AND RESTATED LOAN AND SECURITY AGREEMENT
                ------------------------------------------------


         THIS  SEVENTH  AMENDMENT  TO AMENDED  AND  RESTATED  LOAN AND  SECURITY
AGREEMENT (this "Amendment") is made and entered into as of March ____, 2002, by
                 ---------
and among: PANACO,  INC., a Delaware corporation  ("Borrower") which is the sole
                                                    --------
surviving  corporation  of the  merger by  Panaco  Production  Company,  a Texas
corporation ("PPC") and Goldking Acquisition Corporation, a Delaware corporation
              ---
("GAC"),  with and into Borrower and is the  successor-by-merger  to PPC and GAC
  ---
thereunder;  the financial  institutions  listed on the  signature  pages hereof
(such  financial  institutions,  together with their  respective  successors and
assigns,  are  referred  to  hereinafter  each  individually  as a "Lender"  and
                                                                    ------
collectively as the "Lenders");  and FOOTHILL CAPITAL CORPORATION,  a California
                     -------
corporation, as agent for the Lenders ("Agent").
                                        -----

                                    RECITALS
                                    --------

         A. Borrower,  PPC (prior to its merger with and into Borrower),
Agent and Lenders have entered into that certain  Amended and Restated  Loan and
Security  Agreement,  dated as of September 30, 1999, as amended by that certain
First  Amendment to Amended and  Restated  Loan and  Security  Agreement,  dated
November 30, 1999,  as amended by that certain  Second  Amendment to Amended and
Restated Loan and Security  Agreement,  dated  September 29, 2000, as amended by
that  certain  Third  Amendment  to  Amended  and  Restated  Loan  and  Security
Agreement,  dated December 21, 2000, as amended by that certain Fourth Amendment
to Amended and Restated Loan and Security  Agreement,  dated September 30, 2001,
as amended by that certain  Fifth  Amendment  to Amended and  Restated  Loan and
Security Agreement, dated October 29, 2001, and as amended by that certain Sixth
Amendment to Amended and Restated Loan and Security Agreement, dated November 9,
2001 (as so amended, the "Loan Agreement").
                          --------------

         B. Capitalized  terms  used in  this  Amendment  are used as defined in
the Loan  Agreement,  as amended  hereby,  unless otherwise stated.

         C. Borrower has  requested  that Lenders  (i)  waive  certain Events of
Default  that occurred from  Borrower's failure to comply  with (a) Section 6.19
                                                                    ------------
of the Loan  Agreement  from  January 1, 2002  through  the date  hereof and (b)
Section  7.20(a) of the Loan Agreement on December 31, 2001 and January 31, 2002
---------------
(collectively,  the  "Specified  Events  of  Default"),  (ii)  waive  Borrower's
obligation  to comply  with  Section  6.19 of the Loan  Agreement  from the date
                             -------------
hereof through March 31, 2002 (the "Hedging Obligation"), and (iii) make certain
                                    ------------------
modifications to the Loan Agreement.

         D. Borrower, Agent and Lenders desire to amend the Loan Agreement
as hereinafter set forth.

         NOW,  THEREFORE,  in consideration of the premises herein contained and
other good and valuable consideration,  the receipt and sufficiency of which are
hereby  acknowledged,  the  parties,  intending  to be legally  bound,  agree as
follows:

                                       1
<PAGE>

                                    AGREEMENT
                                    ---------

                                    ARTICLE I
                                 Limited Waiver
                                 --------------

         1.01  Limited  Waiver.  Upon  satisfaction  of  the  conditions
               ---------------
precedent set forth in Article III hereof, the Lenders signatory hereto,  hereby
waive the Hedging Obligation from the date hereof through March 31, 2002 and the
Specified Events of Default.  Except as specifically  provided  herein,  nothing
contained in this Amendment  shall be construed as a waiver by any Lender of any
covenant or  provision of the Loan  Agreement,  the other Loan  Documents,  this
Amendment or of any other  contract or  instrument  between the Borrower and any
Lender, and the failure of the Lenders at any time or times hereafter to require
strict  performance  by the Borrower of any  provision  thereof shall not waive,
affect  or  diminish  any  right  of the  Lenders  to  hereafter  demand  strict
compliance  therewith.  Each Lender hereby reserves all rights granted under the
Loan Agreement, the other Loan Documents,  this Amendment and any other contract
or instrument between the Borrower and any Lender.

                                   ARTICLE II
                          Amendments to Loan Agreement
                          ----------------------------

         2.01  Amendment  to  Section  7.20(a)  of  the  Loan  Agreement.
               ---------------------------------------------------------
Effective as of the date hereof, Section 7.20(a) of the Loan Agreement is hereby
amended and restated to read in its entirety as follows:

               "(a) Current Ratio.  As of the last day of each month, a ratio of
         Consolidated  Current Assets divided by  Consolidated  Current
         Liabilities  of at least (i)  0.15:1.0  for each month  ending  between
         January 1, 2002 and April 30, 2002, (ii) 0.20:1.0 for each month ending
         between May 1, 2002 and January 1, 2003,  and (iii)  0.25:1.0  for each
         month ending after January 1, 2003;"

         2.02  Amendment  to  Section  7.20(b)  of  the  Loan  Agreement.
               ---------------------------------------------------------
Effective as of the date hereof, Section 7.20(b) of the Loan Agreement is hereby
amended and restated to read in its entirety as follows:

               "(b) Consolidated  Interest  Coverage  Ratio. As of the last day
         of each month, a ratio of (i) Borrower's  consolidated  EBITDA for  the
         12  consecutive  fiscal  month  period  then  ended,  to  (ii)
         Borrower's  consolidated Interest Expense for the 12 consecutive fiscal
         month period then ended,  of at least the ratio set forth below for the
         month ending corresponding to such ratio:

                                       2
<PAGE>

<TABLE>

---------------------------------------- --------------------------------------
<CAPTION>
             Month                                  Ratio
---------------------------------------- --------------------------------------
<S>           <C>                                    <C>
---------------------------------------- --------------------------------------
          January 2002                             2.00:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
         February 2002                             1.90:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
           March 2002                              1.95:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
           April 2002                              1.70:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
            May 2002                               1.50:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
           June 2002                               1.20:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
           July 2002                               1.20:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
          August 2002                              1.00:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
         September 2002                            0.85:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
          October 2002                             0.70:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
         November 2002                             0.55:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
         December 2002                             1.00:1.0
---------------------------------------- --------------------------------------
---------------------------------------- --------------------------------------
        January 2003 and                           2.00:1.0
     each month thereafter
---------------------------------------- --------------------------------------
</TABLE>

                                   ARTICLE III
                              Conditions Precedent
                              --------------------

         3.01 Conditions  to  Effectiveness.  The  effectiveness  of this
              -----------------------------
Amendment is subject to the satisfaction of the following  conditions  precedent
in a manner  satisfactory  to Agent,  unless  specifically  waived in writing by
Agent:

         (a) Agent shall have received this Amendment, duly executed by
Borrower and each Lender.

         (b) Agent shall have received the Amendment Fee described in
Section 5.11 of this Amendment.
------------

         (c) The representations  and warranties  contained herein and in
the Loan  Agreement  and the other Loan  Documents,  as each is amended  hereby,
shall be true and correct as of the date hereof, as if made on the date hereof.

         (d) No Default or Event of Default  shall have  occurred  and be
continuing,  unless  such  Default  or  Event  of  Default  has  been  otherwise
specifically  waived in writing by Agent and to the extent  required by the Loan
Agreement, the Lenders.

         (e) All  corporate  proceedings  taken in  connection  with the
transactions  contemplated by this Amendment and all documents,  instruments and
other legal  matters  incident  thereto shall be  satisfactory  to Agent and its
legal counsel.

                                   ARTICLE IV
                  Ratifications, Representations and Warranties
                  ---------------------------------------------

         4.01 Ratifications.  The terms and  provisions set forth in this
              -------------
Amendment shall modify and supersede all  inconsistent  terms and provisions set
forth in the Loan  Agreement  and the  other  Loan  Documents,  and,  except  as


                                       3
<PAGE>

expressly modified and superseded by this Amendment, the terms and provisions of
the Loan  Agreement and the other Loan  Documents are ratified and confirmed and
shall continue in full force and effect.  Borrower, Agent and Lenders agree that
the Loan  Agreement  and the other  Loan  Documents,  as amended  hereby,  shall
continue to be legal,  valid,  binding and  enforceable in accordance with their
respective terms.

         4.02 Representations and Warranties.  Borrower hereby represents
              ------------------------------
and  warrants  to Agent and each  Lender that (a) the  execution,  delivery  and
performance  of this  Amendment  and any and all other Loan  Documents  executed
and/or  delivered in connection  herewith have been  authorized by all requisite
corporate  action on the part of Borrower  and will not violate the  Articles of
Incorporation  or Bylaws of Borrower;  (b) attached hereto as Annex I is a true,
                                                              -------
correct and complete copy of presently effective resolutions of Borrower's Board
of  Directors  authorizing  the  execution,  delivery  and  performance  of this
Amendment  and any and all other Loan  Documents  executed  and/or  delivered in
connection   herewith,   certified  by  the  Secretary  of  Borrower;   (c)  the
representations  and  warranties  contained  in the Loan  Agreement,  as amended
hereby,  and any other Loan  Document are true and correct on and as of the date
hereof; (d) no Default or Event of Default under the Loan Agreement,  as amended
hereby, has occurred and is continuing,  unless such Default or Event of Default
has been  specifically  waived in writing by Agent and to the extent required by
the Loan  Agreement,  the Lenders;  (e) Borrower is in full  compliance with all
covenants  and  agreements  contained in the Loan  Agreement  and the other Loan
Documents,  as amended hereby;  and (f) Borrower has not amended its Articles of
Incorporation or its Bylaws since the Closing Date.

                                    ARTICLE V
                            Miscellaneous Provisions
                            ------------------------

         5.01  Survival   of   Representations   and   Warranties.   All
               --------------------------------------------------
representations  and  warranties  made in the Loan  Agreement  or any other Loan
Document,  including,  without limitation,  any document furnished in connection
with this Amendment,  shall survive the execution and delivery of this Amendment
and the other Loan Documents, and no investigation by Agent or any closing shall
affect the  representations and warranties or the right of Agent and the Lenders
to rely upon them.

         5.02 Amendment  to  References  in all Loan  Documents. Effective as of
              -------------------------------------------------
the date  hereof,  any  reference  in the Loan  Documents to the capitalized
terms "Loan Agreement" or "Credit  Agreement" or to the Amended and Restated
Loan and Security  Agreement,  dated as of September  30, 1999, by and among the
Borrower,  PPC  (prior to its  merger  with and into  Borrower),  the Lenders
and the Agent,  shall be deemed a reference  to the Loan  Agreement  (as defined
in this Amendment), as amended hereby.

         5.03 Expenses  of Agent and  Lenders.  As  provided  in the Loan
              -------------------------------
Agreement,  Borrower agrees to pay on demand all costs and expenses incurred by
Agent and Lenders in connection with the preparation, negotiation, and execution
of this Amendment and the other  Loan Documents executed pursuant hereto and any
and all amendments, modifications,  and supplements thereto,  including, without
limitation,  the costs and fees of Agent's and Lenders'  legal counsel,  and all
costs  and  expenses  incurred  by Agent  and  Lenders  in  connection  with the
enforcement or preservation  of any rights under the Loan Agreement,  as amended
hereby, or any other Loan Documents,  including,  without, limitation, the costs
and fees of Agent's and Lenders' legal counsel.

                                       4
<PAGE>

         5.04 Severability.  Any  provision of this  Amendment  held by a
              ------------
court of competent  jurisdiction to be invalid or unenforceable shall not impair
or invalidate  the remainder of this  Amendment and the effect  thereof shall be
confined to the provision so held to be invalid or unenforceable.

         5.05 Successors and Assigns.  This Amendment is binding upon and
              ----------------------
shall  inure to the  benefit  of  Agent,  each  Lender  and  Borrower  and their
respective  successors  and  assigns,  except  that  Borrower  may not assign or
transfer any of its rights or  obligations  hereunder  without the prior written
consent of Agent.

         5.06 Counterparts.  This Amendment may be executed in one or more
              ------------
counterparts,  each of which when so executed shall be deemed to be an original,
but all of  which  when  taken  together  shall  constitute  one  and  the  same
instrument.

         5.07 Effect of Waiver. No consent or waiver,  express or implied,
              ----------------
by Agent or any Lender to or for any breach of or deviation from any covenant or
condition by Borrower shall be deemed a consent to or waiver of any other breach
of the same or any other covenant, condition or duty.

         5.08 Headings.  The  headings,  captions,  and  arrangements  used  in
              --------
this Amendment are for convenience only and shall not affect the interpretation
of this Amendment.

         5.09 Applicable Law. THIS AMENDMENT AND ALL OTHER LOAN DOCUMENTS
              --------------
EXECUTED PURSUANT HERETO SHALL BE DEEMED TO HAVE BEEN MADE AND TO BE PERFORMABLE
IN AND SHALL BE GOVERNED BY AND  CONSTRUED  IN  ACCORDANCE  WITH THE LAWS OF THE
STATE OF NEW YORK.

         5.10 Final  Agreement.  THE LOAN  AGREEMENT  AND THE OTHER LOAN
              ----------------
DOCUMENTS,  EACH AS  AMENDED  HEREBY,  REPRESENT  THE ENTIRE  EXPRESSION  OF THE
PARTIES WITH RESPECT TO THE SUBJECT  MATTER HEREOF ON THE DATE THIS AMENDMENT IS
EXECUTED.  THE LOAN AGREEMENT AND THE OTHER LOAN  DOCUMENTS,  AS AMENDED HEREBY,
MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL
AGREEMENTS OF THE PARTIES.  THERE ARE NO UNWRITTEN ORAL  AGREEMENTS  BETWEEN THE
PARTIES.  NO  MODIFICATION,  RESCISSION,  WAIVER,  RELEASE OR  AMENDMENT  OF ANY
PROVISION OF THIS AMENDMENT SHALL BE MADE,  EXCEPT BY A WRITTEN AGREEMENT SIGNED
BY EACH BORROWER AND AGENT.

         5.11 Amendment  Fee. In  consideration  of the execution of this
              --------------
Amendment,  Borrower agrees to pay to Agent on the date of this  Amendment,  for
the sole and separate  account of Agent, an amendment fee of $75,000,  which fee
shall be  fully  earned  and  non-refundable  as of the date of this  Amendment;
provided,  however, that in the event (i) substantially all of the capital stock
--------   -------
of  Borrower  is sold in a  transaction  and (ii) all  Obligations  owed to each
Lender and Agent are paid in full,  in each case prior to June 28,  2002,  Agent
agrees  promptly  thereafter  to refund to  Borrower  a $37,500  portion of such
amendment fee.

     [remainder of page intentionally left blank; signature page follows]

                                       5
<PAGE>




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

                                    BORROWER:

                                    PANACO, INC.


                                    By:
                                          --------------------------------------
                                    Name:
                                          --------------------------------------
                                    Title:
                                          --------------------------------------



                                    AGENT:

                                    FOOTHILL CAPITAL CORPORATION,
                                    as Agent for the Lenders


                                    By:
                                          -------------------------------------
                                          Jeffrey Stanek
                                          Vice President


                                    LENDERS:

                                    FOOTHILL CAPITAL CORPORATION, as a Lender


                                    By:
                                          -------------------------------------
                                          Jeffrey Stanek
                                          Vice President








                                       6
<PAGE>



                                      ANNEX I
                             TO SEVENTH AMENDMENT TO
                AMENDED AND RESTATED LOAN AND SECURITY AGREEMENT


           CERTIFIED RESOLUTIONS OF PANACO, INC.'S BOARD OF DIRECTORS
           ----------------------------------------------------------

         RESOLVED: That any officer of Panaco, Inc., a Delaware corporation (the
"Corporation"),  acting  alone,  by his  signature  be, and the same  hereby is,
authorized and directed,  in the name of and on behalf of the Corporation (a) to
amend that certain Amended and Restated Loan and Security Agreement by and among
the Corporation,  Panaco  Production  Company,  Lenders  signatory  thereto (the
"Lenders") and Foothill Capital Corporation, a California corporation,  as agent
 -------
for  Lenders  ("Agent"),  as the  same may be  amended,  restated  or  otherwise
                -----
modified  from time to time,  (b) to  execute  and  deliver  to Agent  with such
changes in the terms and provisions thereof as the officer executing same shall,
in his sole discretion, deem advisable, (i) a certain proposed Seventh Amendment
to  Amended  and  Restated  Loan  and  Security  Agreement  to  be  executed  by
Corporation, Lenders and Agent, a draft of which has been reviewed and discussed
by the  Board  of  Directors  of the  Corporation,  and  (ii)  such  other  loan
documents,  instruments,  statements  and  writings  as the  officer or officers
executing the same may deem desirable or necessary in connection therewith,  and
(c) to perform such other acts as the officer or officers  performing  such acts
on behalf of the  Corporation  may deem  desirable or  necessary  in  connection
therewith; and be it

         FURTHER  RESOLVED:  That said  agreements will benefit the Corporation,
both directly and  indirectly, and are in the best interests of the Corporation;
and be it

         FURTHER  RESOLVED:  That  said  agreements  and  other  statements  in
writing  executed  in the  name and on  behalf of the Corporation by any officer
of  the  Corporation  shall  be presumed conclusively to be the instruments, the
execution  of which is authorized by these resolutions; and be it

         FURTHER RESOLVED: That the officers of the Corporation be, and the same
hereby are,  authorized and directed to execute, in the name of and on behalf of
the Corporation,  security agreements, financing statements, mortgages, deeds of
trust,  assignments,  collateral  reports,  loan  statements,  confirmations  of
delivery, lien statements,  pledge certificates,  release certificates,  removal
reports, guaranties,  cross-collateralization agreements and such other writings
and to take such other  actions as are  necessary in their  dealings with Agent,
and any such papers  executed and any such actions taken by any of them prior to
this time are approved, ratified and confirmed; and be it

         FURTHER RESOLVED:  That the Secretary or any Assistant Secretary of the
Corporation,  by the  signature  of any one or more of  them,  be,  and the same
hereby are,  authorized and directed to attest the execution by the  Corporation
of the papers  signed  pursuant to these  resolutions,  to affix the seal of the
Corporation  thereto, if required by Agent, and to certify to Agent the adoption
of these resolutions.

                                  CERTIFICATION
                                  -------------

         The  undersigned   hereby  certifies  that  the  within  and  foregoing
resolutions are in effect as of the date hereof, without modification,  and that
the  person  signing  the  within  and  foregoing  Amendment  on  behalf  of the
Corporation  is the duly  elected  officer  stated  below his  name,  that he is
authorized to sign such Amendment, and that his signature thereon is genuine.

         DATED:  March  ___, 2002

                                          -------------------------------------
                                          Secretary of the Corporation


                                       7
<PAGE>