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                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                                ________________

                                    FORM 10-Q

(Mark One)

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

            For the quarterly period ended September 30, 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
 incorporation or organization)                             Number)

     1100 Louisiana Street, Suite 5100
            Houston, Texas                                   77002
    (Address of principal executive offices)               (Zip Code)

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



     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 _______.


     24,359,695  shares of the  registrant's  $.01 par value  Common  Stock were
outstanding on September 30, 2001.



--------------------------------------------------------------------------------
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<PAGE>
                                  PANACO, Inc.
                            Condensed Balance Sheets


                                     ASSETS

<TABLE>
<CAPTION>

                                                              As of                     As of
                                                       September 30, 2001         December 31, 2000
                                                       ------------------         -----------------
<S>                                                             <C>                        <C>

 CURRENT ASSETS                                             (Unaudited)
   Cash                                                $      9,313,000            $     2,878,000
    Accounts receivable, net of an allowance of
       $303,000 and $554,000, respectively                   13,020,000                 17,680,000
    Accounts receivable-related party                                 -                    300,000
    Prepaid and other                                         1,459,000                    907,000
                                                      -----------------           ----------------
       Total current assets                                  23,792,000                 21,765,000
                                                      -----------------           ----------------

 OIL AND GAS PROPERTIES, AS DETERMINED BY THE
 SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
    Oil and gas properties, proved                          279,257,000                289,892,000
    Less proved property accumulated depletion,
       depreciation and amortization                       (174,081,000)              (193,135,000)
    Net unproved oil and gas properties                       1,944,000                  2,888,000
                                                      -----------------           ----------------
       Net oil and gas properties                           107,120,000                 99,645,000
                                                      -----------------           ----------------
 PIPELINES AND EQUIPMENT
    Pipelines and equipment                                  26,535,000                 26,409,000
    Less accumulated depreciation                           (10,252,000)                (8,256,000)
                                                      -----------------           ----------------
       Net pipelines and equipment                           16,283,000                 18,153,000
                                                      -----------------           ----------------
 HER ASSETS
    Restricted deposits                                      10,460,000                  8,625,000
    Deferred debt costs, net                                  1,664,000                  3,128,000
    Deferred income taxes                                             -                 22,763,000
                                                      -----------------           ----------------
       Total other assets                                    12,124,000                 34,516,000
                                                      -----------------           ----------------

 TOTAL ASSETS                                          $    159,319,000            $   174,079,000
                                                      =================           ================

                                                                                     (continued)

</TABLE>


         The accompanying notes are an integral part of this statement.

                                       2

<PAGE>
                                  PANACO, Inc.
                            Condensed Balance Sheets


                 LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)

<TABLE>
<CAPTION>

                                                               As of                      As of
                                                        September 30, 2001          December 31, 2000
                                                      ---------------------         -----------------
CURRENT LIABILITIES                                          (Unaudited)
<S>                                                             <C>                         <C>
    Accounts payable and accrued liabilities             $   33,277,000              $   31,963,000
    Interest payable                                          5,480,000                   2,917,000
    Gas imbalance payable                                       979,000                   2,860,000
    Restricted cash payable                                           -                     629,000
    Deferred income taxes                                             -                           -
                                                         --------------              --------------
      Total current liabilities                              39,736,000                  38,369,000
                                                         --------------              --------------

DEFERRED CREDITS                                              1,646,000                   1,609,000

LONG-TERM DEBT                                              128,345,000                 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                                       (82,549,000)                (56,815,000)
  Accumulated other comprehensive income                      2,805,000                           -
                                                         --------------              --------------
     Total stockholders' equity (deficit)                   (10,408,000)                 12,408,000
                                                         --------------              --------------


 TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY              $  159,319,000              $  174,079,000
                                                         ==============              ==============
</TABLE>


         The accompanying notes are an integral part of this statement.

                                       3

<PAGE>
                                  PANACO, Inc.
                            Statements of Operations
                     For the Nine Months Ended September 30,
                                   (Unaudited)

 <TABLE>
<CAPTION>
                                                              2001                 2000
                                                          -----------           ----------
<S>                                                           <C>                  <C>

 REVENUES
   Oil and natural gas sales                             $ 63,058,000          $ 61,811,000
   Gain on property sales                                   3,967,000                     -
   Lawsuit recovery                                                 -               990,000
                                                         ------------          ------------
     Total                                                 67,025,000            62,801,000

 COSTS AND EXPENSES
   Lease operating expense                                 20,454,000            16,359,000
   Depletion, depreciation & amortization                  24,153,000            20,227,000
   General and administrative expense                       3,356,000             3,474,000
   Production and ad valorem taxes                          1,284,000             1,454,000
   Exploratory dry hole expense                             4,590,000               794,000
   Geological and geophysical expense                         785,000             1,171,000
   Severance expense                                                -               746,000
   Impairment of oil and gas properties                     6,874,000                     -
                                                         ------------          ------------
     Total                                                 61,496,000            44,225,000
                                                         ------------          ------------

 OPERATING INCOME                                           5,529,000            18,576,000

 OTHER INCOME (EXPENSE)
   Interest income                                            522,000               113,000
   Interest expense                                        (9,696,000)          (11,689,000)
   Other income                                               798,000                     -
                                                         ------------          ------------
     Total                                                 (8,376,000)          (11,576,000)
                                                         ------------          ------------

 INCOME (LOSS) BEFORE INCOME TAXES                         (2,847,000)            7,000,000

 INCOME TAX EXPENSE (BENEFIT)                              22,887,000           (26,317,000)
                                                         ------------          ------------

 NET INCOME (LOSS)                                       $(25,734,000)         $ 33,317,000
                                                         ============          ============

 BASIC AND DILUTED NET INCOME (LOSS) PER SHARE           $      (1.06)         $       1.37
                                                         ============          ============

 Basic Shares Outstanding                                  24,346,444            24,241,116
                                                         ============          ============
 Diluted Shares Outstanding                                24,346,444            24,241,116
                                                         ============          ============
</TABLE>


         The accompanying notes are an integral part of this statement.

                                       4

<PAGE>
                                  PANACO, Inc.
                      Consolidated Statements of Operations
                    For the Three Months Ended September 30,
                                   (Unaudited)

<TABLE>
<CAPTION>
                                                           2001                     2000
                                                        ----------               ----------
<S>                                                         <C>                   <C>
 REVENUES
   Oil and natural gas sales                          $ 16,685,000             $ 24,911,000

 COSTS AND EXPENSES
   Lease operating expense                               7,540,000                6,283,000
   Depletion, depreciation & amortization                8,811,000                7,769,000
   General and administrative expense                      920,000                1,174,000
   Production and ad valorem taxes                         394,000                  489,000
   Exploratory dry hole expense                                  -                  347,000
   Geological and geophysical expense                      186,000                  319,000
   Severance expense                                             -                  746,000
   Impairment of oil and gas properties                    332,000                        -
                                                      ------------             ------------
       Total                                            18,183,000               17,127,000
                                                      ------------             ------------

 OPERATING INCOME (LOSS)                                (1,498,000)               7,784,000

 OTHER INCOME (EXPENSE)
   Interest income                                         220,000                   39,000
   Interest expense                                     (3,237,000)              (3,853,000)
   Other income                                            142,000                        -
                                                      ------------             ------------
       Total                                            (2,875,000)              (3,814,000)
                                                      ------------             -------------

 INCOME (LOSS) BEFORE INCOME TAXES                      (4,373,000)               3,970,000

 INCOME TAX EXPENSE (BENEFIT)                           22,235,000                1,508,000
                                                      ------------             ------------

 NET INCOME (LOSS)                                    $(26,608,000)             $ 2,462,000
                                                      ============             ============

 BASIC AND DILUTED NET INCOME (LOSS) PER SHARE        $      (1.10)                  $ 0.10
                                                      =============            ============

 Basic Shares Outstanding                                24,359,695              24,323,521
                                                      =============            ============
 Diluted Shares Outstanding                              24,359,695              24,323,521
                                                      =============            ============
</TABLE>


         The accompanying notes are an integral part of this statement.

                                       5

<PAGE>
                                  PANACO, Inc.
                             Statement of Cash Flows
                     For the Nine Months Ended September 30,
                                   (Unaudited)

<TABLE>
<CAPTION>
                                                                         2001                2000
                                                                      ----------          ----------
<S>                                                                      <C>                  <C>
 CASH FLOWS FROM OPERATING ACTIVITIES
   Net income (loss)                                                $(25,734,000)       $ 33,317,000
   Adjustments to reconcile net income to net cash
   provided by operating activities:
     Deferred income taxes                                            22,763,000         (26,317,000)
     Depletion, depreciation and amortization                         24,152,000          20,227,000
     Impairment of oil and gas properties                              6,874,000                   -
     Exploratory dry hole expense                                      4,590,000             794,000
     Gain on property sales                                           (3,967,000)                  -
     Plug and abandoning of wells and platforms                       (5,203,000)                  -
     Changes in assets and liabilities:
        Accounts receivable                                            8,504,000          (7,546,000)
        Accounts payable                                               2,152,000           8,210,000
        Gas imbalance payable                                           (518,000)          1,581,000
        Deferred credits                                                  37,000           1,697,000
        Interest payable                                               2,563,000           2,570,000
        Accounts receivable-related party                                300,000                   -
        Changes relating to derivative instruments                    (1,071,000)                  -
        Prepaid and other                                             (1,068,000)           (488,000)
                                                                    ------------        ------------
                   Net cash provided by operating activities          34,374,000          34,045,000
                                                                    ------------        ------------

 CASH FLOWS FROM INVESTING ACTIVITIES
      Proceeds from the sale of oil and gas properties                 2,843,000                   -
      Capital expenditures and acquisitions                          (35,529,000)        (22,009,000)
      Increase in restricted deposits                                 (1,835,000)         (1,518,000)
                                                                    ------------        ------------
                   Net cash used in investing activities             (34,521,000)        (23,527,000)
                                                                    ------------        ------------

 CASH FLOWS FROM FINANCING ACTIVITIES
      Long-term debt borrowings                                       17,993,000          11,415,000
      Repayment of long-term debt                                    (11,341,000)        (25,000,000)
      Additional deferred financing costs                                (70,000)           (354,000)
                                                                    ------------        ------------
                   Net cash used in financing activities               6,582,000         (13,939,000)
                                                                    ------------        ------------

 NET INCREASE (DECREASE) IN CASH                                       6,435,000          (3,421,000)

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

 CASH AT SEPTEMBER 30                                                $ 9,313,000         $ 2,154,000
                                                                    ============        ============
</TABLE>


         The accompanying notes are an integral part of this statement.

                                       6

<PAGE>


                                  PANACO, Inc.
                     NOTES TO CONDENSED FINANCIAL STATEMENTS
                                   (Unaudited)

Note 1 - BASIS OF PRESENTATION

     In  the  opinion  of  management,   the  accompanying  unaudited  condensed
financial  statements  contain all  adjustments  necessary to present fairly the
Company's  financial position as of September 30, 2001 and December 31, 2000 and
the results of its operations and cash flows for the periods ended September 30,
2001 and  2000.  Most  adjustments  made to the  financial  statements  are of a
normal, recurring nature. Although the Company believes that the disclosures are
adequate to make the information  presented not misleading,  certain information
and footnote disclosures,  including significant  accounting policies,  normally
included in financial  statements prepared in accordance with generally accepted
accounting  principles have been condensed or omitted  pursuant to the rules and
regulations  of the  Securities  and Exchange  Commission  (the  "SEC").  A more
complete  description of the accounting policies followed by the Company are set
forth in Note 1 to the Company's financial  statements in Form 10-K for the year
ended  December  31,  2000.  These  financial   statements  should  be  read  in
conjunction with the financial statements and notes included in the Form 10-K.

     The Company restated its financial  results for the first three quarters of
2000. The adjustments reflect an increase in the Company's gas imbalance payable
and  associated  reduction  of revenues in the  quarters to which the  imbalance
relates. The changes reflect adjustments to natural gas production and revenues,
depletion,  income before income taxes and net income.  The  adjustments  to the
first nine months of 2000 revenues, depletion, depreciation and amortization and
net income were  $(1,688,000),  $(387,000)  and  $(808,000),  respectively.  The
adjustments to the third quarter of 2000 revenues,  depletion,  depreciation and
amortization  and net  income  were  $(1,007,000),  $(293,000)  and  $(444,000),
respectively.

Note 2 - OIL AND GAS PROPERTIES AND PIPELINES AND EQUIPMENT

     The Company  utilizes the  successful  efforts method of accounting for its
oil and gas properties.  Under the successful efforts method,  lease acquisition
costs are initially capitalized. Exploratory drilling costs are also capitalized
pending determination of proved reserves. If proved reserves are not discovered,
the  exploratory  costs are expensed.  All  development  costs are  capitalized.
Non-drilling  exploratory costs,  including geological and geophysical costs and
rentals,  are expensed.  Unproved leaseholds with significant  acquisition costs
are  assessed  periodically,  on a  property-by-property  basis,  and a loss  is
recognized  to the  extent,  if any,  that  the  cost of the  property  has been
impaired.  Unproved  leaseholds  whose  acquisition  costs are not  individually
significant  are  aggregated,  and  the  portion  of  such  costs  estimated  to
ultimately  prove  nonproductive,  based on  experience,  are amortized  over an
average holding period. As unproved  leaseholds are determined to be productive,
the related costs are transferred to proved leaseholds.  Provision for depletion
is determined on a depletable  unit basis using the  unit-of-production  method.
Estimated future  abandonment  costs are recorded by charges to depreciation and
depletion expense over the lives of the proved reserves of the properties.

     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.


                                       7

<PAGE>



                                  PANACO, Inc.
                     NOTES TO CONDENSED FINANCIAL STATEMENTS
                                   (Unaudited)

     The Company  recognized asset  impairments  during the first nine months of
2001  totaling $6.9  million,  relating to both proved and unproved  properties.
Based on the  decision  by the  Company  to  discontinue  development  of proved
reserves, discovered in 1998, the Company recorded an impairment of $1.1 million
for the capital incurred in initially  discovering those reserves.  In addition,
in connection with the Company's regular review of the  recoverability of proved
reserves  carrying  values,  an impairment of $5.8 million was recorded based on
reserve and price reductions for several  properties which the Company considers
non-core.

     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.

     During the second  quarter of 2001,  the Company  sold its  interest in the
High  Island  309  and  310  Fields  to  the  operator  of  the  property.   The
consideration received by the Company included cash, before adjustment,  of $3.8
million  and the  forgiveness  of a $1.4  million gas  imbalance  payable by the
Company.  The sale closed on June 29, 2001 and the proceeds  from the buyer were
adjusted  to the  effective  date of the sale,  January 1, 2001,  and reduced by
amounts  owed by the  Company to the buyer.  Both the Company and the buyer also
agreed to dismiss  lawsuits filed by each party against the other as part of the
purchase and sale agreement.  The sale resulted in a gain of $4.0 million during
the second quarter of 2001.

Note 3 - CASH FLOW INFORMATION

     Cash  payments for  interest  totaled $7.2 million and $9.3 million for the
first nine months of 2001 and 2000, respectively. Cash payments for income taxes
totaled  $26,000  and  $50,000  for the  first  nine  months  of 2001 and  2000,
respectively.

Note 4 - EARNINGS PER SHARE CALCULATIONS

     Basic and diluted earnings per share for the first nine months of each year
were based on the year-to-date  weighted average share outstanding of 24,346,444
in 2001 and 24,241,116  for 2000.  The Company did have potential  common shares
outstanding  during 2001 in the form of stock  options,  however,  the potential
common  shares are  excluded  from the diluted  earnings  per share  calculation
because the  Company  had a net loss for both the nine months and quarter  ended
September   30,  2001  and  the   potential   common   shares  would  have  been
anti-dilutive.  The Company  also had stock  options  outstanding  during  2000,
however,  these stock  options  were out of the money during the period prior to
their expiration in June 2000.

Note 5 - 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.


                                       8

<PAGE>


                                  PANACO, Inc.
                     NOTES TO CONDENSED FINANCIAL STATEMENTS
                                   (Unaudited)

     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 $5.2  million at
September 30, 2001 and requires  quarterly deposits of $375,000 until June 2003,
decreasing to $125,000 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 $4.6 million at September 30, 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 September 30, 2001.

Note 6 - COMMITMENTS AND CONTINGENCIES

     An action was filed  against  the  Company in  Louisiana,  along with Exxon
Pipeline Company ("Exxon"), National Energy Group, Inc. ("NEG"), Mendoza Marine,
Inc., Shell Western Exploration & Production,  Inc. ("Shell"), and the Louisiana
Department of Transportation  and Development.  The petition was filed in August
1998, and alleges that, in 1997 and perhaps  earlier,  leaks from a buried crude
oil pipeline contaminated the plaintiffs' property. Pursuant to the purchase and
sale agreement  between PANACO and NEG, NEG is required to indemnify the Company
from any damages  attributable  to NEG's  operations  on the property  after the
sale.

     Pursuant  to another  purchase  and sale  agreement,  the  Company  may owe
indemnity  to Shell and Exxon,  from whom the  property  was  acquired  prior to
selling same to NEG. The Company believes that it has insurance coverage for the
claims  asserted in the petition,  and has notified all insurance  carriers that
might  provide  coverage  under  its  policies.  In 1999 NEG  filed  chapter  11
bankruptcy  and emerged in late 2000.  Some  discovery has occurred in the case,
but is not yet complete. Therefore, at this point it is not possible to evaluate
the likelihood of an unfavorable  outcome, or to estimate the amount or range of
potential loss.

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

Note 7 - LONG-TERM DEBT

     The Company maintains a Credit Facility that is a reducing,  revolving loan
and is  collateralized  by a first  mortgage on the  Company's  properties.  The
amount  available to the Company  under the Credit  Facility is  determined by a
borrowing base typically  based on the estimated  value of the properties  under
mortgage to the lender, less any amounts borrowed under the Credit Facility.  In
October 1999 the Company put in place a new, $60 million  Credit  Facility  with
Foothill Capital Corp.  ("Foothill") as the Agent for the lenders.  The Foothill
facility had an initial term of two years with two six-month  extension  options
available  at the sole  option of the  Company.  The  borrowing  base  under the
Foothill facility at the expiration of the initial term was $60 million.


                                       9

<PAGE>


                                  PANACO, Inc.
                     NOTES TO CONDENSED FINANCIAL STATEMENTS
                                   (Unaudited)

     In November 2001, the Company amended the Foothill facility to, among other
changes,  extend the  expiration  date an additional  two years.  The new Credit
Facility is a $40 million  facility  with a borrowing  base of $40  million.  At
September 30, 2001,  $26.1  million was  outstanding  under the  facility,  with
availability of $12.7 million, of which $1.3 million was reserved under a letter
of credit.  The borrowing base is subject to monthly  determinations  made using
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  amendment  also reduced the interest  rates,  administrative  fees and
servicing  fees charged the  Company.  Interest on the loan is computed at Wells
Fargo's  prime rate plus 0.25% to 0.75% or LIBOR plus 2.25% to 2.75%,  depending
on the  percentage  of the  facility  being used and the  pricing  option is the
choice of the Company.  The loan agreement contains certain covenants  including
an EBITDA (as defined in the  agreement)  to interest  expense ratio of at least
2.0 to 1.0 and a working capital ratio (as defined in the agreement) of at least
 .25 to 1.0. The loan  agreement also contains  limitations  on additional  debt,
dividends, mergers and sales of assets.

Note 8 - INCOME TAXES

     During the second quarter of 2000, the Company  determined that it was more
likely than not that its deferred tax assets would be realized.  This  valuation
was based on several factors, including estimates for future oil and natural gas
prices.  Projections of future taxable income were  sufficient to utilize all of
the deferred tax assets due to higher  commodity  prices and reserve  additions,
therefore the valuation allowance was removed.  The Company performs a review of
the deferred tax asset  including the associated  utilization  estimates for the
asset. The factors considered in the review include historical utilization,  tax
planning  strategies that may improve the  utilization and market  conditions at
the time of review.  The Company has and is  continuing to evaluate tax planning
strategies  for utilizing  its deferred tax asset  including the sale of assets,
when appropriate.

     Based  on its  review  during  the  third  quarter  of  2001,  the  Company
determined  that it was more likely than not that its  deferred  tax asset would
not be utilized and reestablished a valuation allowance against the deferred tax
asset. This valuation was due to, among other factors,  the significant decrease
in oil and  natural  gas prices and reduced  reserve  estimates  from the second
quarter  of 2000,  losses  in the  prior  years,  excluding  2000,  and  current
estimates of results for 2001.  These  projections  of future taxable income are
management's  best  estimates,  using current  reserve  estimates,  estimates of
future commodity prices and other  information  currently  available.  While the
Company believes that the assumptions used in these  projections are reasonable,
future  events,  including  changes  in  commodity  prices,  could  result  in a
reduction in some or all of the deferred tax asset valuation allowance in future
periods.

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
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


                                       10

<PAGE>



                                  PANACO, Inc.
                     NOTES TO CONDENSED FINANCIAL STATEMENTS
                                   (Unaudited)

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.

     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.

     The Company  periodically enters into derivative  commodity  instruments to
hedge its exposure to price fluctuation on natural gas and crude oil production.
At September 30, 2001, the Company had one derivative instrument outstanding,  a
natural  gas swap.  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. For the period of October
1 through December 31, 2001 the Company's average price for its natural gas swap
is $4.56 per MMBtu.

     The Company  recognized a $0.3 million increase in earnings,  pre-tax,  for
the  cumulative  effect of adopting SFAS 133 on January 1, 2001 and for the nine
months ended September 30, 2001 the Company  recognized a $0.3 million  decrease
in earnings, pre-tax, related to the decrease in the value of the put option.

     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.  During the first nine months of 2001,
the Company realized pre-tax income of $0.1 million on hedging activity incurred
in the first nine months 2001, which were  transferred from Other  Comprehensive
Income/Loss to natural gas revenues for the production months the hedge related.
The Company also  recognized  Other  Income of $1.1  million,  pre-tax,  for the
ineffective  portion of the natural gas swap. At September 30, 2001 $2.8 million
of deferred net gains on derivative  instruments recorded in Other Comprehensive
Income/Loss  are expected to be  reclassified to earnings during the next twelve
months.

     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


                                       11

<PAGE>


                                  PANACO, Inc.
                     NOTES TO CONDENSED FINANCIAL STATEMENTS
                                   (Unaudited)

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.

Note 10 - COMPREHENSIVE INCOME

     Comprehensive  income  includes  net  income  and  certain  items  recorded
directly  to   shareholders'   equity  and  classified  as   Accumulated   Other
Comprehensive  Loss.  The Company  recorded Other  Comprehensive  Income for the
first time in the first  quarter of 2001.  On January 1, 2001,  upon adoption of
SFAS 133, the Company recorded a charge to Accumulated Other  Comprehensive Loss
of $9.9  million  for the fair  value of the  Company's  cash flow  hedges.  The
following table illustrates the calculation of comprehensive income for the nine
months ended September 30, 2001:

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

     Accumulated Other Comprehensive Income (Loss), December 31, 2000                  $         --

     Net Loss                                                                           (25,734,000)

     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                        13,862,000
           Financial derivative settlements transferred from
                    Accumulated Other Comprehensive Income                               (1,176,000)
                                                                                       ------------

     Accumulated Other Comprehensive Income                                               2,805,000
                                                                                       ------------

     Comprehensive Income (Loss)                                                       $(22,929,000)
                                                                                       ============

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

</TABLE>


                                       12

<PAGE>


PART I
Item 2.
                           MANAGEMENT'S DISCUSSION AND
                         ANALYSIS OF FINANCIAL CONDITION
                            AND RESULTS OF OPERATIONS

Forward-looking Statements

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

General

     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

     In  implementing  our business  strategy of  increasing  our reserve  base,
increasing cash flows from operations and to reduce debt, we reinvest cash flows
from operations as capital expenditures or to reduce debt. During the first nine
months of 2001, net cash provided by operating activities totaled $34.3 million,
which,  along with cash on hand, was used to fund capital  expenditures,  net of
property sales, of $32.6 million and for required  restricted  deposit increases
of $1.8 million.  Net capital  expenditures  of $32.6 million for the first nine
months of 2001  represents a 48% increase  over  capital  expenditures  totaling
$22.0 million for the comparable period of 2000. For the year 2001, our Board of
Directors has approved a $45 million capital budget.  We believe that cash flows
from operations and availability  under our Credit Facility will fund this level
of capital expenditures.

     In an attempt to reduce  interest  costs, we keep as little cash on hand as
possible and apply available cash to our Credit Facility balance.  The timing of
receipt of monies due us and the payment of amounts due others also  affects our
working capital.  These two factors cause us to typically have a working capital
deficit.  On  September  30, 2001 this working  capital  deficit  totaled  $15.9
million.  We believe that cash flows from operations and borrowing  availability
under our  Credit  Facility  will be  sufficient  to fund this  working  capital
deficit in addition to ongoing operations and capital expenditures.

Credit Facility

     The primary source of capital beyond discretionary cash flows is our Credit
Facility.  The 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 and  for  acquiring  additional  oil  and  natural  gas


                                       13

<PAGE>

reserves.  We may also use the Credit Facility for working capital  support,  to
provide letters of credit and general corporate purposes.

     In October 1999 we put in place a $60 million Credit Facility with Foothill
Capital Corp.  ("Foothill") as the Agent for the lenders.  The Foothill facility
had an initial term of two years with two six-month  extension options available
at the sole  option of the  Company.  The  borrowing  base  under  the  Foothill
facility at the expiration of the initial term was $60 million.

     In November 2001, we amended the Foothill facility to, among other changes,
extend the expiration date an additional two years. The new Foothill facility is
a $40 million facility with a borrowing base of $40 million.  The borrowing base
is subject to monthly  determinations made using 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. At
September 30, 2001,  $26.1  million was  outstanding  under the  facility,  with
availability of $12.7 million, of which $1.3 million was reserved under a letter
of credit.  The reduction in the Credit Facility was part of management's  focus
on  controlling  costs and reduces the amount of unused line fees charged by the
lender.  Management  believes  that the $40 million  provides the  liquidity and
flexibility needed to continue its capital expenditure program and implement our
business strategy.

     The  amendment  also reduced the interest  rates,  administrative  fees and
servicing  fees charged the  Company.  Interest on the loan is computed at Wells
Fargo's  prime rate plus 0.25% to 0.75% or LIBOR plus 2.25% to 2.75%,  depending
on the  percentage  of the  facility  being used and the  pricing  option is the
choice of the Company.  The loan agreement contains certain covenants  including
an EBITDA (as defined in the  agreement)  to interest  expense ratio of at least
2.0 to 1.0 and a working capital ratio (as defined in the agreement) of at least
 .25 to 1.0. The loan  agreement also contains  limitations  on additional  debt,
dividends,  mergers and sales of assets. We were in compliance with the terms of
the Foothill facility on September 30, 2001 and anticipate compliance throughout
the term of the loan.

Senior Note offering

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

Commodity price hedges

     We follow a hedging strategy designed to protect against the possibility of
severe  price  declines  due to  market  volatility.  We may also  make  hedging
decisions to assure a payout of a specific acquisition or development project.

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


                                       14

<PAGE>


     The Company also purchased an option to put oil to a purchaser at an agreed
upon price.  The put option was for 1,000  barrels of oil per day from January 1
through September 30 at a NYMEX price of $25.00 per barrel.  The cost of the put
option was $1.00 per barrel, or $365,000.

     At September 30, 2001 the fair value of the remaining  hedges was a gain of
$3.9 million, pre-tax.

     The fair value of commodity  hedging  instruments  is the estimated  amount
that  we  would  receive  or pay to  settle  the  applicable  commodity  hedging
instrument at the reporting  date,  taking into account the  difference  between
NYMEX prices or index prices at year-end and the contract price of the commodity
hedging instrument. 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 SFAS 133, all derivative instruments are recorded on the balance
sheet at fair value. See Note 9 to the Company's Condensed Financial  Statements
for a discussion of activities involving derivative financial instruments during
the first nine months of 2001.

     We produce and sell natural gas, oil and natural gas liquids.  As a result,
our financial results are  significantly  affected by changes in these commodity
prices. We use derivative financial instruments to attempt to hedge our exposure
to changes in the market price of natural gas and oil. While commodity financial
instruments  are intended to reduce exposure to declines in these market prices,
the commodity  financial  instruments may also limit gains from increases in the
market price of natural gas and oil.

Capital expenditures

     Net capital expenditures totaled $32.6 million for the first nine months of
2001, representing a 48% increase over the $22.0 million of capital expenditures
incurred in the comparable period of 2000. The capital expenditures  incurred in
2001  were  concentrated  primarily  in four  fields in the Gulf of  Mexico,  as
follows.

     In late June 2000,  we began a  development  program in the East Breaks 109
and 110 Fields,  with the aid of 3-D  seismic,  which we purchased in late 1998.
These Fields are in  approximately  700 feet of water in the Gulf of Mexico.  We
own a 100%  working  interest in these Fields and are the  operator.  During the
first nine  months of 2001 we spent $14.1  million in  continuing  the  drilling
program in these  Fields,  $3.8  million of which  related to the #A-4 well,  an
exploratory  well that was not completed and  accounted for as  exploratory  dry
hole  expense.  The remaining  capital was primarily  incurred on the #A-13 well
which was completed and began production during the second quarter,  in addition
to the #A-7 well, which was completed and began production in late January 2001.

     On April  13,  2001  PANACO  acquired  100% of West  Delta  Block 52 for $4
million,  before  purchase  price  adjustments  to  the  effective  date  of the
acquisition, January 1, 2001. The acquisition included approximately 1.1 million
barrels of proved  reserves and is contiguous to our existing West Delta Fields.
During the second  quarter we spent  $3.2  million in capital  expenditures,  in
addition to the  acquisition  cost,  primarily for the  completion of previously
shut-in wells to new gas zones.

     PANACO also incurred capital expenditures totaling $9.1 million in the East
Breaks 205 and 161 Fields  during  the first nine  months of 2001.  We own a 25%
working  interest  in the first  well,  the East  Breaks 205 #1 well,  which was
drilled and completed during the second quarter.  The #1 well, which is operated
by Unocal,  was successful and is expected to begin production during the fourth
quarter of 2001. The Block 161 #2 well was spudded during the second quarter and
completed during the third quarter of 2001. This well was also successful and is
expected to begin production during the fourth quarter of 2001. PANACO also owns
a 25% working interest in the Block 161 #2 well.


                                       15

<PAGE>


     During  the third  quarter of 2001,  we spudded a new well in the  Umbrella
Point Field,  the State Tract 76 #3 well in which we own a 40% working  interest
and are the operator.  The State Tract 76 #3 well is an  exploratory  well which
will test the prolific Deep Vicksburg  formation at  approximately  15,700 feet.
Based  on  current  estimates,  our net  dry  hole  exposure  for  this  well is
approximately  $3  million.  Through  September  30, 2001 we had  incurred  $2.0
million in net costs in drilling this well.  The costs are  capitalized  pending
determination of proved reserves once the well has reached the targeted depths.

     The  remaining  capital  expenditures  were  incurred  primarily on several
properties in which we own smaller interests.

Results of Operations

For the nine months ended September 30, 2001 and 2000:

     One of the most  significant  factors  affecting our business is the market
price  of oil and  natural  gas  that we  produce  and  sell.  In late  1997 and
continuing  through early 1999,  both oil and natural gas prices were lower than
they had been in the proceeding years. A turnaround was seen in 1999 and through
the first quarter of 2001 where we benefited from a steady  increase in realized
prices for both oil and natural gas. Since March 2001,  both oil and natural gas
prices have decreased from their highs earlier in 2001.

Revenues

     Oil and  natural  gas sales  totaled  $63.1  million  during the first nine
months of 2001,  an increase of $1.2  million,  or 2% when compared to the first
nine  months of 2000.  While both oil and natural gas  production  decreased  in
2001,  improved  natural  gas  prices  have  offset  lower oil  prices and lower
production.

Production and Prices:
<TABLE>
<CAPTION>

                                                                                        % Increase
                                                  2001                2000              (Decrease)
                                                  ----                ----              ----------
<S>                                               <C>                  <C>                  <C>


      Natural gas production (MMcf)               8,595              10,299                (17%)
      Average price per Mcf
       excluding hedging                       $   5.12            $   3.71                 38%
      Average price per Mcf
       including hedging                       $   5.13            $   3.68                 39%

      Oil Production (MBbl)                         698                 818                (15%)
      Average price per Bbl
       excluding hedging                       $  27.16            $  29.78                 (9%)
      Average price per Bbl
       including hedging                       $  27.16            $  29.23                 (7%)

</TABLE>

     Both oil and natural gas production decreased when comparing the first nine
months of 2001 to the comparable period of 2000.

     The most  significant  decreases  in  natural  gas  production  were in the
Umbrella  Point Field (1,769  MMcf),  East Breaks 160 and 161 Fields (898 MMcf )
and the East Breaks 165 Field (651 MMcf),  which were due  primarily  to natural
declines in the production from those fields. In addition,  naturally  declining
production  and the sale of the High Island 309 and 310 Fields (808 MMcf) during
the second  quarter  of 2001  contributed  to the  decreased  production.  Those
declines were somewhat offset by increases in the East Breaks 109 and 110 Fields


                                       16

<PAGE>

(2,192 MMcf) and the West Delta Fields (923 MMcf), a focal point for part of our
2001 capital expenditure program.

     Likewise,  oil production has decreased from the East Breaks 165 Field (124
Mbbl)  and East  Breaks  160 and 161  Fields  (47  Mbbl)  due to  lower  capital
expenditures in those fields and the rapid production declines from the wells in
those fields,  which are inherent in the areas that we operate.  The bulk of the
capital  expenditures  in 2001 are for projects that should produce natural gas,
rather than oil.

     We also recognized a gain of $4.0 million on the sale of an oil and natural
gas property during the second quarter of 2001. We sold PANACO's entire interest
in High Island  Blocks 309 and 310 to the  operator of the fields for cash,  the
assumption  of a gas  imbalance  liability  and the  dismissal  of a lawsuit the
operator had filed against us for non-payment of invoices. The property sale was
completed on June 29, 2001.

Cost and Expenses

     Lease operating expenses increased $4.1 million,  to $20.5 million,  during
the first nine  months of 2001  compared  to $16.4  million  in 2000.  On an Mcf
equivalent  ("Mcfe") basis,  lease operating expenses also increased to $1.60 in
2001 from $1.08 in 2000.  During  2001,  we have spent a  significant  amount of
capital for repairs and maintenance of PANACO's offshore  platforms,  which, due
to the nature of the work, are expensed as incurred.  Some of these expenses are
required  by the  regulatory  agencies  in the Gulf of  Mexico.  We expect  this
program to continue throughout 2001, specifically in the East Breaks area of the
Gulf of Mexico, where we own 3 platforms. Total repair and workover expenses for
the first nine months of 2001 was $7.6 million,  compared to $5.2 million during
2000.  These  projects  include  production  equipment  repairs and  workover or
cleanout of  productive  zones in well bores.  Excluding  these  amounts,  lease
operating  expenses  per Mcfe were $1.01 and $0.73 for the first nine  months of
2001 and 2000, respectively.

     Depletion,  depreciation and amortization  ("DD&A")  increased 19%, or $3.9
million  primarily due to a 42% increase in DD&A per unit of  production,  which
was offset by a 16%  decrease  in total  production.  The  higher  cost per unit
relates  primarily  to an increase in the cost per Mcfe of  production  from the
East  Breaks  109 and 110  Fields  along with  increased  production  from those
Fields.

     Exploratory dry hole expense increased to $4.6 million primarily due to the
unsuccessful  #A-4 well  drilled  during  the first  quarter of 2001 in the East
Breaks 109 and 110 Fields.

     Geological and geophysical  expense decreased $0.4 million primarily due to
3-D  Seismic  purchases  and land  rentals  incurred  during  2000 that were not
included in 2001 spending.

     During the second and third quarters of 2001, PANACO recognized impairments
for both  proved and  unproved  oil and  natural gas  properties.  The  unproved
property  impairment was based on our decision to not further develop  potential
reserves based on the significant  capital required to develop the field and the
low potential to be realized  based on numerous  evaluations  made by PANACO and
other partners in the field. Also, due to reductions in future reserve estimates
by our third party engineers, and the resulting lower future net cash flows from
certain fields, we were required to impair non-core proved properties.

     Interest  expense  decreased  $2.0  million due to lower  weighted  average
borrowing  levels during 2001 in addition to lower  interest rate for our Credit
Facility, which is based on the prime rate.

     Other income  increased $0.8 million and is made up of the adoption of SFAS
No. 133,  including a gain on the ineffective  portion of a natural gas swap and
the mark-to-market of an option to put oil to a purchaser.


                                       17

<PAGE>


Income Tax Expense (Benefit)

     As oil and  natural  gas  prices  increased  during  2000,  we were able to
project  future  taxable  income  sufficient to utilize our net  operating  loss
carry-forwards. As such, during the second quarter of 2000 we recorded an income
tax benefit of $29 million by reversing a valuation  allowance  recorded against
these assets.  From that point forward until the second quarter of 2001,  income
tax expense has been  recognized,  at the  effective  rate,  as a percentage  of
pre-tax income.

     The analysis of the deferred tax asset  utilization  made during the second
quarter of 2000  determined  that it was more likely than not that the  deferred
tax assets would be realized.  This  determination was based on several factors,
including  current  projections  of future  taxable  income.  This analysis also
included current  estimates for future oil and natural gas prices in addition to
recent reserve  additions.  Projections of future taxable income were sufficient
to utilize all of the  deferred  tax assets due to higher  commodity  prices and
reserve  additions,  therefore  the valuation  allowance  was removed.  With the
decrease in oil and natural  gas prices and reserve  estimates  since the second
quarter of 2000,  management's  estimates of future taxable income had decreased
to a point in which it was more  likely than not that none of its  deferred  tax
asset would be utilized. Based on this analysis and all other evidence available
at the time, the valuation allowance was reestablished  against the deferred tax
asset.

     These projections of future taxable income are management's best estimates,
using current reserve estimates,  estimates of future commodity prices and other
information  currently available.  While we believe that the assumptions used in
these projections are reasonable,  future events, including changes in commodity
prices,  could  result in a reduction  in some or all of the  deferred tax asset
valuation  allowance  in future  periods.  PANACO also  evaluates  tax  planning
strategies and utilizes them when available in order to utilize our deferred tax
assets and  minimize  income  taxes.  During 2001 this  evaluation  included the
potential  sales of assets which would have resulted in significant  gains which
would  have been  offset  by the  deferred  tax  asset.  While  there is no sale
imminent, we are continually evaluating our options.

Net Income (Loss)

     Although  total  revenues  increased  7%,  to  $67.0  million,  a  property
impairment of $6.9 million,  an increase in exploratory dry hole expense of $3.8
million and the  increase  in the  deferred  tax  valuation  allowance  of $22.9
million  during  2001  along with an income  tax net  benefit  of $26.3  million
recognized  during 2000, were the primary factors in a decrease of $59.1 million
in net income and a $2.43 per share decrease in net income per share.


                                       18

<PAGE>

Results of Operations

For the three months ended September 30, 2001 and 2000:

Revenues

     Oil and natural gas sales totaled $16.7 million during the third quarter of
2001, a decrease of $8.2 million,  or 33%, when compared to the third quarter of
2000.

Production and Prices:
<TABLE>
<CAPTION>

                                                                                    % Increase
                                                  2001              2000           (Decrease)
                                                  ----              ----           -----------
<S>                                               <C>               <C>                <C>

     Natural gas production (MMcf)                2,576             3,635               (29%)
     Average price per Mcf
      excluding hedging                         $  2.95           $  4.53               (35%)
     Average price per Mcf
      including hedging                         $  3.93           $  4.51               (13%)

     Oil Production (MBbl)                          249               277               (10%)
     Average price per Bbl
      excluding hedging                         $ 26.43           $ 31.45               (16%)
     Average price per Bbl
      including hedging                         $ 26.43           $ 30.81               (14%)

</TABLE>

     Both oil and natural gas  production  decreased  when  comparing  the third
quarter of 2001 to the comparable period of 2000.

     The most  significant  decreases  in  natural  gas  production  were in the
Umbrella Point Field (630 MMcf), the Price Lake Field (320 MMcf) East Breaks 160
and 161  Fields  (316 MMcf ) and the East  Breaks  165 Field (252 MMcf) were due
primarily to natural  declines in the respective  production  from those fields.
Those declines were somewhat  offset by increases in the East Breaks 109 and 110
Fields (849 MMcf) and the West Delta Fields (179 MMcf),  both a primary focus of
our current capital expenditure program.  Likewise, oil production has decreased
from the East  Breaks 165 Field (31 Mbbl) and East Breaks 160 and 161 Fields (14
Mbbl) due to lower capital expenditures in those fields and the rapid production
declines from the wells in those fields, which are inherent in the areas that we
operate.

Cost and Expenses

     Lease operating  expenses increased $1.2 million,  to $7.5 million,  during
the third quarter of 2001 compared to $6.3 million in 2000. The West Delta Block
52 Field,  which was  purchased in April 2001,  added $0.8 million of additional
lease operating expenses, when compared to the third quarter of 2000. On an Mcfe
basis,  lease operating  expenses also increased to $1.85 in 2001, from $1.19 in
2000.

     Depletion,  depreciation and amortization  ("DD&A")  increased 13%, or $1.0
million  primarily due to a 48% increase in DD&A per unit of production  and was
offset by a 23% decrease in total  production.  The higher cost per unit relates
primarily  due to an increase in the cost per Mcfe of  production  from the East
Breaks 109 and 110 Fields along with increased production from those Fields.


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     As part of our  regular  review  of proved  property  carrying  values  and
estimated  recoverability  of those  values,  during the third  quarter of 2001,
PANACO  recognized an  impairment of two proved oil and natural gas  properties.
The impairments were due primarily to reductions in estimated prices for oil and
natural gas production.

     Interest  expense  decreased  $0.6  million due to lower  weighted  average
borrowing  levels during 2001 in addition to lower  interest rate for our Credit
Facility, which is based on the prime rate.

     Other  income  increased  $0.1 million and is made up of the impact of SFAS
No. 133,  including a gain on the ineffective  portion of a natural gas swap and
the mark-to-market of an option to put oil to a purchaser.

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 the second quarter of 2000 we recorded an income
tax benefit of $29 million by reversing a valuation  allowance  recorded against
these assets.  From that point forward until the second quarter of 2001,  income
tax expense has been  recognized,  at the  effective  rate,  as a percentage  of
pre-tax income.

     The analysis of the deferred tax asset  utilization  made during the second
quarter of 2000  determined  that it was more likely than not that the  deferred
tax assets would be realized.  This  determination was based on several factors,
including  current  projections  of future  taxable  income.  This analysis also
included current  estimates for future oil and natural gas prices in addition to
recent reserve  additions.  Projections of future taxable income were sufficient
to utilize all of the  deferred  tax assets due to higher  commodity  prices and
reserve  additions,  therefore  the valuation  allowance  was removed.  With the
decrease in oil and natural  gas prices and reserve  estimates  since the second
quarter of 2000,  management's  estimates of future taxable income had decreased
to a point in which it was more  likely than not that none of its  deferred  tax
asset would be utilized. Based on this analysis and all other evidence available
at the time, the valuation allowance was reestablished  against the deferred tax
asset.

     These projections of future taxable income are management's best estimates,
using current reserve estimates,  estimates of future commodity prices and other
information  currently available.  While we believe that the assumptions used in
these projections are reasonable,  future events, including changes in commodity
prices,  could  result in a reduction  in some or all of the  deferred tax asset
valuation allowance in future periods.  During 2001 this evaluation included the
potential  sales of assets which would have resulted in significant  gains which
would  have been  offset  by the  deferred  tax  asset.  While  there is no sale
imminent, we are continually evaluating our options.

Net Income (Loss)

     A decrease in total revenues of $8.2 million, in addition to an increase in
income tax expense of $20.7 million, were the primary factors in a $29.1 million
decrease in net income and $1.20 decrease in net income per share from the third
quarter of 2000 to the third quarter of 2001.

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


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business is capital intensive,  typically requiring an investment up front and a
resulting  return on that  investment.  The resulting return and success of that
investment  will vary depending on the prices we receive for the oil and natural
gas. Also, due to the geographic  area that we operate in, the levels of capital
spending  are  significant  and  the  lives  of the  reserves  that  we own  are
relatively  short.  Historically,  our reserves  have a five to seven year life,
which tends to amplify oil and natural gas price fluctuations on our Company.

     For fiscal 2001, the Board of Directors has approved a $45 million  capital
budget.  This  budget  includes   approximately  $21.5  million  of  exploratory
projects,  the  majority  of which has been spent at the East Breaks 109 and 110
Fields.  While this level of  exploratory  spending  is higher  than in previous
years,  based on current  seismic and  drilling  technology,  we feel that these
projects are also lower risk than the exploratory  projects we have historically
participated in.

Other Contingencies

     An action was filed  against  the  Company in  Louisiana,  along with Exxon
Pipeline Company ("Exxon"), National Energy Group, Inc. ("NEG"), Mendoza Marine,
Inc., Shell Western Exploration & Production,  Inc. ("Shell"), and the Louisiana
Department of Transportation  and Development.  The petition was filed in August
1998, and alleges that, in 1997 and perhaps  earlier,  leaks from a buried crude
oil pipeline contaminated the plaintiffs' property. Pursuant to the purchase and
sale agreement  between PANACO and NEG, NEG is required to indemnify us from any
damages attributable to NEG's operations on the property after the sale.

     Pursuant to another  purchase and sale  agreement,  we may owe indemnity to
Shell and Exxon,  from whom we acquired  the  property  prior to selling same to
NEG. We believe that we have insurance  coverage for the claims  asserted in the
petition,  and have notified all insurance  carriers that might provide coverage
under our policies.  In 1999 NEG filed for chapter 11 bankruptcy  and emerged in
late 2000.  Some  discovery  has occurred in the case,  but discovery is not yet
complete. Therefore, at this point it is not possible to evaluate the likelihood
of an unfavorable outcome, or to estimate the amount or range of potential loss.


PART I
Item 3a.
                          QUANTITATIVE AND QUALITATIVE
                          DISCLOSURES ABOUT MARKET RISK

Commodity price hedges

     We follow a hedging strategy designed to protect against the possibility of
severe  price  declines  due to  market  volatility.  We may also  make  hedging
decisions to assure a payout of a specific acquisition or development project.

     For 2001, we have hedged 18,000 MMBtu per day of natural gas for the entire
year.  The hedge is a swap,  based on the NYMEX closing prices when the swap was
put in place in November  2000.  The swap prices range from a high of $6.415 per
MMBtu in January to a low of $4.485 per MMBtu in October and average  $4.914 per
MMBtu for the year.  The average price of this swap for July 1 through  December
31, 2001 is $4.54 per MMBtu. The  corresponding  settlement  prices are based on
the last three  trading days on the NYMEX for the month to which the swap prices
relate.  If  the  swap  prices  are  higher  than  the  settlement  prices,  the
counterparty  will pay us the price  difference  for the total MMBtu  hedged for
that month. If the swap prices are less than the settlement  prices, we will pay
the counterparty the price difference for the total MMBtu hedged for that month.


                                       21

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     We have also  purchased  an option to put oil to a  purchaser  at an agreed
upon price.  The put option is for 1,000  barrels of oil per day from  January 1
through September 30 at a NYMEX price of $25.00 per barrel.  The cost of the put
option was $1.00 per barrel, or $365,000.

     At  September  30,  2001 the fair value of these  hedges was a gain of $3.9
million, pre-tax.

     The fair value of our commodity hedging instruments is the estimated amount
that  we  would  receive  or pay to  settle  the  applicable  commodity  hedging
instrument at the reporting  date,  taking into account the  difference  between
NYMEX prices or index prices at year-end and the contract price of the commodity
hedging instrument.

PART II                        OTHER INFORMATION

Item 6.
                        EXHIBITS AND REPORTS ON FORM 8-K

         (a)   Exhibits

               None.

         (b)   Reports on Form 8-K

               None.

                                   SIGNATURES

     Pursuant to the  requirements  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.


Date:    November 13, 2001                 /s/  Todd R. Bart
     ------------------------              -------------------------------------
                                           Todd R. Bart, Chief Financial Officer

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