SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                                -----------------


                                    FORM 10-K
                  Annual Report Pursuant to Section 13 or 15(d)
                     of the Securities Exchange Act of 1934

     For the Fiscal Year Ended                       Commission File Number
         November 30, 1999                                 001-9872

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

                              COLUMBUS ENERGY CORP.
             ------------------------------------------------------
             (Exact name of Registrant as specified in its Charter)

                COLORADO                                84-0891713
       ------------------------             ------------------------------------
       (State of incorporation)             (I.R.S. Employer Identification No.)

           1660 Lincoln Street                             80264
            Denver, Colorado                            ----------
----------------------------------------                (Zip code)
(Address of principal executive offices)

               Registrant's telephone number, including area code:
                                 (303) 861-5252

                        Securities registered pursuant to
                            Section 12(b) of the Act:

                                                 Name of each Exchange on
      Title of each class                            which registered
      -------------------                        -----------------------
Common Stock, ($.20 par value)                   American Stock Exchange

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

     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,  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 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 nonaffiliates of the
registrant as of January 31, 2000 is $16,848,000.

     Indicate  the  number of  shares  outstanding  of each of the  registrant's
classes of common stock, as of January 31, 2000

                                                       Outstanding at
             Class                                    January 31, 2000
             -----                                    ----------------
Common Stock, ($.20 par value)                        3,762,374 shares

                       DOCUMENTS INCORPORATED BY REFERENCE

     Columbus Energy Corp.  definitive proxy statement to be filed no later than
120  days  after  the  end of  the  fiscal  year  covered  by  this  report,  is
incorporated by reference into Part III.




<PAGE>



                        ANNUAL REPORT (S.E.C. FORM 10-K)

                                      INDEX

                       Securities and Exchange Commission
                           Item Number and Description

                                     PART I

                                                                           Page
                                                                           ----
Item 1.  Business............................................................3
Item 2.  Properties - Oil and Gas Operations ............................... 4
Item 3.  Legal Proceedings..................................................22
Item 4.  Submission of Matters to a
                Vote of Security Holders....................................23

                                     PART II

Item 5.  Market for the Registrant's Common Equity
                and Related Stockholder Matters.............................24
Item 6.  Selected Financial Data............................................25
Item 7.  Management's Discussion and Analysis of Financial
                Condition and Results of Operations.........................26
Item 7A. Quantitative and Qualitative Disclosure About Market Risk .........41
Item 8.  Financial Statements and Supplementary Data........................42
Item 9.  Changes in and Disagreements with Accountants
                on Accounting and Financial Disclosure......................42

                                    PART III

Item 10. Directors and Executive Officers
                of the Registrant...........................................43
Item 11. Executive Compensation.............................................43
Item 12. Security Ownership of Certain Beneficial
                Owners and Management.......................................43
Item 13. Certain Relationships and
                Related Transactions........................................43

                             PART IV AND SIGNATURES

Item 14. Exhibits, Financial Statement
                Schedules and Reports on Form 8-K...........................44

         Signatures.........................................................75










                                       2
<PAGE>



                                     PART I

Item 1.  BUSINESS

      Columbus Energy Corp.  ("Columbus") was incorporated under the laws of the
State of Colorado on October 7, 1982.  Columbus  engages in the  production  and
sale of crude oil,  condensate and natural gas, as well as the  acquisition  and
development of leaseholds  and other  interests in oil and gas  properties,  and
also acts as  manager  and  operator  of oil and gas  properties  for itself and
others.  It also  engages  in the  business  of  compression,  transmission  and
marketing  of natural gas  through its  wholly-owned  subsidiary,  Columbus  Gas
Services,  Inc. ("CGSI"), a Delaware corporation.  On September 1, 1998 Columbus
formed a Texas  partnership  named  Columbus  Energy,  L.P.  and is its  general
partner.  The  partnership's  limited partner is Columbus Texas,  Inc., a Nevada
corporation,  which  is a  wholly-owned  subsidiary  of  Columbus.  All  of  the
Company's oil and gas properties in Texas were  transferred  to the  partnership
effective  September 1, 1998.  Columbus  remains the operator of the properties.
Prior to February  1995,  CEC Resources Ltd.  (Resources"),  an Alberta,  Canada
corporation,   was  also  a  wholly-owned   subsidiary  but  became  a  separate
publicly-owned  entity when it was spun-off via a rights offering by Columbus to
its  shareholders.  The term "Company" or "EGY" as used herein includes Columbus
and its subsidiaries.

      The Company  currently  has 31  employees.  The current  technical  staff,
including management,  is comprised of four petroleum engineers and one landman.
The  administrative  staff  provides  support  required for  accounting and data
processing  including  disbursement  of  monthly  oil  and gas  revenues,  joint
interest billing functions, and accounts payable.

             During  1998  Columbus  declared a 10% stock  dividend  distributed
March 9, 1998 to  shareholders  of record as of February 23, 1998.  During 1997,
Columbus  declared a five-for-four  stock split for shareholders of record as of
May 27 which was distributed on June 16, 1997 and was issued from authorized but
unissued  shares.  The 1998 stock dividend and two prior 10% stock  dividends in
1994 and 1995 were paid from  treasury  shares  reacquired  from the  market and
therefore reduced cumulative retained earnings and increased paid-in capital. No
cash dividends have been paid since the Company became publicly-owned in 1988.

      From shortly after its incorporation until January 1988, the Company was a
wholly-owned  or  majority-owned  subsidiary  of  Consolidated  Oil & Gas,  Inc.
("Consolidated") after which time it became a separate  publicly-owned entity as
a  result  of  a  spin-off  via  a  rights   offering  by  Consolidated  to  its
shareholders.



                                       3
<PAGE>



Item 2.  PROPERTIES

                             Oil and Gas Properties

Reserves

             The  estimated   reserve  amounts  and  future  net  revenues  were
determined  by  outside  consulting  petroleum  engineers.  The  reserve  tables
presented  below show total proved reserves and changes in proved reserves owned
by Columbus for the three years ended November 30, 1999, 1998 and 1997.

                           PROVED OIL AND GAS RESERVES
<TABLE>
<CAPTION>

                                                  1999                    1998                       1997
                                           -------------------     -----------------          -----------------
                                            Oil         Gas          Oil        Gas            Oil         Gas
                                            MBbl        Mmcf         MBbl       Mmcf           MBbl        Mmcf
                                            ----        ----         ----       ----          -----        ----
<S>                                         <C>        <C>           <C>       <C>            <C>         <C>
Proved reserves:
Beginning of year                             960      22,463        1,805     18,520         1,643       18,665
Revisions of previous
   estimates                                  399      (1,405)        (713)       767          (127)         226
Purchase of reserves                            -           -            1        320             -            -
Extensions and discoveries                     68         726           88      6,355           538        5,066
Production                                   (169)     (3,201)        (221)    (3,499)         (249)      (3,370)
Sale of reserves                                -           -            -          -             -       (2,067)
                                           ------      ------        -----     ------         -----       ------
End of year                                 1,258      18,583          960     22,463         1,805       18,520
                                           ======      ======        =====     ======         =====       ======
Proved developed reserves:

Beginning of year                             762      20,674        1,333     16,122         1,211       15,758
                                           ======      ======        =====     ======         =====       ======
End of year                                   925      14,748          762     20,674         1,333       16,122
                                           ======      ======        =====     ======         =====       ======
</TABLE>


Proved Developed Producing Reserves

     As of November 30,  1999,  Columbus has  approximately  815,000  barrels of
proved developed producing oil and condensate in the United States most of which
are  attributable to primary  recovery  operations.  Producing oil properties in
Montana and Texas  account for over 98%, and Texas alone 77%, of the reserves in
the proved developed producing category.

     The gas producing  properties owned by Columbus are located in Texas, North
Dakota,  Louisiana,  Oklahoma and Montana and contain 11.0 billion cubic feet of
proved developed  producing gas reserves.  Texas  properties  account for 95% of
these reserves.

     The reserves in this  category can be  materially  affected  positively  or
negatively  by  either  currently  prevailing  or  future  prices  because  they
determine the economic lives of the producing wells.



                                       4
<PAGE>



Proved Developed Non-Producing Reserves

     The reserves in this category are located in the states of Texas, Louisiana
and Montana.  Generally,  these are reserves behind the casing in existing wells
with  recompletion  required  before  commencement  of production or else are in
wells being completed and/or completed but awaiting pipeline connections at year
end.

     Columbus' non-producing reserves equal 110,000 barrels of oil, or 9% of its
total proved oil reserves,  and 3.7 billion cubic feet of natural gas, or 20% of
its total proved natural gas reserves.

Proved Undeveloped Reserves

     Columbus' proved undeveloped  reserves were  approximately  333,000 barrels
and 3.8 billion  cubic feet of natural  gas.  Almost all of the oil  reserves in
this  category are in Montana.  All of the proved  undeveloped  gas reserves are
attributable  to undrilled  locations  offsetting  production  in Webb,  Zapata,
Harris and Jim Hogg Counties, Texas and Montana.

     These reserves are expected to either be developed during 2000 or in future
when  there is some  stabilization  of oil  prices at levels  which will yield a
satisfactory rate of return on investment without fear of another roller coaster
price fallout.


















                                       5
<PAGE>



Standardized Measure

     The schedule of  Standardized  Measure of Discounted  Future Net Cash Flows
(the  "Standardized  Measure") is  presented  below  pursuant to the  disclosure
requirements of the Securities and Exchange  Commission ("SEC") and Statement of
Financial  Accounting Standards No. 69, "Disclosures About Oil and Gas Producing
Activities"  (SFAS- 69) for such  information.  Future cash flows are calculated
using  year-end oil and gas prices and operating  expenses,  and are  discounted
using a 10% discount factor.

            STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
                RELATING TO ESTIMATED PROVED OIL AND GAS RESERVES
                             (thousands of dollars)
<TABLE>
<CAPTION>

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

<S>                                                                    <C>           <C>         <C>
Future oil and gas revenues                                            $ 74,284      $53,271     $ 79,381
Future cost:
  Production cost                                                       (24,031)     (13,688)     (21,856)
  Development cost                                                       (4,811)      (2,638)      (5,401)
Future income taxes                                                     (10,504)      (6,325)     (11,531)
                                                                       --------      -------     --------
Future net cash flows                                                    34,938       30,620       40,593
Discount at 10%                                                         (11,229)      (8,691)     (10,422)
                                                                       --------      -------     --------
Standardized measure of discounted future net
  cash flows                                                           $ 23,709      $21,929     $ 30,171
                                                                       ========      =======     ========
</TABLE>

          CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
                FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES
                   FOR THE THREE YEARS ENDED NOVEMBER 30, 1999
                             (thousands of dollars)
<TABLE>
<CAPTION>

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

<S>                                                                     <C>          <C>           <C>
Balance, beginning of year                                              $21,929      $30,171       $ 38,160

  Sale of oil and gas net of production costs                            (7,081)      (7,397)       (10,708)
  Net changes in prices and production costs                              9,801      (12,034)       (10,502)
  Purchase of reserves                                                        -          310              -
  Sale of reserves                                                            -            -         (1.320)
  Extensions, discoveries and other additions                             1,150        6,896          9,660
  Revisions to previous estimates                                         1,346       (3,406)          (710)
  Previously estimated development costs
    incurred during the period                                              268          586          1,089
  Changes in development costs                                           (1,945)       2,066            229
  Accretion of discount                                                   2,599        3,730          4,653
  Other                                                                  (1,951)      (2,066)        (1,620)
  Change in future income taxes                                          (2,407)       3,073          1,240
                                                                        -------      -------        -------

Net increase (decrease)                                                   1,780       (8,242)        (7,989)
                                                                        -------      -------        -------

Balance, end of year                                                    $23,709      $21,929        $30,171
                                                                        =======      =======        =======
</TABLE>





                                       6
<PAGE>


     The  standardized  measure is intended to provide a standard of  comparable
measurement  of the  Company's  estimated  proved oil and gas reserves  based on
economic and  operating  conditions  existing as of November 30, 1999,  1998 and
1997.  Pursuant to SFAS-69,  the future oil and gas revenues are  calculated  by
applying to the proved oil and gas  reserves  the oil and gas prices at November
30 of each year relating to such  reserves.  Future price changes are considered
only to the extent  provided by  contractual  arrangements  in existence at year
end.  Production  and  development  costs are based upon costs at each year end.
Future income taxes are computed by applying  statutory tax rates as of year end
with  recognition  of tax basis,  net operating  loss  carryforwards,  depletion
carryforwards,  and  investment  tax  credit  carryforwards  as of that date and
relating to the proved properties.  Discounted amounts are based on a 10% annual
discount  rate.  Changes in the demand for oil and gas,  price changes and other
factors make such estimates inherently imprecise and subject to revision.

       Discounted  future net cash flows before  income taxes for reserves  were
$30,173,000 in 1999,  $25,986,000 in 1998, and  $37,301,000 in 1997. As required
by SFAS-69,  the future tax  computation  appearing  in the above table does not
consider the Company's annual interest  expenses and general and  administrative
expenses nor future expenditures for intangible drilling costs. Because of these
factors,  the tax provisions are not truly  representative of the expected lower
future  tax  expense to the  Company  so long as it remains an active  operating
company.

       The reserve and  standardized  measure  tables  prescribed by the SEC and
presented  above are prepared on the basis of a weighted  average  price for all
properties  as of each  year  end.  At  November  30,  1999 the  crude oil price
(including  natural gas liquids) was $23.48 per barrel and the natural gas price
was $2.41 per  thousand  cubic  feet.  The SEC  requires  that this  computation
utilize those year end prices and expenses which are then held constant,  except
for contractual escalations, over the life of the property.

       The  calculation  of  discounted  future  cash  flows  can be  materially
affected by being compelled to use only those prices that happen to be effective
on  November  30  each  year  (Columbus'  fiscal  year  end)  because  of  price
volatility.  Mandatory  usage of prices which happen to prevail on a single date
can  have  an  inordinate  influence  on  year-end  reserves  as  well as on the
resulting year to year change that a company  reports for discounted  future net
cash flows determined using this standardized  measure  calculation.  Management
has  long  advocated  using a  weighted  average  of  prices  actually  received
throughout  the  year  to  make  this  standardized   measure  calculation  less
susceptible  to the impact of wide  monthly  fluctuations  in prices  which have
occurred so frequently  in recent  years.  Even using  weighted  average  annual
prices  still may or may not be very  indicative  of future  cash flows  because
average prices may vary widely in future fiscal years.



                                       7
<PAGE>



Both 1999 and 1998 fiscal years are good  examples of why an average price would
be preferable in management's  opinion since year end prices for natural gas and
crude oil were significantly different from the average annual prices received.

Outside Consultant's Report

       An outside  consulting firm, Reed Ferrill & Associates,  was retained for
the  purpose of  preparing  a report  covering  the  reserves  of the  Company's
properties and a future production forecast using constant prices as of November
30,  1999,  1998 and 1997.  The reports for 1998 and 1997 on the reserves of the
properties located in the Berry Cox field in Texas were prepared by Huddleston &
Co., Inc., another outside consulting firm. These reports are prepared each year
as required by the Company's bank line of credit.

Production

     Columbus' net U.S. oil and gas production for each of the past
three fiscal years is shown on the following table:

                                           Fiscal Year
                             ----------------------------------------
                             1999             1998               1997
                             ----             ----               ----
Oil-barrels                169,000          221,000             249,000
Gas-Mmcf                     3,201            3,499               3,370

       During the fiscal  year 1999,  Columbus  filed Form EIA23 with the Energy
Information Agency which required disclosure of oil and natural gas reserve data
for wells operated by Columbus.  The reserve data reported was for calendar year
1998.  This data was  reported on a gross  operated  basis  inclusive of royalty
interest and,  therefore,  does not compare with Columbus' net reserves reported
for 1998.

       Average price and cost per unit of  production  for the past three fiscal
years are as follows:

                                                 Fiscal Year
                                  -----------------------------------------
                                   1999             1998               1997
                                  ------            ----               ----
Average sales price:
   per barrel of oil              $16.63           $13.22             $19.62
   per Mcf of gas                 $ 2.28           $ 2.18             $ 2.65
Average production cost per
  equivalent barrel               $ 4.18           $ 4.00             $ 3.83

       Natural gas is converted to oil at the ratio of six Mcf of natural gas to
one barrel of oil. Production costs for fiscal years 1999, 1998 and 1997 include
production taxes.



                                       8
<PAGE>



Developed Properties

       A summary of the gross and net interest in producing  wells and gross and
net interest in producing acres is shown in the following table:

November 30, 1999                     Gross                         Net
-----------------               ----------------             ----------------
                                Oil          Gas             Oil          Gas
                                ---          ---             ---          ---
Wells                           80           169              21           21

Acres                               33,788                        9,845

Undeveloped Properties

       The  following  table sets forth the Company's  ownership in  undeveloped
properties:

November 30, 1999                        Gross Acres           Net Acres
------------------                       -----------           ---------
  Louisiana                                16,047                1,561
  Montana                                  11,223                6,759
  New Mexico                                  840                  630
  North Dakota                              1,659                  277
  Oklahoma                                  1,280                  640
  Texas                                     7,460                3,682
                                           ------               ------
Total Undeveloped Properties               38,509               13,549
                                           ======               ======






















                                       9
<PAGE>



Drilling Activities

       The  Company  engages  in  exploratory   and   development   drilling  in
association with third parties,  typically other oil companies.  Actual drilling
operations are not conducted by the Company and are usually carried out by third
party drilling contractors, but the Company may act as operator of the projects.
The following table gives information  regarding the Company's drilling activity
in its last three fiscal years.
<TABLE>
<CAPTION>

                                                       Year Ended November 30,
                                     ------------------------------------------------------------
                                           1999                   1998                   1997
                                     ---------------       ---------------       ----------------
                                     Gross       Net       Gross       Net       Gross       Net
                                     -----       ---       -----       ---       -----       ---
<S>                                    <C>      <C>           <C>     <C>          <C>       <C>
EXPLORATORY
Wells Drilled:
    Oil                                 2       1.34           2       1.10         2        1.45
    Gas                                 1        .54           3       1.69         1         .37
    Dry                                 4       2.38           2        .92         1         .34
DEVELOPMENT
Wells Drilled:
    Oil                                 0          0           1        .67         4        1.91
    Gas                                 7       1.63           8       1.06        18        2.71
    Dry                                 2        .15           4       1.23         3         .65
TOTAL
Wells Drilled:
   Oil                                  2       1.34           3       1.77         6        3.36
   Gas                                  8       2.17          11       2.75        19        3.08
   Dry                                  6       2.53           6       2.15         4         .99
                                       --       ----         ---       ----        --        ----
       Total                           16       6.04          20       6.67        29        7.43
                                       ==       ====         ===       ====        ==        ====
</TABLE>






















                                       10
<PAGE>



Current Activities

       During the fourth  quarter of fiscal 1999 and subsequent  thereto,  there
was a flurry of  drilling  and  completion  activity  involving  the El  Squared
prospect in Bee County.  This was primarily related to the impending  expiration
of the  primary  term of the Fred Long lease which  represented  over 40% of the
approximate  5,700 acres of leaseholds in that prospect block.  This lease could
be extended over the primary term with two alternatives available.  One of these
required payment to the royalty owner of  approximately  $500,000 of lease bonus
for a two-year lease extension  agreement which also required  modifications  to
the base  lease  with some  fairly  significant  changes  in the size of and the
manner in which drilling units could be created or pooled. The other alternative
available was to have drilling operations under way over the primary term of the
lease or have a well completing within 60 days of expiration of the primary term
of the lease, or both.

       Columbus,  as  operator  for its own  account  as  well as on  behalf  of
participants,  determined to have both circumstances in existence by essentially
utilizing the bonus money  equivalent to commence  drilling a deviated  wellbore
toward an upper  Massive  objective  after cutting a window in the casing in the
Long #3 and be  drilling  over  the  January  7,  2000  lease  expiration  date.
Fortunately,  there was already a  completion  attempt  under way at the Long #4
which met the  within 60 days of the lease  expiration  requirement.  During the
last week in December  1999 and early in January of 2000,  management  initially
tried  to  establish  commercial  production  from a lower  Massive  section  at
approximately  13,000  feet  as well as in a  stray  sand  in the  Massive  silt
interval at approximately 12,300 feet. It was assumed that if those zones proved
to be unsuccessful,  the upper Massive Sand at approximately  12,000 feet, which
had an  excellent  electric  log in that  interval,  could be completed as a gas
producer.  However,  a continuous  drilling  program would be necessary with the
commencement  of a new well every 60 days  following  completion  of a preceding
well in order to keep the lease in force. This provision was expected to provide
a  sufficient  period  of time to allow  the group to  develop  the  anticipated
reserves in fault block "B" in the upper and middle Wilcox Sands. Such a program
would not maintain the deep Wilcox Reagan Sands under lease  without  drilling a
wellbore to that depth,  but the group was  unwilling to take that route because
of the  expense  and  the  risk  associated  therewith.  Based  on  3-D  seismic
interpretation, only one potential Reagan structure was being given up under the
Long lease and those rights were owned under the remaining acreage.




                                       11
<PAGE>


       Management was able to meet the critical path logistics necessary to keep
the lease in force but then had to suffer severe disappointment from the results
of those  extraordinary  efforts.  As explained in a Special  Interim  Report to
Shareholders  on January 14, 2000,  the lower  Massive zone was fairly tight and
yielded only about 100,000 cubic feet per day flow rate although it exhibited an
extremely  high  shut-in  bottom hole  pressure of  approximately  10,000  psig.
Management  was not  confident  that a fracture  stimulation  of that sand would
yield a completion with sufficient flow rates to justify  postponing  completion
of the upper Massive zone and leaving it shut-in behind  unperforated  casing. A
dual  completion  was not practical.  Furthermore,  a small amount of water with
limited gas had been added from the zone at 12,300 feet after being  perforated.
This  effectively  eliminated any further  consideration of the basal sand being
fracture  stimulated  without  encountering   considerable  wellbore  logistical
problems to isolate that lower zone from the 12,300-foot zone.

       As a  consequence,  completion  efforts  were moved uphole where we fully
expected an excellent  flow of gas from the upper Massive zone.  This belief was
supported by good sand in the mud samples  along with a  reasonable  show of gas
plus  corroborating   electric  logs  of  the  interval.  The  latter  had  been
interpreted by various service company experts,  our consultants,  and Columbus'
own  personnel  as  being  gas  productive  with a  reasonably  high  flow  rate
anticipated.  This confidence was further  supported by log  calculations  which
were made using available known  resistivities  from water samples obtained from
an upper  Massive Sand  interval in the initial  deviated  hole drilled from the
Long #3 which had flowed gas and water. It was over 300 feet down structure from
this  Long  #4  sand  but  was  in a  separate  fault  block.  To  the  absolute
astonishment  of all  concerned,  this upper Massive Sand  inexplicably  yielded
formation water with only a very limited amount of accompanying  gas. In fact, a
significant  hourly rate was swabbed from 25 feet of perforations  from within a
gross sand interval of 90 feet so the zone was permeable but definitely  wet. To
date, no one has a solid explanation for these results. Admittedly, the water in
this  interval  was a bit fresher  and this  isolated  fault block was  probably
completely sealed, but this is not a satisfactory explanation. So confident that
commercial gas production would be found by every person  involved,  the Company
had already installed a gathering line in order to connect the well and commence
sales   immediately.   Unfortunately,   surprises  such  as  this  have  plagued
explorationists  since the first U.S.  commercial oil discovery in 1859. It is a
part of the business not  understood by most people  outside of the industry and
is painful to those within.

       As soon as it was  established  that the  upper  Massive  Sand was  water
productive,  management  also  shut  down  drilling  operations  at the  Long #3
sidetrack  hole.  However,  by the time this  could be done,  the  wellbore  was
already at a measured  depth of 10,800  feet and was over 150 feet away from the
original wellbore and at a 20 degree angle. Management did weigh the possibility
of continuing  drilling operations at the Long #3 until it reached its objective
since it would have required only a few days and because this sand would be in a
different  fault block. To support the notion that this might make a difference,
the sand in the initial Long #3 deviated wellbore had yielded  considerably more
gas than the Long #4 despite being over 300 feet  structurally  lower.  However,




                                       12
<PAGE>



the  likelihood  of finding a water free  completion  updip in the Long #3 fault
block carried too much risk.  It was believed  those same funds could be used to
further  develop  additional  gas reserves  from the Slick Sands which are known
producers in this "B" fault block area.

       Because  of the Long #4  results,  two  other  identified  upper  Massive
locations  were  scrapped and it was  determined to farmout about 1,000 acres of
leaseholds  within  the "A" fault  block area on the east side of the El Squared
acreage block.  This farmout will require a test of a sizable Massive  structure
identified by 3-D seismic which will be followed by a working  interest  back-in
after  payout  to  Columbus,  et al.  In  addition,  there  are at  least  three
Slick/Luling  Sand  upper  Wilcox  structures  previously  identified  on the El
Squared acreage which can be drilled during fiscal 2000.  While these structures
are not quite so romantic as Massive prospects, they do offer potential reserves
at each structure of 5 to 10 billion cubic feet plus associated  condensate with
considerably lower costs to develop.

       As fiscal 1999 came to a close, Columbus had no rigs actively drilling at
any of its other key  areas as the  focus  and  funds had been  dedicated  to El
Squared activity.  There were two wells in the Laredo area that had been drilled
which for tax reasons  were  awaiting  completion  until after  January 1, 2000.
These were being carried as "in progress" at year end. A few proved  undeveloped
locations  have been  identified  for drilling in the Laredo area during  fiscal
2000 and more should be forthcoming.

       A more detailed description related to recent activities as segregated by
Columbus' primary areas of operations follows:

South Texas - Laredo Area

       This  continues  to be the most  important  operational  area  where  the
Company  serves as operator of over 100 natural gas wells in various fields that
extend  from the  southern  city  limits of Laredo to the B. R. Cox field in Jim
Hogg County,  approximately  80 miles to the south.  In this area  Columbus owns
working  interests  ranging  from 1% to 53% in wells which it operates  and less
than 10% in the relatively few wells where it does not.

       For the past several  years in the area near Laredo,  Columbus has, for a
good portion of each year, had at least one rig drilling infill,  extension, and
new fault block  locations  which had been  identified by a 3-D seismic  program
conducted in 1994-95.  During  fiscal 1999,  only five (1.01 net) gas wells were
drilled and completed successfully.  In addition, one (.06 net) well was drilled
which  resulted in a dry hole.  The total number of wells was  somewhat  reduced
from past drilling  programs of 10 wells in fiscal 1998, 18 in fiscal 1997,  and
12 in fiscal 1996.



                                       13
<PAGE>



     In the B. R. Cox field,  Columbus  continued  to  postpone  all  workovers,
recompletions,  or new  drilling  because of the failure of the largest  working
interest  owner's  willingness or capability to advance their share of the funds
required to do the work. Even worse,  they would not agree to go non-consent and
suffer  penalties  provided  for in the  Operating  Agreement  so we  have  been
stalemated  for  years.  Continued  frustration  with this "do  nothing"  stance
appears  about to be  alleviated  as that  company  recently  agreed to sell the
balance of its  properties in this field to another  operator.  At least now the
working  interest  holders  should be able to jointly  perform  some much needed
workovers to reestablish  commercial  production at several shut-in wells. Also,
the group will consider drilling at least one or more wells during fiscal 2000.

El Squared Prospect - Bee County, Texas

     This  prospect  area is one  for  which  recent  drilling  activities  were
discussed in detail above and had previously  been described in earlier  reports
and news  releases  as one of the most  exciting  areas  for  potential  reserve
accumulation  since  Columbus'  Sralla Road  discovery  east of Houston in 1990.
Currently,  leaseholds  approximate  5,700  acres in size of which all have been
shot with 3- D seismic and Columbus  currently owns a 55% working  interest (42%
NRI) while three of its drilling  associates own working  interests  which total
20%. An energy company which  originated the prospect owns the remaining 25% and
its  principal  owner  is also  the  mineral  owner  of the  prospect's  largest
individual lease which is almost 2,500 acres in size. As indicated,  there was a
flurry of calendar year end activity  because its expiration date was January 7,
2000. Two successful  Slick Sand wells have been completed  thereon with each of
the wells being inside  320-acre units which overlap so  approximately  450 plus
acres out of the almost 2,500 acres will be held by production. The balance will
probably  be allowed  to expire  because  of the lack of a  continuous  drilling
program.  Most of this  leasehold  cost was  wiped  out by  exploratory  expense
charges in fiscal 1999 as it appears the Massive zones of the Wilcox have pretty
much been condemned under the Long lease. Shallower sand development location(s)
are within these producing units for the most part.

         Only one working  interest  well (0.54 net),  the Long #2, was actually
completed  during fiscal 1999 as lower Slick  producer while the other two wells
were in an "in  progress"  status at year end.  These were the Long #3 (0.75 net
WI) and the Long #4 (0.90  net WI)  which  were  subsequently  determined  to be
unsuccessful  exploratory wells as previously  discussed  following  recovery of
water in the upper  Massive in the Long #4 and cessation of drilling at the Long
#3.  These  cased  wellbores  are being kept intact for the present in case they
might be usable for some other purpose.




                                       14
<PAGE>


         Several  leases   adjacent  to  the  Long  lease  have  now  had  their
attractiveness  eliminated by the Massive Sand being condemned in this "B" fault
block. Some of those remaining leases have  possibilities of being productive in
the Slick/Luling  zones of the upper Wilcox and three drillable  structures have
been identified thus far on remaining acreage in the prospect.

         As mentioned in Current Activities, the proposed farmout which is about
to be offered to  industry is a separate  leasehold  block of 1,021  acres.  The
farmee would acquire 100% of this acreage and related seismic for $160,000 which
approximates  the actual cost thereof.  An initial test well will be required to
be  drilled  to a depth of  12,000  feet to test an  upper  Massive  sand  which
underlies the "A" fault block and a 352-acre  drilling unit has been defined for
that purpose.  Also, a lower Massive sand structure  whose apex lies to the west
of this  initial  test well site is  essentially  located  entirely  within this
1,021-acre leasehold block should the farmee desire to drill another wellbore at
some  future  date.  Such a test well is not a  requirement  under the  proposed
farmout agreement.  At such time as the farmee has recovered all of its costs of
drilling and completing the initial test well, Columbus, et al, will back in for
a 33  1/3%  working  interest  in  that  drilling  unit  assuming  a  successful
completion. Because this wildcat location is in an entirely separate fault block
and a separate structure on the basinward side of the "A" fault, it is unrelated
to the Long #4.  This test well will be the second  deep test ever to be drilled
in this fault  block and its  structural  location  is over 300 feet high to the
prior well which was drilled in 1977.  That initial well had excellent  shows of
gas in a sand  which  appears  to be the upper  Massive  but that zone was never
perforated and tested because the hole was junked while trying to run production
liner.  It is expected  this  farmout  well will be drilled  during the next few
months assuming its terms can be negotiated successfully early in fiscal 2000.

         In addition  to the  previously  planned  tests  during  fiscal 2000 of
untested  Slick/Luling  structures on the remaining  leaseholds  which are still
intact, the structure on which the Long #1 and #2 wells have been completed will
require the  drilling  of a Long #5  wellbore in order to timely and  adequately
drain the main Slick sand and the lower  Slick sand  reservoirs.  This well site
should not only find those two reservoirs at structural  positions of 30 feet to
45 feet high to Long #1 but would  permit the upper  portion of the lower  Slick
sand to be drained as it was  faulted out in the Long #2.  Also,  the main Slick
sand that  produced  initially in the Long #1 was  shut-off by a through  tubing
bridge plug and needs to be returned  to  production  very soon rather than wait
until  upper Slick  reserves  have been  depleted  in the Long #1.  Particularly
appealing is the fact the structurally favorable Long #5 location should recover
"chimney" gas reserves for that zone as well as the lower Slick.  Both producing
zones  would  probably be produced  through  separate  strings of tubing in this
single wellbore to facilitate workover  operations when required.  A combination
of the  present  worth value  improvement  of  accelerating  recovery of the gas
reserves related to both reservoirs plus their higher structural  locations that
should recover  reserves  which might  otherwise be lost more than justifies the
drilling of this Long #5 location. It was previously proposed but then postponed
because  of the  flurry of year end  activity  surrounding  the  testing  of the
Massive structures on the Long lease.



                                       15
<PAGE>

Sralla Road Field Area - Harris County, Texas

         During fiscal 1999, there was participation in two wells drilled on the
south end of this  field.  One of those  wells was in the form of an  overriding
royalty  (0.0022  NRI) in a  successful  gas well  drilled by another  operator.
Because of the  relatively  minor amount of acreage that could be contributed to
form the 160-acre  drilling unit and the wellbore would have to be directionally
drilled with no cinch completion,  that acreage was farmed out and an overriding
royalty retained.  A second well, the Johnson/Peace #1, was drilled by that same
operator  at the  southwesternmost  end  of  the  field.  This  proved  to be an
expensive dry hole as  unfortunately  the operator  attempted to complete  same.
Columbus  contributed its limited  acreage owned to this 160-acre  drilling unit
and fortunately  participated for only a 0.086 net working  interest.  This unit
offset to the south  Columbus' Jones #1 oil well discovery that was announced in
fiscal 1998.  That well was placed on production  flowing 200 barrels of oil per
day in June 1999 after  completion of a gas gathering  system  through a densely
populated area.  Columbus owns 19% working  interest in the Jones #1 well and 5%
of the gathering system.  Apparently there is a cross fault between the Jones #1
well and the Johnson/Peace #1 dry hole which accounts for the latter being water
bearing. This is the first indication of water being present in the Jackson sand
in the  Sralla  Road West  Jackson  sand  field and most  probably  signals  the
southwestern extremity of the field has been found.

         The Sralla Road Field area has been a very important  asset to Columbus
throughout the last decade.  This was primarily  because of a relatively  small,
but very prolific,  Vicksburg oil field which  generated the necessary cash flow
which  allowed the Company to take risks in extending  both the initial  Jackson
sand  field on the  downthrown  side of the "B"  fault as well as on the  upside
thereof.  The very thin (3' to 6') sand  thickness  found in both Jackson fields
required the wells to be drilled on 160 acre spacing to make any economic  sense
when the costs and risks  involved were  weighed.  There was little room for any
dry holes or marginal  wells to be drilled yet some were drilled as these fields
were being  defined.  However,  a combination of increased gas prices during the
1990's and the recent  recovery of crude oil prices has definitely  improved the
outlook for obtaining a decent rate of return on recent  investments  during the
coming years. Furthermore, without the initial Jackson sand oil discovery having
been  completed in only four feet of sand at the Davis Oil Unit #1 in 1988,  the
shallower  Vicksburg oil discovery at the offset Davis B-1 would never have been
found.  One must therefore  consider the overall return from the area from every
source so the Jackson sand may claim credit for that  discovery.  Overall,  this
area proved to be very satisfactory from that standpoint and this field has been
Columbus' primary source of field level cash flow for the past ten years.



                                       16
<PAGE>


         About 20 miles east of the Sralla Road field, one of the best gas wells
in which the Company  owns an  interest  is located  near the famous old Anahuac
field in  Chambers  County,  Texas.  This  well,  the  Syphrett  Heirs  #1,  was
discovered in July,  1997 and has sold around 100 million cubic feet of gas each
month  since that  completion  in the Frio 16 sand and is  expected to do so for
many years to come. Columbus originally owned a larger working interest but as a
result of  certain  "back-ins"  that  interest  approximated  about 26%  working
interest in fiscal 1999. The most recent reserve review indicated that remaining
reserves yet to be recovered  approximate  4.92 BCF so it is expected  that this
well will yield a very high production rate for several more years.

Williston Basin Area

         During the latter part of fiscal 1998 and the first half of fiscal 1999
this  mature  area of  operations  suffered  from crude oil prices  that were so
ridiculously low that many of the wells which had been profitable had to be shut
down as they were  essentially  being operated for the benefit of royalty owners
and the state and local taxing  authorities.  They would not cover the operating
expenses  primarily  because  of pump  failures  as well as the  fact  that  the
principal  producing  horizons -- the  Ordivician  Red River  formation  and the
Mississippian  Mission  Canyon  formation  --  produce  water with the crude oil
almost from the  beginning of each well's  productive  life which becomes even a
greater  factor as the  reservoirs  approach the latter stages of their economic
life. During fiscal 1998, a sizeable  reduction was recognized for this area for
both the  proved  producing  and  proved  undeveloped  crude oil  reserves  with
essentially   all  undeveloped   locations  being   eliminated  as  marginal  or
uneconomic.  Also, the potential  structures  that had been  identified by a 3-D
Seismic  program were  eliminated  from further  consideration  as warranting an
exploratory test well. A general provision was made during both 1998 and 1999 in
the form of an  impairment  for  undeveloped  acreage  that  probably  would not
justify a test before expiration of the primary term of the lease.

         When crude oil prices began to recover toward mid-year 1999, an attempt
was made to resume  operations  and all of the wells that had been shut-in.  Not
unexpectedly,  several of the wells  showed a reduced  productivity  of oil as a
result of the shut-in period.  In the instance of two Red River wells, the water
percentage  had  increased  to  100%  or to  such  a  high  percentage  as to be
uneconomic.  Fortunately,  two of these wells, the Ullman #1 and the Young Heirs
#4, had porous zones in the shallower Duperow formation which offered promise of



                                       17
<PAGE>


being productive of commercial rates of oil and were successfully recompleted in
this  uphole zone as oil  discoveries.  While the  initial  production  began at
higher rates, both of these wells leveled off to about 50 barrels of oil per day
and have  settled into what is believed  will be the long slow decline  which is
customary  with the various  producing  formations in this deeper portion of the
Williston Basin. Most of the wells the Company owns in this area are at least 20
years old while several are over 30 years old and still are  producing  from the
original  zone in which  the well was  completed.  Decline  curve  history  of a
majority  of these  reservoirs  appears  to settle at less than 5% per year with
ultimate  well life  depending  more on the integrity of the  production  casing
against  collapse  opposite salt sections than on depletion.  Also,  since there
appears to be evidence of a limited  water drive in almost all of these  fields.
Although  the  production  rates of these  newly  completed  discoveries  in the
Duperow are modest,  Columbus owns a substantial  63.7% working  interest in the
Ullman #2 and a 70.3% working  interest in the Young Heirs #4 and their economic
well  life  expectancy  at  this  time  could  be in the 20 year  range  barring
unforeseen mechanical problems.

         By the end of fiscal  1999,  the price of crude oil had  recovered to a
high enough level and for a sufficient length of time for some of the previously
dropped  reserves for proved  undeveloped  locations to be restored.  Also,  the
economic  well life of several wells was extended  thereby  adding to the proved
developed  producing  reserves for those wells which had produced during the two
years of low prices as well as for those which had successfully been placed back
on production  because water  production had not rendered them uneconomic or had
not been permanently abandoned or recompleted.  If crude prices would eventually
stabilize in the $25 per barrel range,  management  would feel more  comfortable
that a reasonable  rate of return  could be realized and the proved  undeveloped
locations could then be drilled.  There is sufficient  available forecasted cash
flow in excess of preliminary  budget for the coming year to enable  Columbus to
add one or more Red River wells and/or  several of the shallower  Mission Canyon
locations.
















                                       18
<PAGE>


Titles

        The Company is confident that it has satisfactory title to its producing
properties  which are held  pursuant to leases from third  parties and have been
examined  on  several  occasions  to  determine  their  suitability  to serve as
collateral  for bank  loans.  Oil and gas  interests  are  subject to  customary
interest and burdens,  including overriding royalties and operating  agreements.
Titles to the  Company's  properties  may also be subject to liens  incident  to
operating agreements and minor encumbrances, easements and restrictions.

        As is  customary  in the oil and gas  industry,  the  Company  does  not
regularly  investigate  titles to oil and gas leases when acquiring  undeveloped
acreage.  Title is  typically  examined  before any drilling or  development  is
undertaken by checking the county and various  governmental records to determine
the  ownership  of the land and the  validity of the oil and gas leases on which
drilling  is to take  place.  The  methods of title  examination  adopted by the
Company are reasonably calculated, in the opinion of the Company, to insure that
production  from its  properties,  if obtained,  will be readily salable for the
account of the Company.  As stated  above,  certain of the  Company's  producing
properties  have  been  subject  to  independent   title   investigations  as  a
consequence  of bank loans  obtained and have been  accepted for such  purposes.
Insofar as is known to the Company,  there is no material  litigation pending or
threatened pertaining to its proved acreage.

        The  producing  and  non-producing  acreages  are  subject to  customary
royalty interests, liens for current taxes, and other burdens, none of which, in
the opinion of the Company,  materially  interfere  with the use of or adversely
affect the value of such properties.

Competition, Marketing and Customers

        Competition   and  Marketing.   The  oil  and  gas  industry  is  highly
competitive.  Major oil and gas  companies,  independent  producers  with public
drilling and production purchase programs and individual producers and operators
are active  bidders  for  desirable  oil and gas  properties  as well as for the
equipment and labor required to operate such  properties.  Many competitors have
financial resources,  staffs and facilities  substantially greater than those of
the  Company.  A ready  market for the oil and gas  production  is, to a limited
extent, dependent upon the cost and availability of alternative fuels as well as
upon the level of consumer  demand and domestic  production  of oil and gas; the
amount  of  importation  of  foreign  oil and gas;  the cost  and  proximity  to
pipelines  and other  transportation  facilities;  the  regulation  of state and
federal  authorities;  and the cost of complying with  applicable  environmental
regulations.








                                       19
<PAGE>


        All  production  of crude oil and  condensate  by the Company is sold to
others at field prices  posted by the  principal  purchasers of crude oil in the
areas where the producing  properties  are located.  In the Company's  judgment,
termination  of the  arrangements  under  which  such  sales are made  would not
adversely affect its ability to market oil and condensate at comparable  prices.
During  recent  years,   the  posted  prices  were  directly   affected  by  the
fluctuations in the supply and price of imported crude oil as well as by trading
of oil futures.

        A very  limited  amount of the  natural  gas  produced by the Company is
being sold at the wellhead under long-term contracts.  Following deregulation of
natural gas,  excesses of domestic  supply over demand,  plus  competition  from
alternate fuels caused  Columbus,  through CGSI, to take a much more active role
in marketing its own gas along with gas owned by third parties.

        Customers.  Sales to four purchasers of crude oil and natural gas, which
amounted to more than 10% of the Company's combined revenues for the years ended
November  30,  1999,  1998  and  1997,  are set  forth in Note 3 to Notes to the
Consolidated  Financial  Statements.  In the opinion of management,  a loss of a
customer has not to date,  and should not in the future,  materially  affect the
Company  since the nature of the oil and gas  industry is such that  alternative
purchasers are normally available on very short notice.

Government Regulations

        The  development,  production  and  sale of oil and  gas is  subject  to
various  federal,  state  and  local  governmental   regulations.   In  general,
regulatory  agencies are  empowered to make and enforce  regulations  to prevent
waste of oil and gas, to protect the  correlative  rights and  opportunities  to
produce oil and gas  between  owners of a common  reservoir,  and to protect the
environment.  Matters  subject to  regulation  include,  but are not limited to,
discharge permits for drilling  operations,  drilling bonds,  reports concerning
operations,  the  spacing  of wells,  unitization  and  pooling  of  properties,
taxation and environmental  protection.  From time to time,  regulatory agencies
have imposed price controls and  limitations  on production by  restricting  the
rate of flow of oil and gas wells below actual  production  capacity in order to
conserve supplies of oil and gas.










                                       20
<PAGE>


        The Company believes that the environmental regulations, as presently in
effect, will not have a material effect upon its capital expenditures,  earnings
or  competitive  position in the  industry.  Consequently,  the Company does not
anticipate  any  material  capital   expenditures  for   environmental   control
facilities  for the current year or any  succeeding  year.  No assurance  can be
given as to the future capital expenditures which may be required for compliance
with  environmental  regulations  as they may be adopted in future.  The Company
believes,  however, that it is reasonably likely that the trend in environmental
legislation and regulations will continue  to be towards stricter standards. For
instance, legislation previously considered in Congress would amend the Resource
Conservation  and Recovery Act to reclassify  oil and gas  production  wastes as
"hazardous  waste,"  the  effect  of which  would  be to  further  regulate  the
handling, transportation and disposal of such waste. If similar legislation were
to pass, it could have a significant  adverse  impact on the operating  costs of
the Company, as well as the oil and gas industry in general.

Operating Hazards

        The oil  and  gas  business  involves  a  variety  of  operating  risks,
including  the  risk  of  fire,  explosions,  blow-outs,  pipe  failure,  casing
collapse, abnormally pressured formations, and environmental hazards such as oil
spills, gas leaks,  ruptures and discharge of toxic gases, the occurrence of any
of which  could  result in  substantial  losses to the Company due to injury and
loss of life,  severe damage to and destruction of property,  natural  resources
and   equipment,    pollution   and   other   environmental   damage,   clean-up
responsibilities,  regulatory  investigation  and  penalties  and  suspension of
operations. The Company maintains insurance against some, but not all, potential
risks;  however,  there can be no assurance that such insurance will be adequate
to cover any losses or exposure for liability.  Furthermore,  the Company cannot
predict  whether  insurance will continue to be available at premium levels that
justify its purchase or whether  insurance will be available at all.  Generally,
the Company has elected to not obtain  blow-out  insurance when drilling a well,
except for deep high pressure wells or when required such as within city limits.




                                       21
<PAGE>


Natural Gas Controls

        The Federal  Energy  Regulatory  Commission  ("FERC") has issued several
rules  which  encourage  sales of gas  directly to end users and  provides  open
access to existing  pipelines by producers and end users at the highest possible
prices that can be negotiated.  All price controls were terminated as of January
1,  1993.  On April 8, 1992,  FERC  issued  Order No. 636 which has  essentially
restructured the interstate gas transportation  business.  The stated purpose of
Order 636 was to improve the competitive  structure of the pipeline industry and
maximize  consumer  benefits  from the  competitive  wellhead  gas market and to
assure that the services  non-pipeline  companies  can obtain from  pipelines is
comparable  to  the  services  pipeline  companies  offer  to  their  customers.
Following a rehearing with minimum modification, it was subsequently reissued as
FERC Order No. 636A which has led to much more  competitive  markets.  It raised
questions about whether  gathering  systems of interstate  pipelines can be sold
off and totally escape regulation but in more recent hearings FERC has failed to
resolve this issue  satisfactorily by suggesting this is a matter for regulatory
authorities in various local jurisdictions.

Item 3.  LEGAL PROCEEDINGS

        On October 7, 1998,  Columbus  was served with a complaint  in a lawsuit
styled Maris E. Penn,  Michael  Mattalino,  Bruce Davis, and Benjamin T. Willey,
Jr. vs. Columbus Energy Corp., Cause No. 98- 44940 in the 55th District Court of
Harris County,  Texas. The plaintiffs are parties to a September 1994 settlement
agreement  that provided for the conveyance of overriding  royalty  interests in
leases  acquired by Columbus in certain  portions of Harris  County.  Plaintiffs
claim Columbus is obligated under the settlement agreement to acquire all leases
available  within a described  portion of Harris  County and that  Columbus  has
failed to develop those leases as a reasonably prudent operator.  Plaintiffs are
claiming  damages  based upon their  alleged  right to a 3%  overriding  royalty
interest in leases taken and drilled by third parties within the described area.
Discovery is ongoing.  Columbus denies all allegations of failure to develop and
instructed  counsel to vigorously  defend this lawsuit.  The parties are set for
mediation on April 11, 2000 and for trial on May 22, 2000.

        Management  is  unaware  of  any  asserted  or   unasserted   claims  or
assessments  against the Company  which would  materially  affect the  Company's
future financial position or results of operations.

        The  Company's  officers and directors are  indemnified  by  contractual
agreement with each  individual,  as well as by the Articles of Incorporation of
Columbus as provided in and in accordance with the Colorado Corporation Code, as
amended, of the State of Colorado.







                                       22
<PAGE>

Item 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        During the fourth  quarter of 1999, no matters were  submitted to a vote
of security holders.


































                                       23
<PAGE>


                                     PART II

Item 5.  MARKET FOR THE REGISTRANT'S COMMON EQUITY
         AND RELATED STOCKHOLDER MATTERS

        The common stock of Columbus  commenced  trading on the  American  Stock
Exchange on March 11, 1993. The common stock  previously  traded on the American
Stock Exchange Emerging Companies  Marketplace since July 30, 1992. The reported
high and low sales prices for the periods ending below were as follows:

                                         High(1)        Low(1)
                                         -------        ------
2000:
  December 1, 1999 through

     January 31, 2000                   $ 5.75        $ 5.50

1999:
  First quarter                         $ 6.75        $ 6.125
  Second quarter                          6.25          5.50
  Third quarter                           6.125         5.68
  Fourth quarter                          6.00          5.25

1998:
  First quarter                         $ 8.18        $ 7.125
  Second quarter                          7.875         7.00
  Third quarter                           7.50          6.375
  Fourth quarter                          6.69          6.25

1997:
  First quarter                         $ 8.00        $ 6.27
  Second quarter                          7.64          6.14
  Third quarter                           7.84          6.82
  Fourth quarter                          8.30          7.05

(1)  Price  per share  amounts  have been  adjusted  for the 10% stock  dividend
     distribution  to  shareholders  of  record  on  February  23,  1998 and the
     five-for-four stock split on May 27, 1997.

       As of January  31,  2000 the  reported  closing  sales  price of Columbus
common stock was $5.625 per share.

       As of November 30, 1999, there were  approximately  420 holders of record
of Columbus'  common stock and an estimated 1,000 or more beneficial  owners who
hold their shares in brokerage accounts.

       The Company  has never paid any cash  dividends  on its common  stock and
does  not  contemplate  the  payment  of cash  dividends  since  it plans to use
earnings  available for its drilling,  development and acquisition  programs and
excess cash flow has been used to acquire  treasury  shares that can be used for
acquisitions or stock dividends.  Payment of future cash dividends would also be
dependent on earnings, financial requirements and other factors.



                                       24
<PAGE>



Item 6.  SELECTED FINANCIAL DATA

       The table below sets forth  selected  historical  financial and operating
data for the Company and its consolidated  subsidiaries for the years indicated.
The historical data for each of the years in the five-year period ended November
30, 1999,  were derived from the financial  statements of the Company which have
been  audited  by  PricewaterhouseCoopers  LLP,  independent  accountants.  This
information is not necessarily  indicative of the Company's future  performance.
The information set forth below should be read in conjunction with "Management's
Discussion and Analysis of Financial  Condition and Results of Operations,"  and
the Company's Financial Statements and notes thereto, included elsewhere herein.
<TABLE>
<CAPTION>

                                                                                 Year Ended November 30,
                                                    -------------------------------------------------------------------------------
                                                      1999            1998                1997            1996               1995(a)
                                                      ----            ----                ----            ----               ----
                                                                        (in thousands, except per share data)
<S>                                                 <C>            <C>                <C>               <C>                 <C>
Operating data:
  Revenues                                          $11,500        $ 12,094           $15,156           $11,815             $ 9,400
  Loss on asset disposition,
    impairment of long-lived
    properties and abandonments                        (973)         (3,482)           (2,179)             (165)             (3,055)
  Net earnings (loss)                                (1,215)         (1,235)            2,167             2,098              (1,495)
                                                    =======        ========           =======           =======             =======
  Earnings (loss) per
    share(b):

    Basic                                           $  (.31)       $   (.29)          $   .50           $   .50             $  (.35)
                                                    =======        ========           =======           =======             =======
    Diluted                                         $  (.31)       $   (.29)          $   .49           $   .49             $  (.35)
                                                    =======        ========           =======           =======             =======
  Weighted average number of
    common and common equivalent
    shares outstanding(b):
    Basic                                             3,898           4,194             4,299             4,211               4,321
                                                    =======        ========           =======           =======             =======
    Diluted                                           3,898           4,194             4,392             4,259               4,321
                                                    =======        ========           =======           =======             =======
Cash flow data(d):
  Cash from operating activities                    $ 3,258        $  6,258           $ 8,638           $ 5,638             $ 3,929
  Cash used in investing activities                 $(2,336)       $ (6,717)          $(7,294)          $(6,320)            $  (119)
  Cash provided by (used  in)
    financing activities(c)                         $(1,075)       $    605           $  (883)          $   664             $(4,223)
  Cash flow before changes in
    operating assets and liabilities                $ 3,027        $  5,470           $ 9,132           $ 6,340             $ 3,920
  Discretionary cash flow                           $ 5,770        $  6,192           $ 9,672           $ 6,658             $ 4,096
Balance sheet data:
  Total assets                                      $22,530        $ 23,949           $26,135           $21,625             $18,321
  Long-term debt, excluding
    current maturities - bank debt                  $ 5,500        $  4,900           $ 2,200           $ 2,200             $ 1,600
  Stockholders' equity                              $12,798        $ 15,264           $17,958           $16,225             $13,186

</TABLE>

 (a)  Does not include results of CEC Resources Ltd. after its divestiture on
      February 24, 1995.
 (b)  Reflects restated amounts for 1994 through 1997 after stock dividends and
      stock split.
 (c)  No cash dividends have been declared or paid in any period presented.
 (d)  See discussion of cash flows in "Management's Discussion and Analysis of
      Financial Condition and Results of Operations".



                                       25
<PAGE>


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

    The following  summarizes the Company's  financial  condition and results of
operations and should be read in  conjunction  with the  consolidated  financial
statements and related notes.

    The  information  below and elsewhere in this Form 10-K may contain  certain
"forward-looking  statements" that have been based on imprecise assumptions with
regard  to  production  levels,   price   realizations,   and  expenditures  for
exploration and development and anticipated  results therefrom.  Such statements
are subject to risks and uncertainties that could cause actual results to differ
materially from those expressed herein or implied by such statements.

Liquidity and Capital Resources

    By mid-1999  crude oil prices had begun to recover after two years of dismal
prices.  Natural gas prices also had a similar recovery from lower prices during
the winter of  1998/1999.  The Company's  natural gas prices  averaged 5% higher
than in 1998 while  annual  production  was down 9% compared to 1998 for reasons
discussed  later.  Improved prices did not fully offset the 24% decline in crude
oil production which resulted in lower revenues.  Fiscal 1999 had  substantially
higher  exploration  expenses but lower impairment  charges so that the 1999 net
loss approximated  that of 1998. Such charges in 1999 totaled  $4,044,000 which,
after being tax effected, reduced net earnings by $2,790,000, or $0.72 per share
which thereby created a net loss of $1,215,000,  or $0.31 per share. During 1998
exploration  charges of  $722,000  and  impairment  charges of  $3,482,000  were
primarily  responsible for the net loss of $1,235,000,  or $0.29 per share.  Low
crude oil prices during the 1998 fiscal year  contributed to the impairments and
essentially  eliminated drilling for crude oil production and reserves.  Average
shares  outstanding  for fiscal 1999 were only  3,898,000  compared to 4,194,000
last  year.  Discretionary  Cash Flow in 1999 of  $5,770,000  was 7% lower  than
1998's because of lower gross revenues and oil and gas sales.

     As of the  end of  1999,  shareholders'  equity  decreased  to  $12,798,000
compared to $15,264,000 at November 30, 1998 as a result of the  exploration and
impairment  charges along with repurchases of treasury shares.  Positive working
capital was  $1,169,000  at year end which,  when  combined  with the  Company's
anticipated cash flow for 2000, should provide  sufficient funds for the capital
expenditure program during fiscal 2000 which will continue to be directed toward
onshore exploratory  drilling in the lower Gulf Coast area including activity on
existing El Squared prospect  leaseholds.  The unused portion of the $10,000,000
bank credit  facility has previously  been primarily  targeted by management for
acquisitions of oil and gas properties,  but can be used for any legal corporate
purpose and also is  available  should  unforeseen  capital  expenditures  arise
during 2000 as a result of exploratory success.



                                       26
<PAGE>


    Generally accepted  accounting  principles  ("GAAP") require cash flows from
operating  activities  to be determined  after giving effect to working  capital
changes.  Accordingly,  GAAP's net cash provided from  operating  activities has
fluctuated widely from $3,300,000 to $8,600,000 during the last three years but,
when  coupled  with  use  of  the  Company's  credit  facility,  still  provided
sufficient   liquidity   to  fund  those  three   years'  oil  and  gas  capital
expenditures,  treasury share  repurchases,  and limited purchases of fractional
working interests in existing properties.

    As regularly noted in prior reports, management places greater reliance upon
an important  alternative method of computing cash flow which is generally known
as  Discretionary  Cash Flow ("DCF").  DCF is not in accordance with GAAP but is
commonly used in the industry as this method calculates cash flow before working
capital  changes or deduction of  exploration  expenses  since the latter can be
increased  or  decreased  at  management's  discretion.  DCF is  often  used  by
successful  efforts  companies  to compare  their cash flow  results  with those
independent  energy  companies  who use the full cost  accounting  method  where
exploration  expenses are capitalized and do not  immediately  adversely  affect
either  operating  cash  flow  or net  earnings.  Columbus'  DCF  for  1999  was
$5,770,000   which  compared  to  1998's   $6,192,000   when  more  shares  were
outstanding.  DCF is calculated  without debt retirement being considered but in
Columbus'  case this does not matter as current bank debt  requires no principal
payments  before  August 1, 2001.  Interest  expense is always  deducted  before
arriving at DCF.

    Management  notes in each of its  public  filings  and  reports  its  strong
exception  to the  Statement  of  Financial  Accounting  Standards  No. 95 as it
applies  to  Columbus  which  directs  that  operating  cash  flow  must only be
determined after  consideration of working capital changes.  Management believes
such a  requirement  by GAAP ignores  entirely the  significant  impact that the
timing of income  received for, and expenses  incurred on behalf of, third party
owners  in  properties  may  have  on  working  capital.  This  is  particularly
significant  where  Columbus  owns  only a  small  working  interest  but is the
operator.

    Neither  DCF nor  operating  cash flow  before  working  capital  changes is
allowed to be substituted  for net income or for cash available from  operations
as defined by GAAP. Furthermore, currently reported cash flows, however defined,
are not  necessarily  indicative  that  there will be  sufficient  funds for all
future  cash  requirements.  For 1999 and 1997 GAAP cash flow was lower than DCF
and for 1998 it was the opposite.



                                       27
<PAGE>



    At the present time the Company has  partially  hedged its crude oil prices.
Therefore, the Company's natural gas revenues are fully exposed and a portion of
its crude oil  revenues  are  exposed to risk of very low prices such as existed
during fiscal 1998 and 1999's first half.

    Columbus  periodically  hedges  both  natural  gas and crude  oil  prices by
entering into "swaps".  The swap is matched against the calendar monthly average
price on the NYMEX and settled monthly.  Revenues were decreased when the market
price at  settlement  exceeded  the contract  swap price or  increased  when the
contract swap price exceeded the market price.  There was no hedging activity in
fiscal 1998. The following table shows the results of these swaps:

<TABLE>
<CAPTION>
                                                        Increase (decrease) in
                                                         oil and gas revenues
                        Volume                          ----------------------
Description             per mo.          Period           1999          1997
-----------             -------          ------           ----          ----
<S>                 <C>                <C>          <C>            <C>
                    (Mmbtu or bbl)

Natural Gas
-----------
$2.20/Mmbtu               60,000        3/97-10/97                   $(86,400)

Crude Oil
---------
Collar with $17.50/
  bbl floor and
  $22.25/bbl ceiling       7,500        9/99- 8/00      $(34,000)
$21.17/bbl                10,000       11/96-10/97                   $  8,900
$17.25/bbl with
  $19.50/bbl cap          10,000        1/96-12/96                   $(22,500)
</TABLE>

      The  Company's  natural gas and crude oil swaps are  considered  financial
instruments  with  off-balance  sheet risk which are entered  into in the normal
course of business to partially reduce its exposure to fluctuations in the price
of crude oil and natural gas. Those  instruments  involved,  to varying degrees,
elements  of market and credit  risk in excess of the amount  recognized  in the
balance sheets.

      The Company had a crude oil hedge  outstanding  as of November 30, 1999 by
using a costless  "collar"  on 7,500  barrels  per month for the 12 months  from
September 1, 1999  through  August 31, 2000.  This  "collar" is settled  monthly
against the calendar monthly average price on the NYMEX with a $17.50 per barrel
floor and $22.25 per barrel ceiling.  For any average price below or above those
prices Columbus  receives or pays the difference  which increases or reduces oil
revenues each month in which this occurs.  For the two months of December,  1999
and January,  2000,  oil sales would have been $65,000  higher if this hedge had
not been in place because oil prices exceeded the $22.25 ceiling price.  For the
remaining  period of February  through August 2000 using the prevailing price as
of January  31, 2000 for each of the months,  the  settlement  value the Company
would owe is $158,000 which would also reduce crude oil sales.



                                       28
<PAGE>



      Columbus had outstanding  borrowings of $5,500,000 as of November 30, 1999
against its $10,000,000  line of credit with Norwest Bank Denver,  N.A. which is
collateralized  by its oil and gas properties.  At the end of 1999, the ratio of
net long-term debt (debt less working capital) to shareholders'  equity was 0.34
and to total assets was 0.19. The  outstanding  debt used a LIBOR option with an
average interest rate of 7.0%.  Subsequent to year end through January 31, 2000,
the debt was increased by $200,000 to $5,700,000. The net increase (or decrease)
in long-term debt directly  affects cash flows from  financing  activities as do
the purchase of treasury shares and proceeds from the exercise of stock options.
For the  Company's  floating rate debt,  interest rate changes  generally do not
affect the fair market value but do impact future results of operations and cash
flows,  assuming  other factors are held  constant.  The carrying  amount of the
Company's debt approximates its fair value.

      Working capital at 1999 year end remained positive at $1,169,000  compared
to  $1,556,000  at  November  30,  1998.  This  was  achieved   despite  capital
expenditures  of $2,153,000 for additions to oil and gas  properties  along with
record  exploration  expenses plus purchase 300,538 shares of treasury stock for
$1,836,000 during the year.

      The Company has been  authorized  by its Board of Directors to  repurchase
its common  shares  from the market at various  prices  during the last  several
years. Those repurchases are summarized as follows:

                             Number of Shares
       Fiscal year     ---------------------------    Average
       repurchased     As purchased      Restated*     price*
       -----------     ------------      ---------    -------
          1997            158,000         197,863      $6.92
          1998            352,750         357,715      $7.07
          1999            300,538         300,538      $6.08

       *Restated for stock split and stock dividends

      As of November 30, 1999 a total of 73,384 shares  remained to be purchased
from the most  recent  authorizations  to  repurchase  shares  at a price not to
exceed  $6.00 per share.  As of January 31,  2000,  45,000 of those  shares have
subsequently been acquired at an average price of $5.61 per share.

      During  1999,  capital  expenditures  actually  incurred  for  oil and gas
properties totaled $2,153,000  (excludes costs of exploratory dry holes included
in exploration  expense) which amount differs from the capital expenditure shown
in the  Consolidated  Statement  of Cash Flows.  The latter also  includes  cash
payments made during 1999 for 1998 expenditures  incurred but not yet paid as of
1998's year end.  Similarly,  there were expenditures  accrued in 1999 that will
not be actually paid until 2000. These were primarily related to the exploratory
program in the Texas Gulf Coast area.



                                       29
<PAGE>



      Impact  of the Year  2000  issue.  The Year  2000  issue is the  result of
computer  programs  being  written  using two digits  rather than four, or other
methods,   to  define  the  applicable   year.   Computer   programs  that  have
date-sensitive  software may recognize a date using "00" as the year 1900 rather
than the year  2000 and  could  result in a system  failure  or  miscalculations
causing  disruptions  of  operations  such as a temporary  inability  to process
transactions, transmit invoices or engage in similar normal business activities.

      The Company  upgraded its major system computer  software in 1997 to a new
release of a major  software  vendor that the vendor  represented  was compliant
with the year 2000.  Columbus completed before year-end 1999 its review of other
less important  systems as well as its significant  suppliers,  purchasers,  and
transporters  of oil and gas to determine  the extent to which the Company might
be vulnerable to other failures and what the impact might be on its operations.

      The  Company's  interest  in wells  operated  by other  companies  was not
considered  to be as important  but  management  attempted to determine if those
companies  were ready for the year 2000.  The Company uses outside  services for
payroll and medical benefits  processing and those companies provided updates to
their software that they  represented  were year 2000 compliant.  The Company is
also somewhat dependent upon personal  computers as well as certain  spreadsheet
and word  processing  software  programs  which  may not  have  been  year  2000
compliant.  Evaluations  were  made to  establish  which of those  systems  were
critical and a few personal  computers and software  programs were replaced at a
cost of less than $10,000.

      The Company also relies on  non-information  technology  systems,  such as
office telephones,  facsimile machines, air conditioning,  heating and elevators
in its leased office space,  which may have  embedded  technology  such as micro
controllers and are generally outside of its control to assess or remedy.

      As  previously  disclosed,  the major  system  computer  software  upgrade
performed  in 1997 cost $16,000 and personal  computer  upgrades  cost less than
$10,000. This represented the costs required to meet the Company's goal of being
year 2000 ready for  mission-critical  systems. The Company did not believe that
any loss of  revenue  would  occur as a result  of the year  2000  problem.  The
Company did not  established  a  contingency  plan because it believed all major
issues had been addressed.

      As of the  date of this  report  in the  year  2000  the  Company  has not
experienced  any year 2000  failures or problems that have affected its computer
systems, operations, revenues, benefits processing or non-information technology
systems. Should any year 2000 failures occur we will address them at that time.



                                       30
<PAGE>



Results of Operations

      The  Company's  1999 gross  revenues of $11.5 million were 5% below 1998's
and was  attributable to lower sales volumes because higher prices were received
for both natural gas and crude oil. The Company's  1998 gross  revenues of $12.1
million were 20% below 1997's primarily  because of significantly  lower prices.
During  1998 low crude oil prices  resulted in over  one-half  of the  Company's
operated wells in the Williston  Basin being  uneconomic  which were either shut
down or operated  only a few days each month and this  continued  during  1999's
first half.

       The operating loss in 1999 was almost entirely due to record  exploration
expense charges and  impairments of $4,044,000  because gross revenues were only
slightly lower than 1998's. Lease operating costs, depreciation and amortization
and general and  administrative  expenses were all lower.  The operating loss of
$1,706,000 in 1998 was a direct result of a significant increase in impairments,
lower  revenues  due  to  prices  plus  higher  lease  operating   expenses  and
exploration  costs  compared with 1997.  Operating  income of $3,766,000 in 1997
represented an  improvement  of only 5% over 1996 and excluding the  exploratory
charges and impairment provisions, this would have been a 59% improvement.

      The 1999 net loss of  $1,215,000  was  caused  by the  factors  previously
discussed as well as increased  interest and  litigation  expense.  The 1998 net
loss of $1,235,000 was primarily attributable to the impairment expense although
all of the factors previously discussed contributed to this result. Net earnings
during  1997 set a new high  from  U.S.  only  operations  of  $2,167,000  which
surpassed  1996 earnings of  $2,098,000.  Had there not been the extremely  high
non-cash  impairment  provisions  during 1997,  record net  earnings  would have
surpassed earlier years' results which also included Canadian operations.














                                       31
<PAGE>



Impairments

      The 1999 pre-tax,  non-cash  impairment loss of $973,000 included $503,000
that was recorded  during the second quarter with the balance added at year end.
The initial improvement in crude oil prices toward the end of the second quarter
was insufficient at that time to justify  restoration of previously written down
proved undeveloped reserves in one of the Williston Basin's cost pools which had
led to that pool's  impairment  charge equal to a shortfall of $253,000  between
remaining  book  value of the  pool and the  current  fair  market  value of its
reserves.  Elsewhere,  an unexpected influx of water in natural gas wells in the
shallow  Heidi  property in Jim Wells  County,  Texas  brought  about  premature
abandonment  of  producing  zones and  associated  natural  gas  reserves.  This
contributed a pre-tax, non-cash impairment of $250,000 of the mid-year charge.

      As of 1999's  fiscal year end, an  impairment of $270,000 was recorded for
one  successful  efforts  pool in Texas where a  significant  reduction in total
reserve  quantities  and  future  net  cash  flows  became  evident  due  to its
producing/pressure  performance.  Also,  there was a charge of  $200,000  for an
anticipated loss in value of undeveloped acreage following exploratory dry holes
at the El Squared project and in Oklahoma.

      During  fiscal  1998,  the  non-cash  impairment  loss of  $3,482,000  was
recognized  during the first and fourth  quarters with  provisions of $2,816,000
and $666,000  respectively.  The primary  cause for each was the  continued  low
crude oil prices which had showed signs of recovery on occasions  throughout the
year  but had  again  retreated  to the lows by year  end.  This  resulted  in a
significant  reduction for total reserve  quantities  which are based on the SEC
calculation  method  using  constant  prices.  Therefore,   carrying  values  of
remaining  unamortized  costs in several  successful  efforts pools continued to
exceed  resultant  undiscounted  future net cash flows even if determined  using
somewhat  higher  crude  prices  than were  currently  being  realized.  Several
property pools were initially written down as of the end of the first quarter to
a fair value based on an assumption that the average future crude oil price over
the life of reserves would be $18.75 per barrel,  which was subsequently lowered
to $14 at year end based on bearish  longer term  sentiments  expressed  by many
noted experts.  The actual $11.50 year-end price calculation  eliminated certain
proved  undeveloped  locations as no longer being economic and further shortened
the economic  productive life and reserves of most oil wells.  Using a $14 price
over the life of the reserves still required an additional  non-cash  impairment
for the 1998 fourth quarter of $666,000.





                                       32
<PAGE>


      A $400,000  charge in 1998 which was provided during the first quarter was
for probable loss in value of undeveloped acreage and abandonments of leaseholds
located  primarily  in  Louisiana.  This was in addition  to $200,000  similarly
reserved in 1997. A Louisiana  Austin Chalk  horizontal  well, the Morrow #23-H,
had reserves originally assigned to a contemplated extension of the then current
downdip  lateral.   However,   those  reserves  were  eliminated  by  price  and
performance  which  contributed  heavily to the first quarter  provision.  Also,
because of added costs related to the necessary  recompletion  workover required
to place the updip lateral on production,  this operation was deferred. Although
economic at a $14 per barrel crude oil price,  such a recompletion was postponed
for a  minimum  of two more  years in  anticipation  that  better  prices  would
favorably  alter the present worth of those  reserves.  This  circumstance  also
contributed to the fourth quarter provisions.

      The  non-cash  impairment  loss of $243,000  for 1997 was  recognized  for
certain  Oklahoma  development  oil and gas wells completed in prior years which
had become marginal.  During the third quarter of 1997,  despite the fact that a
production test of the Morrow #23-1H had not yet occurred, management also chose
to write off as impaired certain small leaseholds within the acreage block where
the possibility of putting together a drilling unit before  expiration  appeared
rather remote.  Also included were certain  leaseholds where annual rentals were
already due or about to become due. Those non-cash write downs equaled  $251,000
which brought the total impairment provision during the third quarter of 1997 to
$494,000.

      As  fiscal  1997  ended,  it  had  become  apparent  that  with  continued
increasing  water cuts, the Morrow #23-1H's oil production  rates would probably
be less than the initial  potential  tests had  indicated.  Accordingly,  1997's
year-end proved reserves attributable to both horizontal legs were reduced which
created  additional  impairment  charges of $1,140,000 related to that Louisiana
well and $84,000 to related  leaseholds.  Also, a general  provision of $200,000
against all undeveloped leaseholds was recorded in anticipation that it was very
likely that  additional  development  probably  could not be completed  prior to
lease expirations. Also, two oil wells in Oklahoma failed to respond to attempts
to eliminate shifting frac sand from halting production. These were charged with
additional  impairment of $260,000 of the total 1997 year end amount even though
the wells had not been abandoned  permanently.  Another attempt at production is
expected during fiscal 2000 when better crude prices are available which support
drilling  horizontally  to reduce  the  shifting  frac sand and  formation  sand
problem since a potentially profitable oil reservoir is believed to exist.



                                       33
<PAGE>


Oil and Gas Operations

      The following  discussion of the Company's oil and gas operations is based
upon the tables of production and average prices shown under the caption Item 2,
"Oil and Gas Properties" and "Production".

      The changes in the  components of oil and gas revenues  during the periods
presented are summarized as follows:

                                                Production
                             Price Change    Quantity Change     Revenue Change
                             ------------    ---------------     --------------
1999 vs. 1998
      Gas                        5 %                (9)%                (6)%
      Oil                       26 %               (24)%                (5)%

1998 vs. 1997
      Gas                      (18)%                 4 %               (14)%
      Oil                      (33)%               (11)%               (40)%

      Natural gas  revenues for fiscal 1999  compared to 1998  decreased 6% as a
result of a 9%  decrease  in  production  and  despite a 5%  increase in average
prices.  Average gas prices  improved from somewhat  depressed 1998 prices which
had  resulted  from a warm winter and a high level of  inventory of storage gas.
Production  volumes for 1999  decreased as a result of  production  declines not
fully offset by production  from newly  completed  development  wells and from a
lack of exploratory successes.

      Oil revenues for 1999 were down 5% from 1998 as a result of a 26% increase
in the average price received because sales volumes were 24% lower. Oil revenues
and average  prices for 1999 were also reduced by $34,000  ($.20 per barrel) due
to hedging  activity  while no oil hedges  existed in 1998.  Oil  production has
declined  steadily  commensurate  with a lack of development  drilling  activity
because of depressed oil prices.  However,  one  exploratory  oil well in Harris
County,  Texas,  drilled  during 1998,  was finally  hooked-up to a gas line and
commenced  flowing  200 barrels  per day with  associated  gas during June 1999.
Columbus owns a 19.5% working interest.

      Columbus'  1999 sales  volumes of natural gas  averaged  8,751 Mcf per day
while oil and liquids  sales  declined to 456 barrels per day.  This  equates to
daily  production  of 1,915 barrels of oil  equivalent  (BOE) which was down 14%
from the record 2,223 BOE during 1998.

      A ratio of oil versus natural gas production  during 1999 reveals that the
Company now realizes  approximately 76% of its production from natural gas. Such
a high  percentage is in keeping with  expected  results  commensurate  with the
change in emphasis by management  during the last several years toward exploring
for and developing natural gas reserves.



                                       34
<PAGE>



      Natural gas revenues for 1998  decreased 14% compared to 1997 primarily as
a result of lower prices which more than offset improved gas production from new
wells in the Texas Gulf Coast area. These new discoveries had mitigated a normal
annual  production  decline  plus the sale of a Berry R. Cox field  property  in
Texas  during  fourth  quarter  1997.  Average  prices for  natural  gas in 1998
decreased  18%  compared to 1997 as a result of reduced  demand from both a warm
winter and the  highest  percentage  of storage  refill ever  accomplished.  Gas
revenues for 1997 were  reduced by $86,400  ($.03 per Mcf) from swaps of natural
gas.

      Oil  revenues  for 1998  versus 1997 were down by a  significant  40% as a
result of a  substantial  33%  decrease in the average  price along with a lower
sales volume of 11% which  reflected a very sharp decline related to a 90%-owned
Montana oil well.  This well had been  recompleted  in a new zone uphole  during
1997's third quarter and  contributed  most of its initial flush  production for
the last few months of that year.  Furthermore,  during  1998's  third  quarter,
several oil wells which had been  marginal  because of low prices were shut down
and any  well  which  had  pump or  tubing  problems  was not  repaired  nor any
workovers  performed.  Unfortunately  no crude oil swap  existed  during 1998 to
offer  protection  from that price  debacle  because  one was in place  during a
portion of 1997 when prices were high which reduced  revenues.  Oil revenues for
1997 were decreased by $13,600 ($.06 per barrel) from crude oil swaps.

      U.S. oil prices have fluctuated for several years similar to the same wide
swings experienced in world crude oil prices.  From the beginning of 1997, world
and U.S. crude oil prices  steadily  softened from almost $23.00 per barrel with
the decline  continuing  unabated  throughout fiscal 1998 and reached a year end
price of $11.50 per barrel. Crude oil prices finally began to show recovery late
in 1999's second quarter and have since accelerated  during the third and fourth
quarters reaching approximately $26.00 per barrel by year-end.

      Lease  operating  expenses for 1999 were 11% lower than 1998's.  Expensive
workovers  and  replacements  of downhole  and surface  equipment on older wells
occurred  earlier in 1998 while  several of those older wells  remained  shut-in
during 1999's first half.  Lease operating  expenses  increased 16% in 1998 over
1997 because of expensive  workovers  along with downhole and surface  equipment
replacements  on several older wells.  Lease  operating costs on a barrel of oil
equivalent basis for 1999 approximated $2.72 compared to $2.63 in 1998 and $2.27
for 1997.  Operating costs as a percentage of revenues were 19% in 1999 compared
to 20% in 1998 which had both lower unit  prices and higher  costs.  During 1997
costs  were only 13% due to  increased  production  and  commodity  prices  when
compared with 1998 or 1999.

      Production  and property  taxes  approximated  10% of revenues in 1999 and
1998 and 9% of revenues in 1997. These vary based on Texas'  percentage share of
the total  production  where oil tax rates  are lower  than gas tax  rates.  The



                                       35
<PAGE>



relationship  of taxes and  revenue is not always  directly  proportional  since
several  of the local  jurisdiction's  property  taxes are  based  upon  reserve
evaluations as opposed to revenues  received or production rates for a given tax
period.

Operating and Management Services

      This segment of the  Company's  business is comprised  of  operations  and
services  conducted on behalf of third parties including  compressor rentals and
salt water disposal  facilities.  Operating and management  services revenue has
increased in each of the last three years.

      Operating  and  management  services  profit  was  $502,000  for  1999  up
substantially  from the $276,000  for 1998 and the  $349,000 for 1997.  The 1999
profit  benefited from an increase in operated wells plus an ownership  increase
from 50% to 100% in four  compressors  operating in South Texas although profits
therefrom were adversely affected by significant compressor repairs. During 1999
the  Company's  contract  operator  services in the B. R. Cox field  contributed
$100,000 to  operating  and  management  services  income and profit but this is
expected to be terminated in fiscal 2000.  The 1998 profit was lower as a result
of unusually  high 1998  workover  expenses  required to clean out sand from the
well bore of a salt water  disposal  well in Texas  although  1998's second half
revenue did show  improvement  with the increase in well activity along with the
aforementioned increased ownership interest in the four compressors.

Interest Income

      Interest  income is earned  primarily from  short-term  investments  whose
rates  fluctuate with changes in the commercial  paper rates and the prime rate.
Interest  income  declined in 1999 to $100,000  compared to 1998's $141,000 as a
result of reduced  short-term  interest rates and a lower amount of investments.
Likewise 1998 was lower than the $147,000 for 1997 for the same reasons.

General and Administrative Expenses

      General  and  administrative  expenses  are  considered  to be those which
relate to the direct costs of the Company which do not originate  from operation
of properties  or providing of services.  Corporate  expense  represents a major
part of this category.

      The Company's  general and  administrative  expenses for 1999 were 9% less
than last year and would  have been  even  greater  except  for total  phase out
during  the second  quarter of 1999 of  reimbursement  for  management  services
provided  Resources.  This had the  effect  of  increasing  costs by the  amount
credits of $33,000 for 1999 were lower than $218,000 for 1998.  Salary  expenses
were  comparable  in 1999 and 1998  because  increases  were  granted  effective
December 1, 1998 for  non-officer  employees  while  officer  salaries  remained



                                       36
<PAGE>



unchanged  and  incentive  compensation  and bonuses were reduced in 1999.  Such
bonuses are  discretionary  and directly  related to the  Company's  performance
during a prior year. These amounted to only $80,000 ($58,000 non-cash) for 1999.
Higher  medical  claims in 1999 under the  Company's  self-insured  plan  raised
expenses.  A one-time  charge for a  retirement  pay  accrual  of  $111,000  was
approved  by the Board of  Directors  during  1999 for one  officer and has been
reported as a separate line item.

      One of the  Company's  working  interest  owners is now  disputing its 25%
participation in the Long #4 well in Texas after paying $90,000 of approximately
$300,000 of its share of drilling  costs.  This  dispute came after the well was
determined to be a dry hole. In the Company's  opinion,  the claim is groundless
but in the short-  term will  affect the  collectability  of its joint  interest
receivable.

      The Company's general and administrative  expenses for 1998 were 7% higher
than fiscal 1997 due primarily to higher medical claims and increased  incentive
bonuses which totaled $273,000  ($153,000  non-cash) as of May, 1998 compared to
$220,000  ($70,000  non-cash)  in May,  1997.  Also,  some 1998  cost  increases
resulted  from  salary  adjustments  granted  effective  December  1,  1997  for
non-officer  employees as well as the May 1, 1998 raises for  officers.  Medical
claims  under  the  Company's  self-insured  plan vary from year to year with no
discernible  pattern. For 1998 legal and accounting expenses decreased from 1997
which had included  costs related to a registration  statement  filing which was
canceled.

      Reimbursement for services provided by Columbus officers and employees for
managing  Resources  and  providing  services has had the net effect of reducing
overall general and administrative  expenses. These amounted to $33,000 in 1999,
$218,000 for 1998 and $255,000 for 1997.

Depreciation, Depletion and Amortization

      Depreciation,  depletion  and  amortization  of oil  and  gas  assets  are
calculated  based upon the units of production for the period compared to proved
reserves of each  successful  efforts  property  pool.  This expense is not only
directly  related to the level of  production,  but also is dependent  upon past
costs to find, develop and recover related reserves in each of the cost pools or
fields.  Depreciation and amortization of office equipment and computer software
is also included in the total charge.

      Total charges for depletion  expense for oil and gas  properties was lower
in  1999  compared  to  1998 as a  result  of  decreased  units  of  production,
especially   in  higher  rate  pools,   and   despite   additional   development
expenditures.  This expense item for 1998 was higher than in 1997 as a result of
increased production plus added development  expenditures during the intervening
period and a reduction in reserves in several cost pools.



                                       37
<PAGE>


      During  1999 the  depletion  rate was $4.69 per  barrel of oil  equivalent
("BOE") or $.79 per thousand cubic feet of gas equivalent  ("Mcfe")  compared to
1998's rate of $4.64 per BOE ($.77 per Mcfe).  The  depletion  and  depreciation
rate for fiscal 1998  increased  over 1997 because of 1998's  reduced  crude oil
reserves in certain cost pools and an exceptionally  low $3.91 per BOE ($.65 per
Mcfe) recorded for fiscal 1997.

      Effective October 1, 1997 the Company sold fractional working interests in
seven wells in the Berry Cox field in Texas for cash proceeds of $750,000. These
wells were a part of a larger pool of properties in the general  Laredo area and
so those sale proceeds reduced the carrying costs of the successful efforts pool
and no book gain or loss was recognized.

Exploration Expense

      In  general,  the  exploration  expense  category  includes  the  cost  of
Company-wide   efforts  to  acquire  and  explore  new  prospective  areas.  The
successful  efforts  method of accounting  for oil and gas  properties  requires
expensing  the costs of  unsuccessful  exploratory  wells  including  associated
leaseholds.  Other exploratory charges such as seismic and geological costs must
also be  immediately  expensed  regardless  of whether a prospect is  ultimately
proved to be  successful.  All such  exploration  charges not only  decrease net
earnings but also reduce  reported  GAAP cash flow from  operations  even though
they are  discretionary  expenses;  however,  such  charges  are added  back for
purposes  of  determining  DCF  which is why it more  nearly  tracks  cash  flow
reported by full cost accounting companies which capitalize such costs.

      Exploration charges of $3,071,000 for 1999 were a record and far in excess
of 1998's  $722,000.  Costs for 1999 included  $1,443,000 to initially drill and
eventually deepen the Long #3 exploratory well in the El Squared  prospect.  The
Long #3 wellbore had drilling ceased and was abandoned in January 2000 for yet a
second time when the Long #4 well failed to find commercial natural gas reserves
in the upper  Massive  zone of the  middle  Wilcox.  Long #4 well dry hole costs
totaled $911,000 as of year end which included associated  leaseholds which were
also  expensed.  Seismic  interpretation  costs  of  $72,000  in the El  Squared
prospect in Texas were expensed.  During fiscal 1999 an additional  $453,000 was
expensed for  participation in five other  exploratory dry holes.  Subsequent to
fiscal  year end about  $1,200,000  was  further  incurred  while  drilling  and
eventually  abandoning the Long #3 and #4 wells.  This amount will be recognized
as an exploration expense during first quarter of fiscal year 2000.



                                       38
<PAGE>


      Whenever a company using the  successful  efforts  method of accounting is
involved in an  exploratory  program that  represents a significant  part of its
budget,  it is  automatically  subjected  to the risk that net  earnings for any
given  quarter or year will be impacted  negatively  by wildcat  dry holes.  The
numerous  exploratory  well bores involved at Columbus' El Squared Prospect that
have  already  been or will be required to be drilled to properly  evaluate  the
various  fault blocks and/or  potential  producing  horizons  certainly fit that
circumstance.  Shareholders have been forewarned that net earnings and GAAP cash
flow may not be truly indicative of the Company's operational activity.  This is
why management  suggests that shareholders may wish to follow its own assessment
of placing  more  emphasis  on DCF from year to year and  ignore  net  earnings.
Comparing  EGY's  results with other  company's  net earnings or cash flows when
they use the full cost accounting  method is unrealistic and ill advised because
they capitalize such exploratory costs.

      Exploration  expense for 1998 of $722,000  included  two  exploratory  dry
holes in the S.E. Froid area in Montana where $209,000 was expensed while in the
Texas Gulf Coast area a second dry hole cost $142,000.  No exploratory oil wells
could be justified  during 1998 on any of its 3-D seismic  structures  mapped on
its Williston  Basin  leasehold  blocks in Montana until crude oil prices showed
significant  improvement.  Early in 1998 3-D seismic  costs of $135,000 had been
incurred in this area in anticipation there would be an improvement in crude oil
prices during the year and before leasehold expirations occurred during 1999.

      Exploration charges for 1997 were $540,000. These included $224,000 of 3-D
seismic costs incurred in the S.E. Froid area in Montana in an attempt to locate
new exploratory  well sites plus $73,000  incurred for drilling a non-commercial
exploratory oil well.

Litigation Expense

      The  litigation  expense in 1999 and 1998 relates to the Maris E. Penn, et
al lawsuit previously described.

Interest Expense

      Interest  expense  varies in direct  proportion to the amount of bank debt
and the level of bank interest  rates.  The average amount  outstanding has been
higher during 1999 than in 1998. The average bank interest rate paid for debt in
1999, 1998 and 1997 was 6.6%, 7.1%, and 7.1%, respectively.



                                       39
<PAGE>



Income Taxes

      The  Company's  income tax  position is complex.  The  utilization  of net
operating loss  carryforwards by the Company has been complicated by two "change
of ownership"  transactions  under Section 382 of the Internal Revenue Code, one
of which occurred on October 1, 1987 and the other on August 25, 1993.  Only the
first of those  changes  has  limited  the  utilization  of net  operating  loss
carryforwards.  Furthermore, a quasi-reorganization occurred on December 1, 1987
which requires that benefits from net operating loss  carryforwards or any other
tax  credits  that  arose  prior  to the  quasi-reorganization  be  credited  to
additional paid-in capital rather than to income. Only post quasi-reorganization
tax benefits realized can be credited to income.

      As a result of available net operating loss  carryforwards,  the Company's
Federal income tax obligations have been limited to "alternative minimum tax" so
that the Company has had current  Federal and state taxes payable of 2% to 3% of
pre-tax  earnings.  For use in fiscal 1999, the Company has a net operating loss
carryforward from 1995 and operating loss  carryforwards  remaining from periods
prior to the Section 382 ownership changes. Utilization of those latter benefits
are  limited  to  $1,707,000  for fiscal  1999,  which  expire if not used,  and
$904,000 in fiscal 2000. The significant  exploration costs incurred during 1999
and first  quarter of fiscal 2000 will reduce  taxable  income and may result in
net operating  losses expiring before they are utilized.  The Company's  current
Federal tax provision and liability  might  increase after fiscal 2000 unless an
active  drilling  program is  maintained.  In  addition,  the Company pays state
income taxes in some states.

      During 1999, the net deferred tax asset increased to $1,137,000  which was
comprised  of $200,000  current  portion  and  $937,000  long- term  asset.  The
valuation  allowance  had a net  reduction of $122,000 from 1998 to November 30,
1999. A deduction  of $12,000 for the benefit of  disqualifying  disposition  of
incentive stock options was added to additional paid-in capital.

      During 1998, the net deferred tax asset was $210,000 and is comprised of a
$327,000 current portion and a $117,000  long-term tax liability.  The valuation
allowance  was  decreased  by a net  $35,000.  A deduction  of $156,000  for the
benefit of stock options that were  exercised  was added to  additional  paid-in
capital.



                                       40
<PAGE>



New Accounting Pronouncements

     In June 1999,  the FASB issued SFAS No. 137 which  deferred  the  effective
date for SFAS No.  133,  "Accounting  for  Derivative  Instruments  and  Hedging
Activities,"  to fiscal years  beginning  after June 15, 2000.  The Company must
apply this statement no later than its fiscal year  beginning  December 1, 2000.
SFAS No.  133  requires  recording  all  derivative  instruments  as  assets  or
liabilities measured at fair value. This Statement is not expected to materially
affect the Company's financial statements.

Effects of Changing Prices

      The United States economy  experienced  considerable  inflation during the
late 1970's and early 1980's but in recent  years has been fairly  stable and at
low levels. The Company,  along with most other U.S. business  enterprises,  was
then and could again be adversely  affected by any  recurrence  of such economic
conditions  although  in  general,  inflation  has had a  minimal  effect on the
Company.

      In recent years, oil and natural gas prices have fluctuated  widely so the
Company's results of operations and cash flow have been  inordinately  affected.
Oil and gas prices have also been  somewhat  influenced by regulation by various
governmental  agencies,  by the world economy, and by world politics.  Operating
expenses  have been  relatively  stable but,  when  analyzed as a percentage  of
revenues,  may be distorted  because they become a larger percentage of revenues
when lower  product  prices  prevail.  Drilling and  equipment  costs have risen
noticeably   in  the  last  three  years.   Competition   in  the  industry  can
significantly  affect the cost of acquiring leases,  although in the past decade
competition   has  lessened  as  more   operators  have  withdrawn  from  active
exploration  programs.  Inflation,  as well as a recessionary  period, can cause
significant  swings in the interest  rates the Company pays on bank  borrowings.
These factors are  anticipated  to continue to affect the Company's  operations,
both positively and negatively, for the foreseeable future.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

      The Company's  exposure to interest rate risk and commodity  price risk is
discussed in Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations under the heading  "Liquidity and Capital  Resources".
The Company has no exposure to foreign  currency  exchange  rate risks or to any
other market risks.



                                       41
<PAGE>



Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

      The  report  of  independent   accountants  and   consolidated   financial
statements  listed in the  accompanying  index are filed as part of this report.
See Index to Consolidated Financial Statements on page 46.

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

      None.






































                                       42
<PAGE>


                                    PART III

Items 10 and 11. DIRECTORS AND EXECUTIVE OFFICERS OF THE
                 REGISTRANT AND EXECUTIVE COMPENSATION

      A  definitive  proxy  statement  related  to the 2000  Annual  Meeting  of
Stockholders of Columbus Energy Corp. will be filed no later than 120 days after
the end of the fiscal year with the  Securities  and  Exchange  Commission.  The
information  set forth  therein  under  "Nominees  for  Election of  Directors,"
"Executive   Officers  of  the  Company,"  and   "Executive   Compensation"   is
incorporated herein by reference.

Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

       Information  required is set forth under the caption  "Voting  Securities
and  Principal  Holders  Thereof"  in the Proxy  Statement  for the 2000  Annual
Meeting of Stockholders and is incorporated herein by reference.

Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

       Information  required  is  set  forth  under  the  caption  "Election  of
Directors" in the Proxy  Statement for the 2000 Annual  Meeting of  Stockholders
and is incorporated herein by reference.














                                       43
<PAGE>



                                     PART IV

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

(a)    Financial statements and schedules included in this report:

          See "Index to Consolidated Financial Statements" on page 46.

       All schedules are omitted  since either the required  information  is set
       forth  in  the  financial  statements  or in  the  notes  thereto  or the
       information  called for is not present in the accounts or is not required
       under the exception stated in Rule 5.04.

(b)  Reports on Form 8-K:

       The following  reports on Form 8-K were filed on behalf of the Registrant
       since the third quarter of fiscal 1999:

          None

(c)  Exhibits:

Exhibit No.
-----------
* 3.1        Restated  Articles of Incorporation  and Amendments  thereto to
             date (Exhibit to Registration  Statement No. 33-17885,  Exhibit "a"
             to Form 10-Q dated July 13,  1990 and  Exhibit  3(1)(a) to Form 8-K
             dated May 11, 1995).

* 3.2        Amended By-Laws of Columbus Energy Corp. amended as of  May
             5, 1999 (Exhibit 3(b) to Form 8-K dated May 5, 1999).

*10.1        Amended and Restated  Credit Agreement dated as of October
             23, 1996 between  Columbus  Energy Corp. and Norwest Bank
             Denver, National Association  (Exhibit 10(a) to Registration
             Statement No. 333-19643 dated January 13, 1997).

*10.2        First Amendment of Credit Agreement dated September 8, 1998
             between Columbus Energy Corp. and Norwest Bank Colorado,
             National Association (Exhibit 10(a) to Form 10-Q dated
             August 31, 1998).

*10.3        Second Amendment of Credit Agreement dated October 6, 1998
             between Columbus Energy Corp. and Norwest Bank Colorado,
             National Association (Exhibit 10(b) to Form 10-Q dated
             August 31, 1998).

*10.4        Third Amendment of Credit Agreement dated May 12, 1999
             between Columbus Energy Corp. and Norwest Bank Colorado,
             National Association (Exhibit 10.1 to Form 10-Q dated May
             31, 1999).



                                       44
<PAGE>


*10.5        1993 Stock Purchase Plan (Exhibit to Registration Statement
             No. 33-63336).

*10.6        1995 Stock Option Plan (Exhibit 10(k) to Form 8-K dated May
             11, 1995).

*10.7        1985 Stock Option Plan (Exhibit to Registration Statement
             No. 33-17885).

*10.8        1985 Stock Option Plan, Amendment No. 2 dated November 7,
             1991 (Exhibit 10(h) to Form 10-K dated November 30, 1991).

*10.9        Separation  Pay Policy  adopted  December 1, 1990 for  officers and
             employees and as amended  February 17, 1992 (Exhibit  10(i) to Form
             10-K dated November 30, 1991).

*10.10       Form of Indemnity Agreements with directors (Exhibit 10(k)
             to Registration Statement No. 33-46394).

 22          Subsidiaries of the Registrant.

 23.1        Consent of PricewaterhouseCoopers LLP.

 23.2        Consent of Reed W. Ferrill & Associates, Inc.

 27          Financial Data Schedule

---------------
*Incorporated by reference













                                       45
<PAGE>

                                               COLUMBUS ENERGY CORP.

                                    INDEX TO CONSOLIDATED FINANCIAL STATEMENTS





                                                                         PAGE
                                                                         ----
Report of Independent Accountants                                         47

Financial Statements:
   Consolidated Balance Sheets at
   November 30, 1999 and 1998                                             48

   Consolidated Statements of Operations for the
   years ended November 30, 1999, 1998 and 1997                           50

   Consolidated Statements of Stockholders'
   Equity for the years ended
   November 30, 1999, 1998 and 1997                                       51

   Consolidated Statements of Cash Flows for the
   years ended November 30, 1999, 1998 and 1997                           53

Notes to the Consolidated Financial Statements                            54
























                                       46
<PAGE>



                        Report of Independent Accountants



To the Board of Directors and
Stockholders of Columbus Energy Corp.


In our opinion,  the  accompanying  consolidated  balance sheets and the related
consolidated  statements  of  operations,  shareholders'  equity  and cash flows
present fairly,  in all material  respects,  the financial  position of Columbus
Energy Corp. and its subsidiaries at November 30, 1999 and 1998, and the results
of their  operations  and their  cash  flows for each of the three  years in the
period  ended  November 30,  1999,  in  conformity  with  accounting  principles
generally accepted in the United States. These consolidated financial statements
are the  responsibility of the Company's  management;  our  responsibility is to
express an  opinion  on these  consolidated  financial  statements  based on our
audits.  We conducted our audits of these statements in accordance with auditing
standards  generally  accepted in the United States,  which require that we plan
and  perform  the  audit  to  obtain  reasonable  assurance  about  whether  the
consolidated  financial statements are free of material  misstatement.  An audit
includes  examining,  on a test  basis,  evidence  supporting  the  amounts  and
disclosures in the consolidated  financial statements,  assessing the accounting
principles used and significant estimates made by management, and evaluating the
overall  consolidated  financial  statement  presentation.  We believe  that our
audits provide a reasonable basis for the opinion expressed above.






PricewaterhouseCoopers LLP
Denver, Colorado

February 17, 2000















                                       47
<PAGE>



                              COLUMBUS ENERGY CORP.

                           CONSOLIDATED BALANCE SHEETS

                                     ASSETS
                                     ------

                                              November 30,
                                       -------------------------
                                       1999                 1998
                                       ----                 ----
                                             (in thousands)


Current assets:
  Cash and cash equivalents            $ 1,850           $ 2,003
  Accounts receivable:
    Joint interest partners              1,780             1,570
    Oil and gas sales                    1,501             1,239
    Allowance for doubtful accounts       (116)             (116)
  Deferred income taxes (Note 5)           200               327
  Inventory of oil field equipment,
    at lower of average cost or market     106                95
  Other                                     80               106
                                       -------           -------

   Total current assets                  5,401             5,224
                                       -------           -------

Deferred income taxes (Note 5)             937                 -

Property and equipment:
  Oil and gas assets, successful
    efforts method (Notes 3 and 4)      36,862            36,039
  Other property and equipment           1,836             1,804
                                       -------           -------

                                        38,698            37,843

  Less:  Accumulated depreciation,
    depletion, amortization and
    valuation allowance
    (Notes 2 and 3)                    (22,506)          (19,118)
                                      --------           -------

    Net property and equipment          16,192            18,725
                                      --------           -------

                                      $ 22,530           $23,949
                                      ========           =======

                                                      (continued)





                                       48
<PAGE>



                              COLUMBUS ENERGY CORP.

                    CONSOLIDATED BALANCE SHEETS - (continued)

                      LIABILITIES AND STOCKHOLDERS' EQUITY
                      ------------------------------------

                                                 November 30,
                                             ----------------
                                             1999           1998
                                             ----           ----
                                                 (in thousands)


Current liabilities:
  Accounts payable                          $  2,352    $  1,846
  Undistributed oil and gas
    production receipts                          386         317
  Accrued production and property taxes          738         677
  Prepayments from joint interest owners         200         374
  Accrued expenses                               494         415
  Income taxes payable (Note 5)                   30           2
  Other                                           32          37
                                             -------      ------

    Total current liabilities                  4,232       3,668
                                             -------      ------

Long-term bank debt (Note 4)                   5,500       4,900
Deferred income taxes (Note 5)                     -         117

Commitments and contingent liabilities
  (Note 9)

Stockholders' equity:
  Preferred stock authorized 5,000,000
    shares, no par value; none issued             -           -
  Common stock authorized 20,000,000 shares
    of $.20 par value; 4,645,303 shares
    issued in 1999 and 4,611,001 in 1998
    (outstanding 3,800,558 in 1999 and
    4,046,552 in 1998) (Notes 1 and 7)           929         922
  Additional paid-in capital                  20,069      19,656
  Accumulated deficit                         (2,655)     (1,440)
                                             -------     -------
                                              18,343      19,138
Less:
    Treasury stock, at cost (Note 7)
      844,745 shares in 1999 and
      564,449 shares in 1998                  (5,545)     (3,874)
                                             -------     -------
        Total stockholders' equity            12,798      15,264
                                             -------     -------
                                             $22,530     $23,949
                                             =======     =======

The  accompanying  notes are an integral  part of these  consolidated  financial
statements.



                                       49
<PAGE>

                              COLUMBUS ENERGY CORP.
                      CONSOLIDATED STATEMENTS OF OPERATIONS

                                                   Year Ended November 30,
                                              --------------------------------
                                              1999        1998            1997
                                              ----        ----            ----
                                           (in thousands, except per share data)
Revenues:
  Oil and gas sales                         $10,014     $10,617         $13,815
  Operating and management
    services                                  1,386       1,336           1,176
  Interest income and other                     100         141             165
                                            -------     -------         -------
         Total revenues                      11,500       12,094         15,156
                                            -------      -------        -------

Costs and expenses:
  Lease operating expenses                    1,903        2,140          1,849
  Property and production taxes               1,029        1,080          1,258
  Operating and management

    services                                    884        1,060            827
  General and administrative                  1,336        1,466          1,372
  Depreciation, depletion and
   amortization                               3,400        3,846          3,295
  Impairments                                   973        3,482          2,179
  Exploration expense                         3,071          722            540
  Retirement and separation                     111            -              -
  Litigation expense                            119            4             10
  Loss on sale of assets                          -            -             60
                                            -------      -------        -------
     Total costs and expenses                12,826       13,800         11,390
                                            -------      -------        -------
     Operating income (loss)                 (1,326)      (1,706)         3,766
                                            -------      -------        -------
Other (income) expense:
  Interest                                      373          260            174
  Other                                          62           26             (4)
                                            -------      -------         ------
                                                435          286            170
                                            -------      -------         ------
         Earnings (loss) before
         income taxes                        (1,761)      (1,992)         3,596
  Provision (benefit) for income
     taxes (Note 5)                            (546)        (757)         1,429
                                            -------      -------         ------
            Net earnings (loss)             $(1,215)     $(1,235)       $ 2,167
                                            =======      =======        =======

Earnings (loss) per share (Note 8):
    Basic                                   $  (.31)     $  (.29)       $   .50
                                            =======      =======        =======
    Diluted                                 $  (.31)     $  (.29)       $   .49
                                            =======      =======        =======

Weighted average number of common and
common equivalent shares outstanding:
    Basic                                     3,898        4,194          4,299
                                            =======      =======        =======
    Diluted                                   3,898        4,194          4,392
                                            =======      =======        =======

The  accompanying  notes are an integral  part of these  consolidated  financial
statements.



                                       50
<PAGE>
                              COLUMBUS ENERGY CORP.
                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                   For the Three Years Ended November 30, 1999
<TABLE>
<CAPTION>
                                                                                  Retained
                                           Common Stock           Additional      Earnings         Treasury Stock
                                    --------------------------     Paid-in     (Accumulated    ---------------------
                                         Shares        Amount       Capital       deficit)       Shares       Amount
                                    -------------  -----------    ----------     --------      ----------    -------
                                                               (dollar amounts in thousands)
<S>                                     <C>           <C>          <C>           <C>            <C>         <C>
Balances,
  December 1, 1996                      3,499,915     $  700       $ 17,361      $    720       344,569     $ (2,556)

Exercise of employee
  stock options                            99,233         20            548             -        13,333         (131)
Purchase of shares                              -          -              -             -       158,014       (1,381)
Shares issued for Stock
  Purchase Plan                             6,996          1             62             -        (1,762)          12
Shares issued for
  Incentive Bonus Plan
  and directors' fees                           -          -             (7)            -       (13,451)         105
Shares issued under
  five-for-four stock
  split                                   885,924        177           (178)            -       107,808            -
Tax benefit of disqualifying
  disposition of incentive
  stock options                                 -          -             76             -             -            -
Income tax benefit of
  loss carryforwards
  arising prior to
  quasi-reorganization                          -          -            262             -             -            -
Net earnings                                    -          -              -         2,167             -            -
                                        ---------     ------        -------       -------        ------      -------

Balances,
  November 30, 1997                     4,492,068        898         18,124         2,887       608,511       (3,951)
                                        ---------     ------        -------       -------       -------      -------

Exercise of employee
  stock options                           109,910         22            592             -        27,193         (229)
Purchase of shares                              -          -              -             -       352,766       (2,550)
Shares issued for Stock
  Purchase Plan                             9,023          2             70             -        (2,275)          16
10% stock dividend                              -          -            492        (3,092)     (386,494)       2,598
Shares issued for
  Incentive Bonus Plan
  and directors' fees                           -          -            (57)            -       (35,252)         242
Tax benefit of stock option
  exercises                                     -          -            215             -             -            -

                                                                                                          (continued)


</TABLE>


                                       51
<PAGE>



                              COLUMBUS ENERGY CORP.
          CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - (continued)
                   For the Three Years Ended November 30, 1999
<TABLE>
<CAPTION>
                                                                                  Retained
                                           Common Stock           Additional      Earnings         Treasury Stock
                                    --------------------------     Paid-in     (Accumulated    ---------------------
                                         Shares        Amount       Capital       deficit)       Shares       Amount
                                    -------------  -----------    ----------     --------      ----------    -------
                                                               (dollar amounts in thousands)
<S>                                     <C>           <C>          <C>           <C>            <C>         <C>
Income tax benefit of
  loss carryforwards
  arising prior to
  quasi-reorganization                          -     $     -      $   220       $     -              -     $     -
Net loss                                        -           -            -        (1,235)             -           -
                                        ---------     -------      -------       -------        -------     -------

Balances,
  November 30, 1998                     4,611,001         922       19,656        (1,440)       564,449      (3,874)
                                        ---------     -------      -------       -------        -------     -------

Exercise of employee
  stock options                            23,320           5           63             -            855          24
Purchase of shares                              -           -            -             -        300,540      (1,836)
Shares issued for Stock
  Purchase Plan                            10,982           2           66             -         (2,759)         19
Shares issued for
  Incentive Bonus Plan
  and directors' fees                           -           -          (38)            -        (18,340)        122
Tax benefit of stock option
  exercises                                     -           -           12             -              -           -
Income tax benefit of
  loss carryforwards
  arising prior to
  quasi-reorganization                          -           -          310             -              -           -
Net loss                                        -           -            -        (1,215)             -           -
                                         ---------     ------      -------       -------        -------     -------
Balances,
  November 30, 1999                      4,645,303     $  929      $20,069       $(2,655)       844,745     $(5,545)
                                         =========     ======      =======       =======        =======     =======
</TABLE>




The accompanying notes are an integral part of these
consolidated financial statements.



                                       52
<PAGE>

                              COLUMBUS ENERGY CORP.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>

                                                                    Year Ended November 30,
                                                                ----------------------------------
                                                                1999           1998           1997
                                                                ----           ----           ----
                                                                         (in thousands)

<S>                                                           <C>            <C>             <C>
Net earnings (loss)                                           $(1,215)       $(1,235)        $ 2,167
Adjustments to reconcile net earnings (loss) to
  net cash provided by operating activities:
    Depreciation, depletion, and
     amortization                                               3,400          3,846           3,295
    Impairments and loss on asset dispositions                    973          3,482           2,179
    Deferred income tax provision (benefit)                      (606)          (822)          1,328
    Exploration expense, non-cash portion                         328              9               -
    Other                                                         147            190             163

Changes in operating assets and liabilities:
    Accounts receivable                                          (472)         1,177          (1,554)
    Other current assets                                          (28)            (7)             21
    Accounts payable                                              673           (298)            352
    Undistributed oil and gas production receipts                  69            (76)            339
    Accrued production and property taxes                          61            126              (4)
    Prepayments from joint interest owners                       (174)          (191)            307
    Income taxes payable                                           28             18               9
    Other current liabilities                                      74             39              36
                                                              -------        -------         -------
    Net cash provided by operating activities                   3,258          6,258           8,638
                                                              -------        -------         -------

Cash flows from investing activities:

    Proceeds from sale of assets                                    -             36           1,005
    Additions to oil and gas properties                        (2,291)        (6,642)         (8,172)
    Additions to other assets                                     (45)          (111)           (127)
                                                              -------        -------         -------
    Net cash used in investing activities                      (2,336)        (6,717)         (7,294)
                                                              -------        -------         -------

Cash flows from financing activities:

    Proceeds from long-term debt                                1,300          3,400           3,000
    Reduction in long-term debt                                  (700)          (700)         (3,000)
    Proceeds from exercise of stock options                       161            455             498
    Purchase of treasury stock                                 (1,836)        (2,550)         (1,381)
                                                              -------        -------         -------
    Net cash provided by (used in)
      financing activities                                     (1,075)           605            (883)
                                                              -------        -------         -------

Net increase (decrease) in cash and cash equivalents             (153)           146             461
Cash and cash equivalents at beginning of year                  2,003          1,857           1,396
                                                              -------        -------         -------
Cash and cash equivalents at end of year                      $ 1,850        $ 2,003         $ 1,857
                                                              =======        =======         =======

Supplemental disclosure of cash flow information:
    Cash paid during the period for:
      Interest                                                $   373        $   254         $   182
                                                              =======        =======         =======
      Income taxes, net of refunds                            $    32        $    47         $    91
                                                              =======        =======         =======

Supplemental disclosure of non-cash investing
and financing activities:
    Non-cash compensation expense
      related to common stock                                 $   116        $   190         $    98
                                                              =======        =======         =======
    Use of loss carryforwards credited to
      additional paid-in-capital                              $   310        $   220         $   262
                                                              =======        =======         =======
</TABLE>



The accompanying notes are an integral part of these
consolidated financial statements.



                                       53
<PAGE>

                              COLUMBUS ENERGY CORP.

                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(1)      FORMATION AND OPERATIONS OF THE COMPANY

         Columbus  Energy  Corp.  ("Columbus")  was  incorporated  as a Colorado
corporation  on October 7, 1982 primarily to explore for,  develop,  acquire and
produce oil and gas reserves.  Columbus' wholly-owned subsidiary is Columbus Gas
Services,   Inc.  ("CGSI").   CEC  Resources  Ltd.   ("Resources")  was  also  a
wholly-owned  subsidiary  prior to  February  24,  1995 when it was  divested by
Columbus by a rights offering to its shareholders. On September 1, 1998 Columbus
formed a Texas  partnership  named  Columbus  Energy,  L.P.  and is its  general
partner. The partnership's limited partner is Columbus Texas, Inc. ("Texas"),  a
Nevada corporation,  which is a wholly- owned subsidiary of Columbus. All of the
Company's oil and gas properties in Texas were  transferred  to the  partnership
effective  September 1, 1998.  Columbus  remains the operator of the properties.
Columbus and its  subsidiaries  are referred to in these Notes to the  Financial
Statements as the "Company".

(2)      ACCOUNTING POLICIES

         The consolidated financial statements of the Company have been prepared
in  accordance  with  generally  accepted  accounting   principles  and  require
management to make estimates and assumptions that affect the reported amounts of
assets and  liabilities  and disclosure of contingent  assets and liabilities at
the date of the financial  statements  and the reported  amounts of revenues and
expenses  during the reporting  period.  Actual  results could differ from those
estimates.  The following is a summary of the  significant  accounting  policies
followed by the Company.

         Consolidation

         The accompanying consolidated financial statements include the accounts
of Columbus and its wholly-owned  subsidiaries,  CGSI and Texas. All significant
intercompany balances have been eliminated in consolidation.

         Cash Equivalents

         For purposes of the statements of cash flows, the Company considers all
highly  liquid debt  instruments  purchased  with an original  maturity of three
months or less to be cash equivalents.  Hedging  activities are included in cash
flow from operations in the cash flow statements.



                                       54
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


         Financial Instruments and Concentrations of Credit Risk

         The Company  maintains  demand deposit  accounts with separate banks in
Denver,  Colorado. The Company also invests cash in the highest rated commercial
paper of large U.S.  companies,  with  maturities  not over 30 days,  which have
minimal risk of loss. At November 30, 1999 and 1998 the Company had  investments
in commercial  paper of $1,300,000 and  $1,100,000,  respectively.  The carrying
amounts of accounts  receivable  and  accounts  payable  approximate  their fair
values based on the short-term nature of those instruments.  The carrying amount
of long-term  debt  approximates  fair value  because the interest  rate on this
instrument changes with market interest rates.

         Financial  instruments,   which  potentially  subject  the  Company  to
concentrations of credit risk, consist  principally of cash and cash equivalents
and  accounts  receivable.  Columbus as operator  of  jointly-owned  oil and gas
properties,  sells oil and gas  production to relatively  large U.S. oil and gas
purchasers (see Note 3), and pays vendors for oil and gas services.  The risk of
non-payment by the purchasers,  counterparties  to the crude oil and natural gas
swap  agreements  or joint owners is  considered  minimal.  The Company does not
obtain  collateral  from its oil and gas  purchasers  for  sales to them.  Joint
interest  receivables  are subject to  collection  under the terms of  operating
agreements which provide lien rights to the operator.

         Oil and Gas Properties

         The  Company  follows  the  successful  efforts  method of  accounting.
Expenditures  for  lease   acquisition  and  development   costs  (tangible  and
intangible) relating to proved oil and gas properties are capitalized. Delay and
surface  rentals  are  charged to expense in the year  incurred.  Dry hole costs
incurred on exploratory  operations are expensed. Dry hole costs associated with
developing   proved  fields  are   capitalized.   Expenditures   for  additions,
betterments,   and  renewals  are   capitalized.   Exploratory   geological  and
geophysical costs are expensed when incurred.

         Upon sale or retirement of proved properties,  the cost thereof and the
accumulated depreciation or depletion are removed from the accounts and any gain
or  loss  is  credited  or  charged  to  income  if  significant.   Abandonment,
restoration,  dismantlement  costs and salvage  value are taken into  account in
determining  depletion  rates.  These  costs are  generally  about  equal to the
proceeds  from  equipment  salvage upon  abandonment  of such  properties.  When
estimated abandonment costs exceed the salvage value, the excess cost is accrued
and expensed. Maintenance and repairs are charged to operating expenses.



                                       55
<PAGE>



                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


         Provision for depreciation and depletion of capitalized exploration and
development costs are computed on the unit-of- production method based on proved
reserves of oil and gas, as estimated by petroleum  engineers,  on a property by
property  basis.  Unproved  properties  are assessed  periodically  to determine
whether they are  impaired.  When  impairment  occurs,  a loss is  recognized by
providing a valuation allowance. When leases for unproved properties expire, any
remaining cost is expensed.

         An impairment loss on oil and gas properties is reported as a component
of income from continuing operations.  The Company recognizes an impairment loss
when the carrying value exceeds the expected  undiscounted future net cash flows
of each  property  pool,  at which time the property pool is written down to the
fair value. Fair value is estimated to be a discounted present value of expected
future net cash flows with appropriate risk consideration.

         The  Company  uses crude oil and  natural  gas  hedges to manage  price
exposure.  Realized gains and losses on the hedges are recognized in oil and gas
sales as settlement occurs.

         The Company follows the entitlements method of accounting for balancing
of gas  production.  The Company's gas imbalances are immaterial at November 30,
1999 and 1998.

         Other Property and Equipment

         Other property and equipment consists of compressors,  vehicles, office
and  computer  equipment  and  software.  Gains and losses  from  retirement  or
replacement   of  other   properties  and  equipment  are  included  in  income.
Betterments and renewals are capitalized. Maintenance and repairs are charged to
operating  expenses.  Depreciation  of other  assets is provided on the straight
line method over their estimated useful lives,  which range from three to twelve
years.

         Operating and Management Services

         The Company  recognizes  revenue for operating and management  services
provided  to other  companies  and  non-operating  interest  owners in which the
Company has no economic interest. The Company receives overhead fees, management
fees and revenues related to gas marketing, compression and gathering.

         The cost of providing such services is expensed and shown as "operating
and management services" cost.



                                       56
<PAGE>



                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


         Earnings Per Share

         Basic  earnings  per share is computed  based on the  weighted  average
number of shares outstanding.  Diluted earnings per share reflects the potential
dilution  that would occur if options were  exercised  using the average  market
price for the  Company's  stock for the  period.  Historical  average  number of
shares   outstanding   and  earnings  per  share  have  been  adjusted  for  the
five-for-four stock split distributed June 16, 1997 to shareholders of record as
of May  27,  1997  and the 10%  stock  dividend  distributed  March  9,  1998 to
shareholders of record as of February 23, 1998.

         Accounting for Stock-Based Compensation

         The Financial  Accounting Standards Board ("FASB") issued SFAS No. 123,
"Accounting for Stock-Based Compensation" in 1995. This statement prescribes the
accounting and reporting standards for stock-based  employee  compensation plans
and was  effective  for the  Company's  1997 fiscal year.  The Company makes the
alternative pro forma disclosures as permitted in the SFAS.

         New Accounting Pronouncements

     In June 1999,  the FASB issued SFAS No. 137 which  deferred  the  effective
date for SFAS No.  133,  "Accounting  for  Derivative  Instruments  and  Hedging
Activities,"  to fiscal years  beginning  after June 15, 2000.  The Company must
apply this statement no later than its fiscal year  beginning  December 1, 2000.
SFAS No.  133  requires  recording  all  derivative  instruments  as  assets  or
liabilities measured at fair value. This Statement is not expected to materially
affect the Company's financial statements.



                                       57
<PAGE>



                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(3)      OIL AND GAS PRODUCING ACTIVITIES

         The following  tables set forth the  capitalized  costs related to U.S.
oil  and gas  producing  activities,  costs  incurred  in oil  and gas  property
acquisition,  exploration and development activities,  and results of operations
for producing activities:

                    Capitalized Costs Relating to Oil and Gas
                              Producing Activities
                                 (in thousands)

                                                           November 30,
                                                 ----------------------------
                                                   1999                 1998
                                                 -------              -------

         Proved properties                       $36,456              $35,290
         Unproved properties                         406                  749
                                                 -------              -------
                                                  36,862               36,039
         Less accumulated depreciation,
           depletion, amortization and
           valuation allowance                   (21,221)             (17,919)
                                                 -------              -------
         Total net properties                    $15,641              $18,120
                                                 =======              =======


               Costs Incurred in Oil and Gas Property Acquisition,
                     Exploration and Development Activities
                                 (in thousands)

                                               Year Ended November 30,
                                          -------------------------------
                                           1999          1998        1997
                                          ------        ------      -----
Property acquisition
  costs:
     Proved                               $    -        $   74      $    -
     Unproved                                226           764         508
Exploration costs                          3,071           722         540
Development costs                          1,927         4,925       9,043
                                          ------        ------      ------
Total costs incurred                      $5,224        $6,485      $10,091
                                          ======        ======      =======











                                       58
<PAGE>



                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


                 Results of Operations for Producing Activities
                                 (in thousands)

                                          Year Ended November 30,
                                       -----------------------------
                                        1999        1998        1997
                                       ------      ------      -----
Sales                                 $10,014     $10,617      $13,815
Production (lifting)
  costs (a)                             2,932       3,220        3,107
Exploration expenses                    3,071         722          540
Impairment of long-
  lived assets                            973       3,482        2,179
Depreciation
  depletion and
  amortization (b)                      3,301       3,743        3,194
                                      -------     -------       ------
                                         (263)       (550)       4,795

Income tax provision
  (benefit)                               (82)       (209)       1,905
                                      -------     -------       ------
Results of operations
  from producing
  activities
  (excluding overhead
  and interest
  incurred)                           $  (181)    $  (341)      $2,890
                                      =======     =======       ======

(a) Production costs include lease operating expenses, production
    and property taxes
(b) Amortization expense per equivalent barrel of production:
    1999 - $4.69   1998 - $4.64   1997 - $3.91

         For the years ended  November 30, 1999,  1998 and 1997, the Company had
the following  customers who purchased  production equal to more than 10% of its
total  revenues.  The  following  table  shows  the  amounts  purchased  by each
customer.

                     1999                 1998                1997
              ------------------   ------------------  -------------------
              Amount   % Revenue   Amount   % Revenue   Amount   % Revenue
              ------   ---------   ------   ---------  -------   ---------
Customer A    $1,521     15.2%     $1,652      15.6%   $ 2,956      21.4%
Customer B     4,528     45.2       5,204      49.0      6,536      47.3
Customer C         -        -           -         -      1,395      10.1
Customer D     1,465     14.6       1,321      12.4          -         -

         In the Company's  judgment,  termination  by any purchaser to which its
present sales are made would not have a material impact upon its ability to sell
its production to another purchaser at similar prices.



                                       59
<PAGE>



                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(4)  LONG-TERM DEBT

         The Company has a Credit  Agreement  ("Agreement")  with  Norwest  Bank
Denver,  N.A. ("Bank") having a borrowing base of $10,000,000,  which is subject
to semi-annual redetermination for any increase or decrease. On May 12, 1999 the
Credit Agreement was amended to extend the revolving period to July 1, 2001 when
it entirely  converts to an amortizing term loan which matures July 1, 2005. The
credit is collateralized by a first lien on oil and gas properties. The interest
rate  options are the Bank's  prime rate or LIBOR plus  1.50%.  In  addition,  a
commitment  fee of 1/4 of 1% of the  average  unused  portion  of the  credit is
payable quarterly.

         At November 30, 1999  outstanding  borrowings on the revolving  line of
credit were  $5,500,000 and the unused  borrowing base available was $4,500,000.
The $5,500,000 bears interest at LIBOR rate of 5.51% plus 1.50%.

         The Agreement as amended provides that certain  financial  covenants be
met which include a minimum net worth of $12,000,000  plus 50% of Cumulative Net
Income,  as  defined,  minus  exploration  expenses  after  August 31,  1998,  a
quarterly calculation of a current ratio of not less than 1.0:1.0 and a ratio of
Funded Debt to Consolidated  Net Worth, as defined,  not greater than 1.25:1.00.
Columbus has complied with these  covenants.  Under the terms of the  Agreement,
Columbus  is  permitted  to  declare  and pay a  dividend  in cash so long as no
default has occurred or a mandatory prepayment of principal is pending.

         The scheduled  payments of long-term debt for the years ending November
30 are as follows (in thousands):

                       2001                      $   458
                       2002                        1,375
                       2003                        1,375
                       2004                        1,375
                       2005                          917
                                                 -------
                                Total            $ 5,500
                                                 =======











                                       60
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(5)      INCOME TAXES

         The provision  (benefit) for income taxes consists of the following (in
thousands):

                                           1999         1998        1997
                                           ----         ----        ----
         Current:
            Federal                        $   28       $    -     $   13
            State                              32           65         88
                                           ------       ------     ------
                                               60           65        101
                                           ------       ------     ------
         Deferred:
            Federal                          (582)        (789)       942
            Use of loss carryforwards           -            -        347
         State                                (24)         (33)        39
                                           ------       ------     ------
                                             (606)        (822)     1,328
                                           ------       ------     ------
         Total income tax
            provision (benefit)           $  (546)      $ (757)    $1,429
                                          =======       ======     ======

         Total tax  provision  has resulted in effective  tax rates which differ
from the statutory  Federal income tax rates. The reasons for these  differences
are:

                                            Percent of Pretax Earnings
                                    ----------------------------------------
                                    1999              1998              1997
                                    ----              ----              ----
         U.S. statutory rate        (34)%             (34)%              34 %
         State income taxes           1                 2                 2
         Change in valuation
           allowance                  -                (4)                2
         Other                        2                (2)                2
                                    ---               ---               ---
         Effective rate             (31)%             (38)%              40 %
                                    ===               ===               ===

         The  Company   files  a   consolidated   income  tax  return  with  its
subsidiaries.  Consolidated  income taxes are payable  only when taxable  income
exceeds available net operating loss carryforwards and other credits.

         The  Tax  Reform  Act  of  1986  limits  the  use  of   corporate   tax
carryforwards in any one taxable year if a corporation  experiences a 50% change
of ownership.  Columbus  experienced  such a change of ownership in October 1987
which  limits  its  use  of  pre-change   ownership  net  operating   losses  to
approximately $900,000 in each subsequent year.



                                       61
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     The  Company  uses the asset and  liability  method to  account  for income
taxes.  Under this method,  deferred tax  liabilities  and assets are determined
based on the temporary  differences between financial statement and tax basis of
assets and  liabilities  using enacted rates in effect for the year in which the
differences  are  expected to reverse.  Deferred  tax assets (net of a valuation
allowance)  primarily result from net operating loss  carryforwards,  percentage
depletion  and  certain  accrued  but unpaid  employee  benefits.  Deferred  tax
liabilities   result  from  the  recognition  of  depreciation,   depletion  and
amortization in different periods for financial reporting and tax purposes.

         Because  of  the  Company's  previous  1987  quasi-reorganization,  the
Company is required to report the effect of its net deferred  tax asset  arising
prior to December 1, 1987 as an increase in stockholders'  equity rather than as
an increase to net earnings.

         During fiscal 1999,  certain tax assets (shown in the table below) were
utilized and the valuation  allowance was decreased during the year by $122,000.
The tax effect of significant  temporary  differences  representing deferred tax
assets and liabilities and changes were as follows (in thousands):

<TABLE>
<CAPTION>
                                                                       Current Year
                                                              --------------------------------
                                               Dec. 1,        Stockholders'        Operations/         Nov. 30,
                                                1998              Equity              Other              1999
                                              --------        ------------         -----------          ------
<S>                                            <C>                <C>                <C>                <C>
Deferred tax assets:
  Pre-1987 loss carryforwards                  $1,049             $   -              $ (609)            $  440
  Post-1987 loss carryforwards                    615                 -                   2                617
  Percentage depletion
    carryforwards                               1,478                 -                 172              1,650
  State income tax loss
    carryforwards                                 118                 -                   6                124
  Other                                           329                 -                  58                387
                                               ------             -----               -----             ------
                  Total                         3,589                 -                (371)             3,218
    Valuation allowance (long-term)            (1,408)              310(a)             (188)            (1,286)
                                               ------             -----               -----             ------
         Deferred tax assets                    2,181               310                (559)             1,932
                                               ------             -----               -----             ------
  Tax benefit of stock option
    exercises                                       -                12(a)              (12)                 -
                                               ------             -----              ------             ------
Deferred tax liabilities-
  Depreciation, depletion and
    amortization and other                     (1,971)                -               1,176               (795)
                                               ------             -----              ------             ------
    Net tax asset                              $  210             $ 322              $   605            $1,137
                                               ======             =====              =======            ======
</TABLE>


(a)  Credited to additional paid-in capital.






                                       62
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


         The  Company has  approximate  net  operating  loss  carryforwards  (in
thousands) available at November 30, 1999 as follows:

                                                        Net
                  Expiration Year                  Operating Loss
                  ---------------                  --------------
                       2000                           $   904
                       2001                               387
                       2003                               105
                       2004                               115
                       2010                             1,593
                                                      -------
                                                      $ 3,104
                                                      =======

         For Alternative Minimum Tax purposes the Company had net operating loss
carryforwards of  approximately  $3,219,000 as of November 30, 1999. The Company
also has percentage  depletion  carryforwards of $4,344,000 which do not expire.
Oklahoma  state income tax  operating  loss  carryforwards  total  approximately
$2,075,000 at November 30, 1999. These  carryforwards  begin to expire in fiscal
2003  and  have a full  valuation  allowance  and no net  asset  value  in these
financial statements.

         The earnings before income taxes for financial statements differed from
taxable income as follows (in thousands):

<TABLE>
<CAPTION>
                                                        1999             1998              1997
                                                        ----             ----              ----
<S>                                                   <C>              <C>               <C>
Earnings (loss) before income taxes
  per financial statements                            $(1,761)         $(1,992)          $ 3,596
Differences  between  income before taxes
  or financial  statement  purposes and
  taxable income:
  Intangible drilling costs
    deductible for taxes                                 (453)          (2,685)           (6,158)
  Excess of book over tax
    depletion, depreciation
    and amortization                                    2,212            1,800             1,683
  Tax benefit of stock option
    exercises                                             (32)            (229)             (200)
  Impairment expense                                      973            3,426             1,843
  Lease abandonments                                     (393)             (74)              (13)
  Geological expense                                      318                -                 -
  Other                                                   153              (10)              153
                                                       ------           ------           -------
Federal taxable income                                $ 1,017          $   236           $   904
                                                      =======          =======           =======
</TABLE>

         Realization  of the future tax benefits is  dependent on the  Company's
ability to generate  taxable income within the carryfor ward period.  Based upon
the proved  reserves as of November  30, 1999 as well as  contemplated  drilling



                                       63
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


activities,  but excluding  revenues from any possible future increase in proved
reserves, management believes that taxable income during the carryforward period
will be sufficient to essentially  utilize the NOL's before they expire.  Of the
total  valuation  allowance of  $1,286,000  as of November  30,  1999,  $206,000
relates to  pre-quasi-  reorganization  tax assets and the balance of $1,080,000
relates  to  post-quasi-reorganization   tax  assets.  In  future  periods,  any
reduction of the  pre-quasi-reorganization  portion of the  valuation  allowance
will  be  credited  to  additional  paid-in  capital  and any  reduction  of the
post-quasi-reorganization portion of the valuation allowance will be credited to
income.

         Estimates of future taxable income are subject to continuing review and
change because oil and gas prices  fluctuate,  proved  reserves are developed or
new reserves added as a result of future drilling activities,  and operation and
management  services revenue and expenses vary. A minimum level of $8,500,000 of
future  taxable  income will be necessary to enable the Company to fully utilize
the net operating loss  carryforwards  and realize the gross deferred tax assets
of  $3,218,000.  This level of income can be achieved  using the value of proved
reserves reported in the year end November 30, 1999 standardized  measure of net
cash flows but this does not give total assurance that sufficient taxable income
will be generated for total  utilization  because of the volatility  inherent in
the oil and gas industry which makes it difficult to project  earnings in future
years due to the factors  mentioned above.  During 1999 the valuation  allowance
was decreased by $310,000  related to pre-quasi-  reorganization  tax assets and
increased by $188,000 for post-quasi- reorganization tax assets. During 1998 the
valuation     allowance    was     decreased    by    $221,000     related    to
pre-quasi-reorganization    tax   assets   and   increased   by   $186,000   for
post-quasi-reorganization  assets.  During  1997  the  valuation  allowance  was
decreased  by  $262,000  related  to  pre-quasi-reorganization  tax  assets  and
increased by $236,000 for post-quasi-reorganization assets.

(6)  RELATED PARTY TRANSACTIONS

     Reimbursement  is made by Resources  to Columbus  for services  provided by
Columbus  officers and employees for managing  Resources and reduces general and
administrative  expense.  This  reimbursement  totaled  $33,000 for fiscal 1999,
$218,000 for fiscal 1998 and $225,000 for fiscal 1997.

         During fiscal 1997,  the Company  continued its consulting and drilling
arrangements  with  Trueblood  Resources  , Inc  ("TRI")  that began in 1995 and
continued each year with amendments as appropriate  for each year's program.  In
1997 there was a 90-day  written  notice  provision  in  addition to the monthly


                                       64
<PAGE>



                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


retainer  fee of $10,000 for  geological  and  geophysical  consulting  services
provided by Mark Butler,  a Vice President of TRI, who would dedicate a total of
135 hours each  three-month  period  reviewing  prospects  of third  parties and
supervising  and  planning 3D seismic  programs on Columbus'  leaseholds.  Also,
there was to be continued  participation for a 37.5% working interest in the AMI
located in the Anadarko Basin primarily  located in two counties in the Oklahoma
Panhandle.  TRI is a  privately  held  oil and gas  exploration  and  production
company whose major  shareholder  is John  Trueblood,  the son of Columbus' CEO,
Harry A.  Trueblood,  Jr., who is a director and also was a 1.2%  shareholder of
TRI.  Also,  there is a  related  company  to TRI  known as  Trumark  Production
Company,  LLC ("TPC") in which Mark Butler and John Trueblood each own 50% which
is primarily a technical  services  oriented  company for which TRI serves in an
administrative capacity therefor.

         In November 1997, an amended agreement was created to cover 1998 fiscal
year  operations  and  superseded  and replaced the original 1995  agreement and
supplements  thereto.  Columbus  and TRI formed a new AMI which  included all of
Texas County,  Oklahoma  wherein  Columbus would take up to a one-third  working
interest  participation and the remainder  belonged to TRI. The Company advanced
$30,000 to acquire digitized logs and related software for use in the search for
new prospects in Texas County with the  resulting  data to be owned by Columbus.
To  compensate  for the advance,  TRI agreed to waive any cash  promotion on the
first four prospects generated from the data and further reduced the 10% carried
working  interest  promotion  on the  100% WI to 5% in the  first  two of  those
prospects.  The retainer fee of $10,000 per month was  continued  covering up to
135 hours in each three months period of Mr.  Butler's  time to perform  certain
geological  and  geophysical  services.   Also  TRI  would  have  the  right  to
participate for up to a  proportionate  5.0% WI in any third party deal reviewed
by Mr. Butler and taken by the Company.

         For fiscal 1999,  two separate  agreements  dated December 1, 1998 were
entered into by the Company.  One was with TPC wherein Mr. Butler  increased his
base  consulting  to 70 hours per month and his other  time  would be devoted to
finding  prospects  in the Oklahoma  AMI for TRI's  operations  with third party
participants as well as with Columbus. The retainer would be at the rate of $170
per hour which would result in a monthly  retainer  charge of $11,900.  For each
prospect  review by Mr.  Butler and taken by  Columbus,  TPC would  receive a 2%
proportionately  reduced  carried  working  interest  through  logs but  certain
existing areas of operations were  specifically  excepted from this arrangement.





                                       65
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


The second  agreement  was  with TRI and basically gave Columbus  the option  to
participate in the Oklahoma  prospects  during the year with no carried  working
interest burden related to its proportionate  share of such prospects that might
be drilled.

         As a result of the above contracts, retainer fees paid to TRI for TPC's
consulting  services,  etc. were $155,000 in fiscal 1999,  $179,000 in 1998, and
$121,000 in 1997.  Promotional  costs plus  associated  actual costs of drilling
wells  involved  which were paid to TRI amounted to $348,000 in 1999,  $5,000 in
1998 and $614,000 in 1997.  The amounts are paid monthly and at each year-end no
other amounts were owed.

(7)  CAPITAL STOCK

     The shares and prices of stock  options in this note have been  adjusted to
reflect  the  five-for-four  stock  split in 1997 and the 10% stock  dividend in
fiscal 1998.

     Columbus has several  stock option plans with  outstanding  options for the
benefit of all  employees.  Under the 1985 Plan,  options for 42,178 shares were
exercisable at November 30, 1999. No additional options may be granted under the
1985 Plan. At November 30, 1998, 63,731 shares were exercisable.

     Under the 1995 Plan, as of November 30, 1999, 17,487 option shares remained
available for granting, and options for 287,752 shares were exercisable. Options
may be exercised  for a period  determined  at grant date but not to exceed five
years.  Options are vested in three equal annual amounts from grant date or each
annual  amount may be exercised  immediately  for each  twelve-month  period the
optionholder  has been an employee of the Company.  At November 30, 1998,  6,937
shares  were  available  for  granting,  and  options  for  314,182  shares were
exercisable.

     The Board of Directors  has granted  non-qualified  stock  options of which
there were  329,886  exercisable  at November  30, 1999 and 231,803  shares were
exercisable  at November 30, 1998.  The Board of Directors has reserved  475,000
shares of treasury stock to be used for issuing common stock when  non-qualified
stock options are exercised.



                                       66
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     On December 1, 1996,  the Company  adopted  SFAS No. 123,  "Accounting  for
Stock-Based   Compensation".   The  Company   elected  to  continue  to  measure
compensation  costs for these plans using the current method of accounting under
Accounting Principles Board (APB) Opinion No. 25 and related  interpretations in
accounting for its stock option plans.  Accordingly,  no compensation expense is
recognized  for fixed stock options  granted with an exercise  price equal to or
greater  than the  market  value of  Columbus  stock on the date of  grant.  Had
compensation cost for the Company's stock option plans been determined using the
fair-value  method in SFAS No. 123,  the  Company's  net income and earnings per
share would have been as follows:

                                  1999        1998        1997
                                  ----        ----        ----
                             (thousands except per share amounts)
     Net income (loss)
          As reported           $(1,215)    $(1,235)     $2,167
          Pro forma              (1,340)    $(1,392)     $1,968

     Earnings (loss) per
       share (basic)
          As reported           $  (.31)     $ (.29)     $  .50
          Pro forma             $  (.34)     $ (.33)     $  .46





















                                       67
<PAGE>



                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     Options are granted at 100% of fair market value on the date of grant.  The
following  table is a summary of stock option  transactions  for the three years
ended November 30, 1999:

                                 1999               1998              1997
                           ----------------   ----------------  ----------------
                                  Weighted-           Weighted-        Weighted-
                                   Average             Average          Average
                                  Exercise            Exercise         Exercise
                           Shares   Price     Shares   Price    Shares   Price
                           ------ ---------   ------ ---------  ------ -------
                                           (options in thousands)
Shares under option at
  beginning of year          619    $6.73       557    $6.45      490    $5.65
Granted                      246    $5.93       182    $6.76      191    $7.38
Exercised                    (67)   $5.40      (115)   $5.34     (121)   $4.70
Expired                      (49)   $6.46        (5)   $7.79       (3)   $6.64
                            ----               ----              ----
Shares under option at
  end of year                749    $6.61       619    $6.73      557    $6.45
                            ====               ====              ====
Options exercisable
  at November 30             660    $6.74       610    $6.73      542    $6.42
Shares available for
  future grant at end
  of year                     17                  7                46
Weighted-average fair value
  of options granted during
  the year                          $1.07              $1.40             $2.04

     The  following  table  summarizes  information  about the  Company's  stock
options outstanding at November 30, 1999:

                        Options Outstanding               Options Exercisable
                ------------------------------------   -----------------------
                               Weighted-
                  Options      Average     Weighted-     Options     Weighted-
   Range of     Outstanding   Remaining     Average    Exercisable    Average
   Exercise      at Year     Contractual   Exercise      at Year     Exercise
    Prices         End       Life (Years)    Price         End        Price
   --------     -----------  ------------  ---------   -----------   ----------
                              (options in thousands)

$4.68 - $5.79       137         2.1         $ 5.57          52         $ 5.58
$6.12 - $6.44       273         2.4         $ 6.21         269         $ 6.21
$7.00 - $7.84       339         1.5         $ 7.34         339         $ 7.34
                    ---         ---         ------         ---         ------
$4.68 - $7.84       749         2.0         $ 6.61         660         $ 6.74
                    ===         ===         ======         ===         ======

     The fair  value of each  option  grant was  estimated  on the date of grant
using the Black-Scholes option-pricing model with the following assumptions:

                                 1999         1998         1997
                                 ----         ----         ----
Expected option life - years     2.30         2.32         2.36
Risk-free interest rate          5.50%        5.02%        6.08%
Dividend yield                   0   %        0   %        0   %
Volatility                      19.94%       25.87%       30.60%




                                       68
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


      On October 28,  1992,  the Board of Directors  approved an Employee  Stock
Purchase  Plan  ("Plan")  to begin  January 1, 1993,  which was  approved by the
shareholders  at the 1993  annual  meeting.  Under  the Plan a total of  220,000
shares were reserved from  authorized  unissued common stock from which payments
by participants  into the Plan will be utilized to purchase shares.  The Company
contributes  an amount of shares  equivalent to 25% of those  payments which are
issued out of the Company's treasury stock as vesting occurs semi- annually. The
price of the issued  shares  equals the average  trading  price  during each six
month  purchase  period or the ending  price,  whichever is less.  The following
table  summarizes  the Stock  Purchase  Plan  activity for the last three fiscal
years:

                Matching       Total    Shares from   Average
             Contributions    Shares     Treasury      Cost
Fiscal Year     Expense     Purchased     Stock     Per Share
-----------     -------     ---------     -----     ---------

   1997        $15,000        8,758       1,762       $8.58
   1998        $17,000       11,298       2,275       $7.73
   1999        $16,000       13,741       2,759       $6.30

      The Company has been  authorized  by the Board of Directors to  repurchase
its common  shares  from the market at various  prices  during the last  several
years. Those repurchases are summarized as follows:

                                 Shares
       Fiscal year     --------------------------    Average
       repurchased     As purchased     Restated*     price*
       -----------     ------------     ---------    -------
          1997            158,000        197,863      $6.92
          1998            352,750        357,715      $7.07
          1999            300,538        300,538      $6.08

       *Restated for stock split and stock dividends

      As of November 30, 1999 a total of 73,384 shares  remained to be purchased
from the most  recent  authorizations  to  repurchase  shares  at a price not to
exceed  $6.00 per share.  As of January 31,  2000,  45,000 of those  shares have
subsequently been acquired at an average price of $5.61 per share.



                                       69
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(8)       EARNINGS PER SHARE

          The following  table  provides a  reconciliation  of basic and diluted
earnings per share (EPS):

                                               Fiscal Year Ended November 30,
                                               ------------------------------
                                               1999         1998       1997
                                               ----         ----       ----
                                                  (in thousands,
                                                    except per share data)

Reconciliation of basic and diluted
  EPS share computations:
  Income (loss) available to common
    shareholders - basic and
    diluted EPS (numerator)                  $(1,215)     $(1,235)    $2,167
                                             =======      =======     ======

Shares (denominator):
  Basic EPS                                    3,898        4,194      4,299
  Effect of dilutive option
    shares                                         -            -         93
                                             -------       ------     ------
  Diluted EPS                                  3,898        4,194      4,392
                                             =======       ======     ======

Per share amount:
  Basic EPS                                  $  (.31)      $ (.29)    $  .50
                                             =======       ======     ======
  Diluted EPS                                $  (.31)      $ (.29)    $  .49
                                             =======       ======     ======

Number of shares not included in
  dilutive EPS that would have been
  antidilutive because exercise price
  of options was greater than the
  average market price of the common
  shares                                         544          138         73
                                             =======       ======     ======

          Historical average number of shares outstanding and earnings per share
have been adjusted for the  five-for-four  stock split distributed June 16, 1997
to  shareholders  of  record  as of May 27,  1997  and the  10%  stock  dividend
distributed March 9, 1998 to shareholders of record as of February 23, 1998.



                                       70
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(9)  COMMITMENTS AND CONTINGENT LIABILITIES

       The  Company's   Articles  of  Incorporation   and  By-Laws  provide  for
indemnification of its officers,  directors, agents and employees to the maximum
extent  authorized  by the Colorado  Corporation  Code,  as amended or as may be
amended,  revised or  superseded.  In  addition,  the Company  has entered  into
individual indemnification  agreements with its officers and directors,  present
and past, which agreements more fully describe such indemnification.

       In June 1991, Columbus executed a lease for its present office space. The
total rent expense for 1999, 1998 and 1997 was approximately $200,000,  $171,000
and  $161,000,  respectively.  Columbus has extended the lease for an additional
one year  through  September  2000 at a base rate of $21,525  per month.  Future
rental  payments  required under this lease as of November 30, 1999 are $215,000
for fiscal year 2000.

       Columbus  is  self-insured  for  medical  and dental  claims of its U. S.
employees and  dependents as well as any former  employees or dependents who are
eligible and elect coverage under COBRA rules. Columbus pays a premium to obtain
both  individual and aggregate  stop-loss  insurance  coverage.  A liability for
estimated  claims  incurred and not reported or paid before year end is included
in other current liabilities.

       The  separation pay policy of Columbus  includes a retirement  provision.
Officers and employees may retire at age 65, or older,  and at the discretion of
the Board of Directors be paid retirement  compensation based upon the length of
service and the prior year's average  compensation.  Such  compensation has been
approved for three  individuals who have reached age 65. As of November 30, 1999
the accrued  liability  totals  $290,000  which may change in future years until
their  retirement as compensation  and length of service with Columbus  changes.
The total  obligation  is unfunded and payment upon an  individual's  retirement
will be made from  working  capital.  The total  expense  accrued was  $120,000,
$18,000 and $23,000 in 1999, 1998 and 1997, respectively.



                                       71
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


      Columbus  periodically  hedges  both  natural  gas and crude oil prices by
entering into "swaps".  The swap is matched against the calendar monthly average
price on the NYMEX and settled monthly.  Revenues were decreased when the market
price at  settlement  exceeded  the contract  swap price or  increased  when the
contract swap price exceeded the market price.  There was no hedging activity in
fiscal 1998. The following table shows the results of these swaps:

<TABLE>
<CAPTION>

                                                                 Increase (decrease) in
                                                                   oil and gas revenues
                                Volume                           -----------------------
Description                     per mo.          Period          1999               1997
-----------                 --------------       ------          ----               ----
                            (Mmbtu or bbl)
<S>                              <C>           <C>               <C>               <C>
Natural Gas
-----------
$2.20/Mmbtu                      60,000        3/97-10/97                          $(86,400)

Crude Oil
---------
Collar with $17.50/
  bbl floor and
  $22.25/bbl ceiling              7,500         9/99- 8/00       $(34,000)
$21.17/bbl                       10,000        11/96-10/97                         $  8,900
$17.25/bbl with
  $19.50/bbl cap                 10,000         1/96-12/96                         $(22,500)

</TABLE>

      The  Company's  natural gas and crude oil swaps are  considered  financial
instruments  with  off-balance  sheet risk which are entered  into in the normal
course of business to partially reduce its exposure to fluctuations in the price
of crude oil and natural gas. Those  instruments  involved,  to varying degrees,
elements  of market and credit  risk in excess of the amount  recognized  in the
balance sheets.

      The Company had a crude oil hedge  outstanding  as of November 30, 1999 by
using a costless  "collar"  on 7,500  barrels  per month for the 12 months  from
September 1, 1999  through  August 31, 2000.  This  "collar" is settled  monthly
against the calendar monthly average price on the NYMEX with a $17.50 per barrel
floor and $22.25 per barrel ceiling.  For any average price below or above those
prices Columbus  receives or pays the difference  which increases or reduces oil
revenues each month in which this occurs.  For the two months of December,  1999
and January,  2000,  oil sales would have been $65,000  higher if this hedge had
not been in place because oil prices exceeded the $22.25 ceiling price.  For the
remaining  period of February  through August 2000 using the prevailing price as
of January  31, 2000 for each of the months,  the  settlement  value the Company
would owe is $158,000 which would also reduce crude oil sales.



                                       72
<PAGE>



                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


      The Company is not aware of any events of  noncompliance in its operations
with any  environmental  laws and regulations  nor of any  potentially  material
contingencies  related to environmental  issues.  There is no way management can
predict what future  environmental  control  problems may arise. The continually
changing  character of environmental  regulations and requirements that might be
enacted by  jurisdictional  authorities  in  various  operational  areas  defies
forecasting.

      On October 7, 1998,  Columbus  was served  with a  complaint  in a lawsuit
styled Maris E. Penn,  Michael  Mattalino,  Bruce Davis, and Benjamin T. Willey,
Jr. vs. Columbus Energy Corp., Cause No. 98- 44940 in the 55th District Court of
Harris County,  Texas. The plaintiffs are parties to a September 1994 settlement
agreement  that provided for the conveyance of overriding  royalty  interests in
leases  acquired by Columbus in certain  portions of Harris  County.  Plaintiffs
claim Columbus is obligated under the settlement agreement to acquire all leases
available  within a described  portion of Harris  County and that  Columbus  has
failed to develop those leases as a reasonably prudent operator.  Plaintiffs are
claiming  damages  based upon their  alleged  right to a 3%  overriding  royalty
interest in leases taken and drilled by third parties within the described area.
Discovery is ongoing.  Columbus denies all allegations of failure to develop and
instructed  counsel to vigorously  defend this lawsuit.  The parties are set for
mediation on April 11, 2000 and for trial on May 22, 2000.

(10)  DEFINED CONTRIBUTION PENSION PLAN

      The Company has a qualified defined  contribution 401(k) plan covering all
employees.  The Company matches, at its discretion, a portion of a participant's
voluntary  contribution  up to a certain  maximum  amount  of the  participant's
compensation.  The Company's  contribution  expense was approximately  $110,000,
$106,000, and $95,000 in the fiscal years 1999, 1998 and 1997, respectively.












                                       73
<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(11)  INDUSTRY SEGMENTS

      The Company operates primarily in two business segments of (1) oil and gas
exploration and development,  and (2) providing services as an operator, manager
and gas marketing advisor.

      Summarized  financial  information  concerning the business segments is as
follows:

<TABLE>
<CAPTION>
                                                                1999           1998          1997
                                                                ----           ----          ----
                                                                         (in thousands)
<S>                                                           <C>             <C>          <C>
Operating revenues from unaffiliated services:
     Oil and gas                                              $10,022         $10,630      $13,848
     Services                                                   1,478           1,464        1,308
                                                              -------         -------      -------
          Total                                               $11,500         $12,094      $15,156
                                                              =======         =======      =======

Depreciation, depletion and amortization (a):
     Oil and gas                                              $ 3,341         $ 3,784      $ 3,238
     Services                                                      59              62           57
                                                              -------         -------      -------
          Total                                               $ 3,400         $ 3,846      $ 3,295
                                                              =======         =======      =======

Operating income (loss):
     Oil and gas                                              $  (294)(b)     $  (582)(b)  $ 4,714(b)
     Services                                                     415             342          424
     General corporate expenses                                (1,447)         (1,466)      (1,372)
                                                              -------         -------      -------
          Total operating income (loss)                        (1,326)         (1,706)       3,766
Interest expense and other                                       (435)           (286)        (170)
                                                              -------         -------     --------
          Earnings (loss) before income taxes                 $(1,761)        $(1,992)     $ 3,596
                                                              =======         =======      =======

Identifiable assets (a):
     Oil and gas                                              $18,621         $19,587      $21,917
     Services                                                   3,909           4,362        4,218
                                                              -------         -------      -------
          Total                                               $22,530         $23,949      $26,135
                                                              =======         =======      =======

Additions to property and equipment:
     Oil and gas                                              $ 2,215         $ 5,872      $ 9,671
     Services                                                       -              45            7
                                                              -------         -------      -------
          Total                                               $ 2,215         $ 5,917      $ 9,678
                                                              =======         =======      =======
</TABLE>

(a) Other property and equipment  have been  allocated  above to the oil and gas
and services segment based upon the estimated proportion the property is used by
each  segment.   Therefore,   depletion,   depreciation   and  amortization  and
identifiable  assets do not match the  functional  allocations  in Note 3 to the
consolidated financial statements.

(b) Includes  non-cash  impairment loss of $973,000 in 1999,  $3,482,000 in 1998
and $2,179,000 in 1997.



                                       74
<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.

                                         COLUMBUS ENERGY CORP.
                                         -----------------------------
                                                  (Registrant)


Date: February 17, 2000               By: /s/ Harry A. Trueblood, Jr.
      -----------------------             ----------------------------
                                          Harry A. Trueblood, Jr.
                                          Chairman of the Board

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.

       Signature                     Title                            Date
       ----------                    -----                            ----
                          Principal Executive Officer

                                 Chairman of the Board,
                                 President, and Chief
/s/ Harry A. Trueblood, Jr.      Executive Officer                   2/17/00
-----------------------------                                      ---------
Harry A. Trueblood, Jr.

                            Chief Operating Officer

                                 Executive Vice President
/s/ Clarence H. Brown            and Chief Operating Officer         2/17/00
-----------------------------                                      ---------
Clarence H. Brown

                   Principal Accounting and Financial Officer

/s/ Ronald H. Beck               Vice President                      2/17/00
-----------------------------                                      ---------
Ronald H. Beck

                         Majority of Board of Directors

/s/ Harry A. Trueblood, Jr.       Director                           2/17/00
------------------------------                                     ---------
Harry A. Trueblood, Jr.


/s/ Clarence H. Brown             Director                           2/17/00
------------------------------                                     ---------
Clarence H. Brown

/s/ J. Samuel Butler              Director                           2/17/00
------------------------------                                     ---------
J. Samuel Butler

/s/ William H. Blount, Jr.        Director                           2/17/00
------------------------------                                     ---------
William H. Blount, Jr.








                                       75
<PAGE>
                                                      Commission File No. 1-9872



                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549





                                    EXHIBITS

                                       TO

                                    FORM 10-K



                                  ANNUAL REPORT

                         PURSUANT TO SECTION 13 OR 15(d)

                                       OF

                       THE SECURITIES EXCHANGE ACT OF 1934

                   FOR THE FISCAL YEAR ENDED NOVEMBER 30, 1999















                              COLUMBUS ENERGY CORP.
                           (Exact Name of Registrant)

                               1660 Lincoln Street
                             Denver, Colorado 80264
                     (Address of Principal Executive Office)