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, 1998                               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                            
             Denver, Colorado                               80264
 ----------------------------------------                ----------
 (Address of principal executive offices)                (Zip code)

               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, 1999 is $21,335,000.

     Indicate  the  number of  shares  outstanding  of each of the  registrant's
classes of common stock, as of January 31, 1999

                                                     Outstanding at
                Class                               January 31, 1999
   ------------------------------                   ----------------
   Common Stock, ($.20 par value)                   4,000,588 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>


                                     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................................................24
Item 4.  Submission of Matters to a
                Vote of Security Holders..................................24

                                     PART II

Item 5.  Market for the Registrant's Common Equity
                and Related Stockholder Matters...........................25
Item 6.  Selected Financial Data..........................................26
Item 7.  Management's Discussion and Analysis of Financial
                Condition and Results of Operations.......................27
Item 8.  Financial Statements and Supplementary Data......................41
Item 9.  Changes in and Disagreements with Accountants
                on Accounting and Financial Disclosure....................41

                                    PART III

Item 10. Directors and Executive Officers
                of the Registrant.........................................41
Item 11. Executive Compensation...........................................41
Item 12. Security Ownership of Certain Beneficial
                Owners and Management.....................................41
Item 13. Certain Relationships and
                Related Transactions......................................41

                             PART IV AND SIGNATURES

Item 14. Exhibits, Financial Statement
                Schedules and Reports on Form 8-K.........................42

         Signatures.......................................................72




                                       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 another wholly-owned subsidiary. The term "Company" or "EGY" as
used herein includes Columbus and its subsidiaries.

     The  Company  currently  has 34  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.

     On February 24, 1995,  Columbus completed a rights offering to the Columbus
shareholders  to purchase one share of  Resources  for  U.S.$3.25  cash plus two
subscription rights. One right was distributed as a dividend for each share held
of record on January 27, 1995.  All 1,500,000  shares of Resources  common stock
offered  were   subscribed  (and   oversubscribed)   yielding  an  aggregate  of
U.S.$4,875,000 in cash. The total value assigned to the rights for book purposes
was U.S.$582,000  which was the dividend portion of the total divestiture amount
for the Resources' shares. A deduction of $126,000 for the costs of the offering
was  recorded.  No gain or loss  could  be  recognized  for book  purposes  in a
spin-off  and no taxes were due Revenue  Canada as a result of this  divestiture
because Columbus' Canadian tax basis in the Resources' shares exceeded the value
of the rights plus cash proceeds received from the offering.

                                       3
<PAGE>

     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 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.



































                                       4

<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, 1998, 1997 and 1996.

<TABLE>
<CAPTION>
                           PROVED OIL AND GAS RESERVES
 
                                      1998                  1997                 1996 
                               ----------------      ----------------      ----------------       
                                 Oil        Gas        Oil        Gas        Oil        Gas
                                MBbl       Mmcf       MBbl       Mmcf       MBbl       Mmcf
                               -----     ------      -----     ------      -----     ------
<S>                            <C>       <C>         <C>       <C>         <C>       <C>   
Proved reserves:
Beginning of year ........     1,805     18,520      1,643     18,665      2,035     14,858
Revisions of previous
   estimates .............      (713)       767       (127)       226       (278)    (1,335)
Purchase of reserves .....         1        320       --         --           17      4,808
Extensions and discoveries        88      6,355        538      5,066        150      3,190
Production ...............      (221)    (3,499)      (249)    (3,370)      (246)    (2,686)
Sale of reserves .........        --         --         --     (2,067)       (35)      (170)
                               -----     ------      -----     ------      -----     ------
End of year ..............       960     22,463      1,805     18,520      1,643     18,665
                               =====     ======      =====     ======      =====     ======
Proved developed reserves:
Beginning of year ........     1,333     16,122      1,211     15,758      1,384     11,282
                               =====     ======      =====     ======      =====     ======
End of Year...............       762     20,674      1,333     16,122      1,211     15,758
                               =====     ======      =====     ======      =====     ======
</TABLE>


Proved Developed Producing Reserves

     As of November 30,  1998,  Columbus has  approximately  621,000  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
North  Dakota,  Montana and Texas  account for over 97%, and Texas alone 62%, 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 14.4 billion cubic feet of
proved developed  producing gas reserves.  Texas  properties  account for 99% 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.


                                       5
<PAGE>


Proved Developed Non-Producing Reserves

     The  reserves  in  this  category  are  located  in the  states  of  Texas,
Louisiana,  Montana and North Dakota.  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 141,000  barrels of oil, or 15% of
its total proved oil reserves, and 6.3 billion cubic feet of natural gas, or 28%
of its total proved natural gas reserves.

Proved Undeveloped Reserves

     Columbus' proved undeveloped  reserves were  approximately  198,000 barrels
and 1.8 billion  cubic feet of natural  gas.  Almost all of the oil  reserves in
this  category  are in  Montana,  North  Dakota  and  Texas.  All of the  proved
undeveloped  gas reserves are  attributable  to undrilled  locations  offsetting
production in Webb,  Zapata,  Harris and Jim Hogg Counties,  Texas,  Montana and
North Dakota.

     These  reserves are  expected to either be developed  during 1999 or in the
future when oil prices again stabilize at levels which will yield a satisfactory
rate of return on investment  when  developed.  Four  locations in the Williston
Basin  which had been  carried for several  years with  proved  undeveloped  oil
reserves while awaiting  adequate prices which would yield an acceptable rate of
return on  investment  when  drilled  were dropped at fiscal year end due to low
crude prices.  This accounted for 211,000 barrels of the reduction in proved oil
reserves from fiscal 1997 to fiscal 1998.
















                                       6

<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)

                                                  1998        1997        1996
                                               --------    --------    --------
Future oil and gas revenues .................  $ 53,271    $ 79,381    $ 98,555
Future cost:
  Production cost ...........................   (13,688)    (21,856)    (25,620)
  Development cost ..........................    (2,638)     (5,401)     (4,264)
Future income taxes .........................    (6,325)    (11,531)    (14,198)
                                               --------    --------    --------
Future net cash flows .......................    30,620      40,593      54,473
Discount at 10% .............................    (8,691)    (10,422)    (16,313)
                                               --------    --------    --------
Standardized measure of discounted future net
  cash flows ................................  $ 21,929    $ 30,171    $ 38,160
                                               ========    ========    ========


          CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
                FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES
                   FOR THE THREE YEARS ENDED NOVEMBER 30, 1998
                             (thousands of dollars)

                                                  1998        1997        1996
                                               --------    --------    --------
Balance, beginning of year ..................  $ 30,171    $ 38,160    $ 21,392

  Sale of oil and gas net of production costs    (7,397)    (10,708)     (7,556)
  Net changes in prices and production costs    (12,034)    (10,502)     19,446
  Purchase of reserves ......................       310        --         5,158
  Sale of reserves ..........................      --        (1,320)       (229)
  Extensions, discoveries and other additions     6,896       9,660       8,309
  Revisions to previous estimates ...........    (3,406)       (710)     (4,905)
  Previously estimated development costs
    incurred during the period ..............       586       1,089         729
  Changes in development costs ..............     2,066         229         570
  Accretion of discount .....................     3,730       4,653       2,416
  Other .....................................    (2,066)     (1,620)     (1,571)
  Change in future income taxes .............     3,073       1,240      (5,599)
                                               --------    --------    --------
Net increase (decrease) .....................    (8,242)     (7,989)     16,768
                                               --------    --------    --------
Balance, end of year ........................  $ 21,929    $ 30,171    $ 38,160
                                               ========    ========    ========

                                       7
<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, 1998,  1997 and
1996.  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
$25,986,000 in 1998,  $37,301,000 in 1997, and  $46,530,000 in 1996. 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,  1998 the  crude oil price
(including  natural gas liquids) was $11.29 per barrel and the natural gas price
was $1.89 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.

                                       8
<PAGE>


     Both 1998 and 1997 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, 1998,
1997 and 1996.  The  reports 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     
                                ---------------------------              
                                   1998      1997      1996
                                --------  -------   -------
Oil-barrels                     221,000   249,000   246,000
Gas-Mmcf                          3,499     3,370     2,686
               
     During the  fiscal  year  1998,  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
1997.  This data was  reported on a gross  operated  basis  inclusive of royalty
interest and,  therefore,  does not compare with Columbus' net reserves reported
for 1997.

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

                                          Fiscal Year    
                                 --------------------------              
                                  1998      1997      1996
                                 -------  -------   -------
Average sales price:
   per barrel of oil ......      $13.22    $19.62    $19.42
   per Mcf of gas .........      $ 2.18    $ 2.65    $ 2.15
Average production cost per      
  equivalent barrel .......      $ 4.00    $ 3.83    $ 4.35
                              
     Natural gas  converted to oil at the ratio of six Mcf of natural gas to one
barrel of oil.  Production  costs for fiscal  years 1998,  1997 and 1996 include
production taxes.

                                       9
<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, 1998                     Gross                        Net     
-----------------                ----------------            --------------   
                                 Oil          Gas            Oil        Gas
                                 ---          ---            ---        ---
Wells                            81           161            21         20

Acres                                35,520                      10,493

Undeveloped Properties

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

November 30, 1998                     Gross Acres                 Net Acres
-----------------                     -----------                 ---------
  Louisiana                             23,376                       2,271
  Montana                               12,980                       7,706
  New Mexico                               840                         630
  North Dakota                           1,790                         395
  Texas                                  6,792                       3,256
                                        ------                      ------
Total Undeveloped Properties            45,778                      14,258
                                        ======                      ======




















                                       
                                       10

<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,            
                             --------------------------------------------------------------      
                                  1998                   1997                   1996     
                             ----------------      ----------------     -------------------
                             Gross       Net       Gross       Net      Gross          Net
                             -----       ---       -----       ---      -----          ----
<S>                            <C>       <C>        <C>        <C>        <C>          <C>
EXPLORATORY                                                           
Wells Drilled:                                                        
    Oil ................       2         1.10        2         1.45       --             --
    Gas ................       3         1.69        1          .37       --             --
    Dry ................       2          .92        1          .34        2            .68
DEVELOPMENT                                                             
Wells Drilled:                                                          
    Oil ................       1          .67        4         1.91        2           1.00
    Gas ................       8         1.06       18         2.71       14           2.60
    Dry ................       4         1.23        3          .65        6           2.95
TOTAL                                                                   
Wells Drilled:                                                          
   Oil .................       3         1.77        6         3.36        2           1.00
   Gas .................      11         2.75       19         3.08       14           2.60
   Dry .................       6         2.15        4          .99        8           3.63
                              --         ----       --         ----       --           ----
       Total ...........      20         6.67       29         7.43       24           7.23
                              ==         ====       ==         ====       ==           ====
</TABLE>
                                                                    
                                                                    
                                                                    
                                                                  

















                                       11
<PAGE>

Current Activities

     During  fiscal  1998,  management  shifted  Columbus'  emphasis and capital
budget almost entirely to the  exploration  for, and development of, natural gas
reserves. However, early in fiscal 1998 the Company was involved in completing a
well drilled in fiscal 1997, a successful  12,000-foot  Red River  formation oil
discovery in the Montana portion of the Williston Basin. Since the low crude oil
prices  existing at the  beginning of fiscal 1998 only got worse,  Columbus also
limited its  participation in drilling  activities for oil to only when required
to prevent  drainage.  The 1998 budget formulated in November 1997 included some
3-D seismic plus  exploration  and  development  drilling on existing  leasehold
blocks in the Williston  Basin which was scrapped.  Those funds were diverted to
an exploration  program for natural gas reserves along the Texas Gulf Coast from
east of Houston to northwest of Corpus  Christi.  The 1998 budget also  provided
for continued  natural gas  development  drilling  south of Laredo,  Texas where
Columbus,  or its former parent,  has been involved for over 25 years.  Although
natural  gas prices  weakened  somewhat in latter  fiscal  1998,  they  remained
sufficiently  high for the  capital  expenditure  budget of  approximately  $6.5
million to be completed. Actual cash expended during the 12 months exceeded $7.1
million,  but this amount also  included  payment of  significant  accrued costs
associated  with wells in progress  as the prior year came to a close.  The very
successful wildcat program resulted in three natural gas discoveries out of five
prospects drilled in this onshore Gulf Coast of Texas exploratory  program which
has enhanced fiscal 1999's outlook for expanding natural gas reserves.

     The  more  significant   recent  activities  appear  below  and  have  been
segregated into Columbus' primary areas of operations:

South Texas - Laredo Area
-------------------------

     This continues to be the most important area for well operations  since 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 few years,  Columbus has almost continuously kept at least one
rig  drilling  infill,  extension,  and new fault  block  locations.  These were
identified  by a 3-D seismic  program which was  conducted  and  interpreted  in
1994-95.  During 1998, drilling was halted on two occasions after some wells did
not  find the  expected  new  fault  block  reservoirs  and  were  completed  as
additional  wells in existing  producing  fault blocks.  Also,  three  locations
proved to be unsuccessful.  As a consequence,  during 1998 only seven (0.41 net)
successful  natural  gas wells were  completed  while three (0.62 net) dry holes
were drilled which compares with  participation in 18 gross wells in 1997 and 12
gross wells in 1996.


                                       12
<PAGE>

     In the B. R. Cox field, Columbus attempted one recompletion effort of a gas
zone  behind  pipe in one of the two  inactive  gas  wells in this  field.  This
workover had been postponed  pending a large working interest owner's  agreement
to advance their share of the funds or else suffer non-consent  penalties.  That
owner  finally  agreed to  participate,  but after the new zone flowed gas for a
short period,  the casing  collapsed in this old  wellbore.  None of the working
interest  owners were willing to spend the funds  required to remedy the problem
so the well is a candidate for farmout, sale, or abandonment. Two other proposed
recompletions in new zones behind pipe or to drill the one remaining undeveloped
location in this field await approval by other working interest  owners.  During
latter  1997,  the  Company  sold a  producing  property  from this field and is
currently considering selling the balance of its interests in existing wells and
leaseholds.

Sralla Road Field Area - Harris County, Texas
---------------------------------------------

     This  upper  Gulf  Coast  area is  located  east of  Houston  and has  been
Columbus'  primary source of field level cash flow  throughout the decade of the
1990's.  During fiscal 1998, drilling  operations  continued to be successful as
Columbus,  as operator,  developed additional Jackson Sand crude oil and natural
gas reserves in four separate wells.  Two oil development  wells were drilled in
the field's north end in the oil leg of the reservoir in order to prevent offset
drainage and both wells were completed as flowing high gas/oil ratio wells.  The
Company owns 67% and 65% working interests therein and a similar interest in the
Fig Orchard #1 gas well which was  recompleted  as a  sidetracked  gas  producer
after the casing had collapsed in the original wellbore.  The fourth well (19.5%
WI) was an  exploratory  well on the south end which was projected to extend the
gas cap of this Jackson Sand  reservoir by about one and one-half  miles but the
wellbore was on the other side of an unknown cross fault  separating it from the
gas cap. It found an oil discovery instead as the Jones #1 tested 240 barrels of
oil per day flowing  through an 8/64th  choke and has remained  shut-in  pending
completion  of a gas  gathering  system  since no gas  flaring is  allowed.  The
installation  of a pipeline has proved a challenge since the Jones #1 is located
in an area with  considerable  residential  development  made up of both primary
homes and second homes near the San Jacinto River.  Although  Columbus  operates
this well,  the pipeline  construction  is being pursued by the largest  working
interest  owner in the  Jones #1 who also  owns  most of the  acreage  and wells
nearby.  Obtaining  the permits  necessary to install the  gathering  system has
proved very  frustrating but is expected to be completed by the end of the first
quarter of fiscal 1999.


                                       13
<PAGE>

     About 20 miles east of the Sralla Road field,  the Company  participated in
July 1997 in a  successful  exploratory  discovery  in the Frio 16 Sand near the
famous old Anahuac  field in  Chambers  County,  Texas.  The  Syphrett  Heirs #1
initially  tested for 4.6 million cubic feet per day and has sold  approximately
100  million  cubic feet per month  throughout  fiscal  1998 and has been one of
Columbus' most prolific producers.  The Company originally owned a 27.5% working
interest  as of the end of fiscal  1997,  but this was  subsequently  reduced by
"back-ins" to an approximate 26% working interest.

     The  Company  owned a  similar  interest  in  approximately  600  acres  of
leaseholds to the south of that  discovery.  Available  seismic  indicated  that
there were two  separate  drillable  prospects on this  acreage  which  probably
needed to be tested  before  leases  expired.  These two  seismic  features  are
separated by a fault with the largest being located on the downthrown side which
was chosen as the initial  location for an  exploratory  test.  The Quinn #1 was
drilled to the Frio 15 Sand at about  9,000  feet and a very thick sand  section
was  encountered  but  contained  water with a slight  show of natural gas and a
second test well is not planned at present.

Williston Basin Area
--------------------

     Prevailing low crude oil prices  throughout  fiscal 1998 brought  potential
new activity in this area of  operations  to a halt.  Unfortunately,  a drilling
program  had  already  been  commenced  during  fiscal  1997 and had mostly been
completed  prior to the sharp decline in crude oil prices.  The 1997 3-D seismic
program on the southern  portion of this block of Montana acreage  indicated Red
River  formation  structures  were present,  but  subsequent 3-D seismic in 1998
found no drillable  deep  structures.  During the fall of 1997, one of those Red
River  structures  was  tested  and the  90%-owned  McCabe  Farms  #1-4 well was
successfully  completed in December 1997. This 12,000-foot well pumped initially
at a rate of 86  barrels  of oil per day with a like  amount of water  which was
disappointing  since such a high water cut had not been  indicated on either the
logs or in a drillstem test.  Subsequently,  a second  exploratory well tested a
Tyler Sand zone at about 7,000 feet which was a dry hole  because the  indicated
channel on 3-D seismic was filled with reworked shale and lime with only limited
sand.  No further  tests of this channel are planned.  There was another test of
the Tyler Sand in North Dakota when a behind pipe zone was perforated in a cased
wellbore of a Mission Canyon producer which was ready for abandonment. It flowed
nitrogen  at a rate in excess of 2 million  cubic  feet per day.  Unfortunately,
there is no current  market for a prolific  nitrogen  well  having less than 10%
methane and it will most likely be abandoned  during 1999.  Also,  continued low
crude oil prices  resulted in over half of the operated  wells in the  Williston
Basin being rendered uneconomic and have either been shut down or else are being
operated only a few days of each month.


                                       14
<PAGE>

Goudeau Prospect - Avoyelles and St. Landry Parishes, Louisiana
---------------------------------------------------------------

     This  deep  geo-pressured  Austin  Chalk  prospect  proved  to  be  a  very
disappointing  area for the industry in general and for  Columbus in  particular
even though it only  participated in one re- entry well. The Morrow #23-1H was a
15,000-foot  wellbore which had been cased and abandoned several years ago by an
unrelated  operator  when an attempted  completion in a deeper  horizon  failed.
Belco Oil & Gas, as  operator  of the  prospect  and the major  interest  owner,
agreed to drill  updip and  downdip  laterals  of about  4,000 feet each in this
cased wellbore at no expense to Columbus and its co-venturers who had originated
this  prospect  area.  However,   Belco  apparently  became  disenchanted  after
completion  of an updip  lateral  only.  When it  announced  it would move on to
another well and not finish its  obligation  for a downdip  lateral for Columbus
and  co-  venturers,   there  were  strong  exceptions  taken.  Following  hasty
negotiations,  Columbus  et  al  took  over  the  wellbore  and  Belco  withdrew
altogether  from the  2,560  acre  unit.  What  ensued  thereafter  proved to be
expensive  as numerous  problems  were  encountered  while  drilling the downdip
lateral.  These have been  previously  reported and need not be recounted  here.
Therefore,  instead of having a relatively  small  working  interest and limited
cost exposure in this exploration well, Columbus et al bore the entire expensive
undertaking  which bordered on a disaster  because of attempted  blowouts,  lost
circulation,  and mechanical problems with the drilling equipment.  These became
so intense that the venturers settled for only a 1,200-foot downdip lateral. The
initial rate of produced  fluid was  extremely  high from this short  lateral at
over 66 barrels per hour but unfortunately only 21% was oil initially and during
its subsequent 14 months of production,  this geo-pressured zone's flow rate has
declined  slowly to only 11 barrels of oil per day as the  percentage  water cut
steadily  increased.  At current prices, the well is marginally economic but had
the cut been reversed,  payout would  probably have already been  achieved.  Any
further  attempt to drill a second downdip  lateral,  or to open up the existing
updip lateral which is below bridge plugs and a whip stock,  cannot presently be
justified  based on current prices.  Also,  Columbus has no plans for additional
participation in drilling deep geo-pressured  Austin Chalk wells in Louisiana so
this geologic province has been eliminated as a potential new core area.

El Squared Prospect - Bee County, Texas
---------------------------------------

     This prospect area has been described in earlier 1998 quarterly reports and
news releases as one of the most exciting areas for potential  reserve increases
that has been added as a new  Columbus  operational  area since the Sralla  Road
discovery east of Houston in 1990. At present this  prospect's  leaseholds  have
grown to  approximately  5,500 acres in size and prior to the  Company  becoming
involved were fully covered with a 3-D seismic program.  Columbus currently owns
a 55% working interest (42% NRI) while three of its regular drilling  associates
own 20% working interests and the oil company which originated the prospect owns
the remaining 25%. After acquiring participation,  Columbus had the seismic data
processed and interpreted by an outside expert.  Ownership rights in the initial
4,000-acre  block acquired were limited by depth to formations  below 7,000 feet
which  in  this  immediate  area  primarily  consists  of  several   potentially
productive gas sands in the Wilcox formation from 9,000 feet to 17,000 feet. All
depths are available in the additionally acquired acreage.


                                       15
<PAGE>

     The initial  interpretation of the 3-D seismic indicated there were several
significant  "bright  spots" as well as  numerous  separate  fault  blocks  that
included   both   antithetic   (up-to-the-coast)   faults   as  well  as  normal
down-to-the-coast  faults at various depths. Based on information in the general
area  available  from prior  drilling as well as from  producing  fields nearby,
there are several  different zones of the Wilcox  formation with local names for
the sand intervals that are considered  prospective in this leasehold  block. In
the upper Wilcox there are two or three Slick Sands beginning at depths of about
9,500 feet, two or more Luling Sands  beginning at about 10,200 feet, a Mackhank
Sand beginning  around 11,300 feet, at least two Massive Sands beginning  around
12,000  feet,  and three or more  Reagan  Sands  below  14,000  feet.  Available
information also indicates that all of these reservoirs  should be geo-pressured
with bottom hole pressures ranging from around 6,000 psi at the Slick Sand level
to over  13,000 psi in the deeper  Reagan  Sands.  This  indicates  there can be
significant  reserves of natural gas with porosities of 15% to 22% and a cut-off
at 10%.  Initial seismic  interpretation  also indicated that there are probably
several  individual  fault  blocks that range in size from small in surface area
(100 acres or less) up to several  hundred  acres.  More important is that these
Wilcox Sands appear to have gross thicknesses of 40 feet to 180 feet so with the
reservoirs geo-pressured, significant accumulations of natural gas reserves in a
successful well can occur even if a fault block for a particular reservoir might
be small.  This in effect  defines this  prospective  area as one with  vertical
reserves  potential rather than one with a large geographic areal extent such as
the Hugoton  field.  This area may still require  several  wells fairly  closely
spaced on the surface in order to exploit the reserves at the  different  levels
in their most structurally favorable positions.

     The initial  wellsite for the Long #1 was  selected  using 3-D seismic such
that the vertical  wellbore  would  penetrate  the upper Slick Sand  immediately
underneath a sealing  up-to-the-coast  fault and place the Slick reservoirs near
the apex of their structure. While the deeper Luling Sand zones were expected to
be prospective  even though further down on structure,  they hopefully  would be
found above their gas-water contacts.  If this were not the outcome, a second or
even  a  third  wellbore  might  be  required  to  penetrate  all  Luling  Sands
sufficiently  high on structure.  In the first well, the company who created the
prospect  was  carried to total  depth for a 25%  working  interest  only in the
initial test well and participated in the completion operation expenses.


                                       16
<PAGE>

     Columbus owns a 55% working interest (42% NRI) in the Long #1. It proved to
be a  successful  natural  gas  discovery  and  was  completed  in  38  feet  of
perforations in two separate Slick Sand intervals which had gross thicknesses of
46 and 37 feet, respectively,  between the depths of 9,704 and 9,835 feet. There
was also a third Slick Sand  encountered in the Long #1 which had about 180 feet
of gross  interval.  It tested gas for a few hours at the rate of  approximately
750  thousand  cubic  feet per day but also  produced  formation  water and lost
circulation  drilling mud from 40 feet of  perforations  in the cased hole which
were left open underneath a bridge plug to be produced later. Only the two upper
Slick zones were completed since electric logs indicated that the Luling "A" and
"B" Sands had fairly high water  saturations,  would  probably be borderline gas
productive  zones,  and should be  completed  in another  wellbore  structurally
higher. The Long #1 was placed on production in early October and has sold about
60 million  cubic feet per month along with six to eight  barrels of  condensate
per million cubic feet. Initially the Long #1 also produced formation salt water
at over 80  barrels  per  day but  this  rate  declined  fairly  rapidly  and is
currently about 25 barrels per day. Initial estimates of reserves for all of the
Long #1 Slick Sands  producing  as well as  non-producing  under the bridge plug
approximated  eight billion cubic feet.  With Columbus' net revenue  interest of
about 42%, this was an extremely  important  addition to its reserves as well as
future cash flow.

     Unfortunately,  Wilcox Sands are known to have swelling clays that are very
sensitive to contact with water. Accordingly, fracture stimulation was initially
deferred for the Long #1 but a treatment is now being  formulated  and should be
undertaken  in the very near future when a portion of the tubing  string must be
replaced  because of corrosion.  Evidence of the severity of the clay problem in
this area could be more  carefully  examined  in the second  well,  the Long #2,
because  it did not  have as  much  lost  circulation  problems.  Management  is
developing a program which will help  overcome  future  severe  wellbore  damage
created  while  drilling  through  the sands or by  subsequently  allowing  non-
treated fluids to come into contact with the producing sands. The latter problem
was observed  recently in the Long #1 whereby merely  shutting-in  for treatment
for corrosion in the tubing  production  string actually reduced the well's flow
rate  from  approximately  2 million  down to 1.7  million  cubic  feet per day.
Management  has recently  determined  that even though this gas contains only 4%
carbon  dioxide it appears  that when this amount is combined  with the produced
water that corrosion is occurring and must be addressed in both wells as well as
in future  wells.  By proper  advance  planning,  these types of problems can be
reduced or overcome  so there  appear to be sizable  reserves to be  established
with  appropriate  safeguards  and completion  techniques.  Although these wells
might be  completed  naturally  with no fracture  stimulation,  it will become a
necessity  at some point to  facilitate  recovery of sizable  reserves in a more
reasonable  period of time.  An example is the  postponed  fracture  stimulation
during  original  completion  of the Long #1 which should now be  undertaken  in
order to open the  undamaged  reservoir  to the  wellbore.  During  the next few
weeks,  a fairly limited  stimulation  which will probably use condensate as the
frac  carrying  fluid is  proposed  for this  well and is  expected  to create a
significant  improvement  in its  daily  productive  capability.  Assuming  this
initial treatment desatment design proves  satisfactory,  it will be employed in
future  completions.ign  proves  satisfactory,  it will be  employed  in  future
completions.


                                       17
<PAGE>

     At the end of 1998, the Long #2 had been drilled to a total depth of 11,000
feet and had been cased with 7" production  casing in  anticipation  that a dual
completion  could be accomplished  in the Slick and Luling Sand intervals.  This
was based  primarily on log analysis of each of the sands using the known values
for the Slick Sand formation  water that was actually being produced in the Long
#1. This also  assumed  that the  formation  water in the third Slick Sand,  the
Luling "A" Sand,  and the Luling  "B" Sand would have  similar  characteristics.
Furthermore,  there was a wireline  formation  test run in the basal  Luling "B"
interval which had fairly low resistivity on the logs yet recovered some gas and
water which was relatively  fresh and interpreted as mud filtrate  water.  There
were significant indications of mud invasion into each of the sand intervals and
water from the wireline  formation tester did not remotely resemble more heavily
salt saturated water from the Slick being produced only 700 feet away. Using the
resistivity of produced water in the  calculations for gas saturation in each of
the main sand zones in the three prospective intervals,  the logs indicated that
there was net gas pay in the wellbore which probably exceeded 140 feet. With the
known  geo-pressured  conditions present based on results from wireline pressure
tests, the reserve potential of this well appeared to be fairly sizable. Because
this  potential  addition  to natural  gas  reserves  appeared  so  significant,
management  felt  compelled  to make a press  release  that  would at least  put
shareholders  on notice of such a  possibility  even though the well had not yet
been perforated or tested in any of the zones at that point in time.

     Insofar as the Long #2's third Slick Sand was  concerned,  it had  produced
gas in the Long #1  previously  and there was a  wireline  formation  test which
yielded gas and a lesser amount of fresh mud filtrate water. Also, this sand was
about 140 feet structurally  higher than the first well so management was fairly
confident as to its probable gas productivity. In the instance of the two Luling
Sands, they were not penetrated at their maximum structural position immediately
beneath  the  up-to-the-coast  sealing  fault in order that at least some of the
third Slick Sand would be present in the  wellbore.  These two Luling zones were
expected to be at least 100 feet higher  structurally than in the Long #1 and it
wasassumed this amount would yield a sufficiently high structural position for a
water-free  completion in those two sands.  Management felt that  sacrificing an
additional  150 feet of  available  structure  would not prevent them from being
productive and it was important to get a dual zone gas completion at the Long #2
location.


                                       18
<PAGE>

     As so often  occurs  in the  exploration  phase of this  business,  results
obtained are not always what are anticipated  using  analogous  information as a
guideline with which to formulate an opinion. For example, the basal ten feet of
the Luling "B" was  interpreted on the logs as having low resistivity and was on
the borderline of indicated gas/water contact, but a wireline formation test did
yield some gas and mud  filtrate  water.  It  subsequently  gave up water  after
perforating  with no show of gas and  surprisingly  the produced water from this
basal zone was  significantly  less  saturated  with sodium  chlorides  than the
produced water from the Long #1 Slick Sand  interval.  Assuming this water was a
representative  sample of Luling water, it significantly  changed all of the gas
saturation  calculations that had been made for both of those zones.  Presumably
the third  Slick  Sand  calculations  should  not be  affected.  Using  this new
resistivity,  the basal 10 to 15 feet of the  Luling "B"  calculated  high water
saturation  but the  remainder  would be  expected  to  produce  gas along  with
formation  water.  Complicating  such  calculations is the clay content of these
sands which tends to hold immobile water.  Several feet which  calculated as gas
pay were cement  squeezed also in order that an attempt to  separately  test the
upper portion of the Luling "B" could be undertaken.

     Obviously,  management has been sorely disappointed with the Luling results
but has not been able to obtain a satisfactory  explanation  from experts in the
area as to how or why the salt  saturations  in the  water  from the  Slick  and
Luling zones can be so vastly  different.  Had  management  known such to be the
case,  it would have  entirely  changed  proposed  completion  procedures in the
various  intervals with a more selective  perforating  program.  The problem was
further  exacerbated  by the fact that  apparently the primary cement job behind
the 7" casing is fairly poor  according  to a cement bond log.  This limited the
ability to treat  individual  zones for formation  damage which occurred  during
drilling  operations.  Without  treatment there can be no certainty that any gas
present in the sands will be produced  along with the water  recovered  from the
Luling "B" during swabbing operations. Since the Luling "A" Sand appears to have
been  similarly  affected by drilling  fluids and  presumably  contains the same
water  characteristics  found below,  management decided to temporarily leave it
untested in this wellbore and proceed with a block squeeze  cement program for a
third Slick Sand single zone completion.

                                       19
<PAGE>

     As of early February,  1999 the Long #2 had been successfully  completed in
30 feet of  perforations  in the 120 foot lower  Slick Sand zone from a depth of
9,906 to 9,936 feet which were  fracture  stimulated  with 25,000 pounds of frac
sand using condensate as the carrying fluid.  During initial  cleanup,  the well
flowed  natural gas through a 11/64th inch choke at the rate of 1,781,000  cubic
feet per day along with frac  condensate and water at a daily rate of 66 barrels
and six barrels  respectively.  Flowing  tubing  pressure was 3247 psi. The well
will be flowed on a temporary basis at this lower rate pending the  construction
of a gathering line of larger diameter pipe.

     It now appears  evident  that in order for these  Luling  Sands to be found
productive of natural gas and water free, they must be penetrated at the apex of
the  structure  which would place them as much as 150 feet  structurally  higher
than in the present Long #2 wellbore.  While it is disappointing  not to be able
to use this  larger  diameter  casing  for a dual  completion,  this will  prove
helpful for drilling to the deeper and higher pressured formations in future. We
will be able to use large diameter drilling tools and cross the sealing fault at
the best  possible  structural  position  for either the Mackhank or the Massive
Sands of the middle Wilcox.  There is also an  alternative  that a window can be
cut and a wellbore  drilled  directionally  to the structural apex of the Luling
from this existing cased  wellbore at a later date when the Slick  reservoir has
been depleted.

     Management  has not  wavered in its belief  that this  Prospect  Area holds
significant  potential for rapidly  growing the Company's  natural gas reserves.
However,  it has become painfully evident from its experience with the first two
wells that  further  attempts to achieve dual  completions  in this type of high
structural  relief  environment is neither  realistically  practical nor truly a
money  saving  approach  for rapid  extraction  of  reserves.  Each  prospective
reservoir  in every  fault  block  apparently  must be  drilled  at the  optimum
structural  position.  Also, a drilling and completion  program must be designed
which will  minimize the damage to the clays  contained  in these  sands.  It is
extremely  frustrating to have to accept producing  wellbores in the range of 10
billion  cubic feet of reserves  instead of multiple  sand  completions  with 25
billion cubic feet of reserves.  Management must adopt this general concept as a
wellsite location guideline for most wellbores in this area in future.

Heidi Prospect - Jim Wells County, Texas
----------------------------------------

     This Vicksburg  formation gas prospect near Alice,  Texas is fairly shallow
at 5,800 feet deep with three potentially  productive sand zones which are known
locally as the Bierstadt,  the Alice and the Stillwell sand in descending  order
beginning at about 5,100 feet. In the initial  discovery  well,  the latter sand
was tight with minimal  shows while both the Alice and  Bierstadt  had excellent
gas  shows in well  developed  sands  but  were  extremely  close  to  gas-water
contacts. Only the Bierstadt interval could be completed as a water free natural
gas  discovery  well and has been  flowing for several  months at about  300,000
cubic feet per day.  Based on 3-D seismic  conducted  by another  company  which
became available in exchange for permission to shoot across these leaseholds, it
appeared that at least one or more well sites could be selected that could be 20
to 30 feet  structurally  higher  than  the  Bernsen  #1  discovery  well at the
Vicksburg level and an interesting  deeper structure  appears  prospective for a
test well for  horizons in the Yegua and below.  The Company  owns a 62% working
interest (48% NRI) in this discovery well and the prospect area.

                                       20
<PAGE>

     Recently,  the  Company  drilled  the  Bernsen #2  location  using that 3-D
seismic data for the well site  location and found the Bierstadt and Alice zones
about 16 feet and 24 feet  higher  structurally,  respectively.  For reasons not
entirely clear,  the logs showed  gas-water  contacts to have moved up also with
the  structural  improvement  although  wireline  formation  tests of both zones
showed them to be gas  productive.  Since 4 1/2 inch casing was run in the well,
only the  Bierstadt  has been  completed  as a single zone gas  producer in case
water has to be handled along with the gas. After perforating the zone, the well
instantaneously  began flowing at the rate of  approximately  200,000 cubic feet
per day through a small 6/64th inch choke with 1300 psi flowing tubing  pressure
and no formation water. The well has been turned to sales and its flow rate will
continue to be highly restricted and monitored to make certain that bottom water
is not being coned upward after which time it will be increased.  An offset well
will be  required  in due  course  to  protect  offsetting  royalty  owners  not
presently included in this drill site.

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.


                                       21
<PAGE>

     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.

     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 well head  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,  1998,  1997  and  1996,  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.

                                       22
<PAGE>

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.

     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.

                                       23
<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.  The
Order is complex  and,  while it faces  challenges  in court,  it has been fully
activated  following  a  rehearing  with  minimum  modification  and  subsequent
reissuance as FERC Order No. 636A. The Company is not able to predict the extent
to which this very  complex  order will change the industry in the long term but
short  term it has led to much  more  competitive  markets  and  raised  serious
questions about whether  gathering  systems of interstate  pipelines can be sold
off and totally escape regulation.

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 District  Court of
Harris County, Texas. The plaintiffs claim that Columbus breached the settlement
agreement  reached in  September  1994 of their  previous  lawsuit by failing to
develop  properties  located within the area of mutual interests and to act as a
reasonably  prudent  operator in the  development  of the  property.  Plaintiffs
allege  damages  under the  contract  but no amount is  specified.  Columbus has
responded with a First Set of Interrogatories to plaintiffs. Columbus denies all
of the plaintiffs' allegations.

     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.

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

     During the fourth  quarter of 1998, no matters were  submitted to a vote of
security holders.

                                       24
<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)
                                                -------           ------ 
1999:
  December 1, 1998 through
     January 31, 1999 ....................   $    6.75         $    6.50

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

1996:
  First quarter ..........................   $    4.18         $    3.64
  Second quarter .........................        5.82              3.91
  Third quarter ..........................        8.27              5.09
  Fourth quarter .........................        7.91              6.91


(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 29, 1999 the reported  closing sales price of Columbus common
stock was $6.625 per share.

     As of November 30, 1998, there were  approximately 440 holders of record of
Columbus'  common stock and an estimated 900 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.


                                       25
<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,
1998, 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,      
                                      ----------------------------------------------------                         
                                        1998       1997       1996      1995(a)     1994
                                      ---------  ---------  ---------  ----------  -------
                                               (in thousands, except per share data)
<S>                                   <C>        <C>        <C>        <C>        <C>   

Operating data:
  Revenues .........................  $ 12,094   $ 15,096   $ 11,815   $  9,400   $ 13,141
  Loss on asset disposition,
    impairment of long-lived
    properties and abandonments ....    (3,482)    (2,179)      (165)    (3,055)      --
  Net earnings (loss) ..............    (1,235)     2,167      2,098     (1,495)     2,190
                                        =======    =======    =======    =======    ======
  Earnings (loss) per
    share(b):
    Basic ..........................  $   (.29)  $    .50   $    .50   $   (.35)  $   .49
                                        =======    =======    =======    =======    ======
    Diluted ........................  $   (.29)  $    .49   $    .49   $   (.35)  $   .48
                                        =======    =======    =======    =======    ======
  Weighted average number of
    common and common equivalent
    shares outstanding(b):
    Basic ..........................     4,194      4,299      4,211      4,321      4,495
                                        =======    =======    =======    =======    ======
    Diluted ........................     4,194      4,392      4,259      4,321      4,546
                                        =======    =======    =======    =======    ======
Cash flow data(d):
  Cash from operating activities ...  $  6,258   $  8,638   $  5,638   $  3,929   $  6,194
  Cash used in investing activities   $ (6,717)  $ (7,294)  $ (6,320)  $   (119)  $ (7,194)
  Cash provided by (used  in)
    financing activities(c) ........  $    605   $   (883)  $    664   $ (4,223)  $    519
  Cash flow before changes in
    operating assets and liabilities  $  5,470   $  9,132   $  6,340   $  3,920   $  6,254
  Discretionary cash flow ..........  $  6,192   $  9,672   $  6,658   $  4,096   $  6,715
Balance sheet data:
  Total assets .....................  $ 23,949   $ 26,135   $ 21,625   $ 18,321   $ 24,955
  Long-term debt, excluding
    current maturities - bank debt .  $  4,900   $  2,200   $  2,200   $  1,600   $  4,200
  Stockholders' equity .............  $ 15,264   $ 17,958   $ 16,225   $ 13,186   $ 16,202
</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".

                                       26
<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

     Fiscal 1998 yielded the lowest  average  worldwide  and domestic  crude oil
prices in more than ten years for the domestic  industry and for  Columbus.  The
Company's  average  natural  gas prices  were lower than in 1997 but natural gas
production  was up 4% compared  to 1997.  Also,  fiscal  1998 had  substantially
higher exploration expenses and impairment charges that generated a net loss and
overshadowed  record natural gas production.  Those charges  totaled  $4,204,000
which, after being tax effected, reduced net earnings by $2,606,000 or $0.62 per
share and resulted in a loss of  $1,235,000,  or $0.29 per share.  Discretionary
Cash Flow in 1998 of $6,192,000 was primarily reduced by weak product prices and
lower oil production and was significantly lower than 1997's record cash flow of
$9,672,000.  Gross  revenues  and oil and gas sales were also lower in 1998 with
prices the primary culprit.

     As of the end of 1998,  shareholders'  equity had decreased to  $15,264,000
compared to  $17,958,000  at November  30,  1997 due to higher  exploration  and
impairment charges and repurchase of treasury stock. Positive working capital of
$1,556,000 at year end,  combined with the Company's  anticipated  cash flow for
1999 should  provide  sufficient  funds for the  expected  fiscal  1999  capital
expenditure program. This primarily includes developing undeveloped reserves and
funding an exploratory  program in the lower Gulf Coast area near its El Squared
discovery.  Success to date with the Texas exploratory wildcats in this area has
been extremely  encouraging.  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 there be  unforeseen  capital  expenditures  required
during 1999.

     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  $5,600,000  to  $8,600,000  during the last three years
which,  coupled  with  use  of  the  Company's  credit  facility,  has  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.

                                       27
<PAGE>


     However,  management places greater reliance upon an important  alternative
method of computing cash flow generally known as Discretionary Cash Flow ("DCF")
(which is not GAAP but is commonly used in the industry). This method calculates
cash flow before  considering  either  working  capital  changes or deduction of
explora  tion   expenses  as  the  latter  can  be  increased  or  decreased  at
management's discretion.  DCF is often used by successful efforts companies when
making  comparisons  with the cash flow results of independent  energy companies
which  use the full  cost  accounting  method  where  exploration  expenses  are
capitalized and therefore do not adversely  affect either operating cash flow or
net earnings  immediately.  Columbus' DCF for 1998 was $6,192,000 which compared
to  1997's  $9,672,000  (an all time  record)  and was a 36%  decrease  that was
primarily attributable to prevailing lower crude oil and natural gas prices. DCF
is also calculated  without debt  retirements  being considered but in Columbus'
case it does not  matter  since  outstanding  bank debt  requires  no  principal
payments before August 1, 2000.  Interest  expense on the  outstanding  debt has
been  relatively  insignificant  and is always  deducted  before  computing  DCF
anyway.

     Management  continues to note in all public  filings and reports its strong
exception  to the  Statement  of  Financial  Accounting  Standards  No. 95 which
directs that operating cash flow must only be determined after  consideration of
working capital changes. This position is based on our belief 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  has on working  capital  where  Columbus  owns only a small  working
interest but is the operator.

     However, neither DCF nor operating cash flow before working capital changes
may 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 1998 GAAP cash flow was higher than DCF and, for
the prior two years, it was the reverse.

     At the present  time the Company has no hedges in place of either crude oil
or natural  gas prices  similar to those swaps it  negotiated  in prior years as
discussed below. Therefore, the Company's current oil and gas revenues are fully
exposed to risk of declining  prices such as have  occurred most of fiscal 1998.
Thus,  it will be able to fully  benefit from any price  increases  should these
occur during fiscal 1999.

                                       28
<PAGE>

     In prior years  Columbus  hedged  both  natural gas and crude oil prices by
entering into "swaps" which were 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.  The following  table shows the
results of these swaps:

                                                         Increase (decrease) in
                                                          oil and gas revenues 
                          Volume                        ------------------------
Description               per mo.        Period           1997           1996
-----------           --------------   -----------     ----------     ----------
                      (Mmbtu or bbl)
Natural Gas

$2.20/Mmbtu .......       60,000       3/97-10/97      $ (86,400)   
Futures Contracts .       60,000       10/96-11/96                    $  42,000
$1.74 & $1.88/Mmbtu      120,000       4/96-11/96                     $(560,000)
                                                                    
                                                                    
Crude Oil                                                           
                                                                    
$21.17/bbl ........       10,000       11/96-10/97     $   8,900      $ (23,800)
$17.25/bbl with                                                     
  $19.50/bbl cap ..       10,000       1/96-12/96      $ (22,500)     $(232,300)

                                                                   
     The  Company's  natural gas and crude oil swaps were  considered  financial
instruments  with  off-balance  sheet risk  which  were 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 no natural gas or crude oil swaps outstanding as of November 30,
1998.

     Columbus had  outstanding  borrowings of $4,900,000 as of November 30, 1998
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 1998, the ratio of
bank debt to  shareholders'  equity was 0.32 and to total  assets was 0.20.  The
outstanding  debt used a LIBOR  option  with an average  interest  rate of 6.7%.
Subsequent  to year end through  January 31,  1999,  the debt was  decreased  by
$200,000  to  $4,700,000.  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.

     Working capital at 1998 year end remained  positive at $1,556,000  compared
to $722,000 at November 30, 1997. This was achieved despite capital expenditures
of $5,763,000 for additions to oil and gas properties as well as the purchase of
352,766 shares of treasury  stock for  $2,550,000  during the year and benefited
from a $528,000 increase in current portion of deferred income taxes.

                                       29
<PAGE>

     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:

                                 Shares
       Fiscal year     --------------------------      Average
       repurchased     As purchased     Restated*       price*
       -----------     ------------     ---------      -------
          1996             86,100        118,388        $4.85
          1997            158,000        197,863        $6.92
          1998            352,750        357,715        $7.07

       *Restated for stock split and stock dividends

     As of November 30, 1998 a total of 123,922 shares  remained to be purchased
from the most recent  authorization at a price not to exceed $8.25 per share. As
of January 31,  1999,  52,600 of those  shares have been  acquired at an average
price of $6.60 per share.

     During  1998,  capital  expenditures  actually  incurred  on  oil  and  gas
properties totaled $5,763,000 which amount differs from the capital  expenditure
shown in the Consolidated Statement of Cash Flows. The latter also includes cash
payments made during 1998 for 1997 expenditures  incurred but not yet paid as of
1997's year end.  Similarly,  there have been expenditures  accrued in 1998 that
will not be actually paid until 1999.  These were primarily for the  exploratory
program in the Texas Gulf Coast area.

     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 is  compliant  with the  year  2000.
Columbus has started 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 still be vulnerable to other  failures and
what the impact might be on its operations.

     The  Company's  interest  in  wells  operated  by  other  companies  is not
considered to be as important but management is attempting to determine if those
companies are ready for the year 2000. Outside services are used for payroll and
medical  benefits  processing  and those  companies  provided  updates  to their
software  that is year 2000  compliant  by  year-end  1998.  The Company is also
somewhat  dependent upon personal  computers as well as certain  spreadsheet and
word processing  software  programs which may not be year 2000 ready at present.
Evaluations  will be made to establish  which of those  systems are critical and
need to be remedied.

                                       30
<PAGE>

     The Company  also relies on  non-information  technology  systems,  such as
office telephones,  facsimile machines, air conditioning,  heating and elevators
in its leased office building,  which may have embedded technology such as micro
controllers and are generally outside of its control to assess or remedy.  These
might adversely impact the Company's business but in management's  opinion would
not create a material disruption.

     As  previously  disclosed,  the  major  system  computer  software  upgrade
performed in 1997 cost  $16,000.  Management  expects that this  represents  the
majority of the costs,  including  replacement of any non-compliant  information
technology  system,  required  to meet its goal of being  year  2000  ready  for
mission-critical  systems. The Company does not believe that any loss of revenue
will occur as a result of the year 2000  problem  but  regardless  of efforts to
identify and remedy such  problems,  there could be year 2000  related  failures
that cause some  disruption.  The Company has not established a contingency plan
should year 2000 failures occur and has not determined if it will in fact create
a contingency plan.

Results of Operations

     The  Company's  1998 gross  revenues of $12.1 million were 20% below 1997's
and, as noted  previously,  the decrease was caused  primarily by lower  prices.
Because of continued low crude oil prices,  over half of the Company's  operated
wells in the Williston Basin have been rendered  uneconomic and have either been
shut down or are being  operated only a few days each month.  Furthermore,  1997
gross revenues of $15.1 million were 28% above 1996's which was  attributable to
higher  prices and what was then a record level of natural gas  production  plus
improved crude oil production generated by the Company's 1997 drilling program.

     The  operating  loss  of  $1,706,000  in  1998  was a  direct  result  of a
significant increase in impairments, lower revenues, plus higher lease operating
expenses and exploration  costs versus 1997.  Operating  income of $3,766,000 in
1997  represented  an  improvement  of only  5% over  1996  but  without  higher
exploratory charges and impairment provisions, the increase would have been 59%.

     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 fiscal 1998  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 showed signs of recovery throughout the year but had retreated to the lows
by  year  end.  This  resulted  in a  significant  reduction  in  total  reserve
quantities which are based on the SEC calculation  method using constant prices.
The carrying value of remaining  unamortized costs in several successful efforts
pools still exceeded the resultant  undiscounted future net cash flows even when
determined  using  somewhat  higher  crude  prices  than  were  currently  being
realized.  Several property pools had been 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.
This was  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
it also further shortened the economic productive life of most oil wells. When a
$14 price was used over the life of the  reserves,  it  required  an  additional
non-cash impairment for the fourth quarter of $666,000 although some undeveloped
oil reserves would be restored.

     There was a $400,000  charge  included in the first  quarter  provision for
probable loss in value of  undeveloped  acreage and  abandonments  of leaseholds
located primarily in Louisiana which was in addition to the $200,000 reserved in
1997.  This  Louisiana  Austin Chalk  horizontal  well,  the Morrow  #23-H,  had
reserves  originally assigned to an extension of the current downdip lateral but
were eliminated by price and  performance  and contributed  heavily to the first
quarter provision.  Also, the necessary recompletion workover to place the updip
lateral on production was  theoretically  postponed.  Although economic at a $14
per barrel crude oil price,  this  recompletion  was deferred for two more years
for expected better prices which altered the present worth of those reserves and
also contributed to the fourth quarter provisions.
 
     Non-cash  impairment  losses of $243,000 for 1997 and $165,000 for 1996 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  chose to write  off as  impaired  certain  small  leaseholds  in the
acreage block where the  possibility of putting  together a drilling unit before
exploration  was rather  remote.  Also  included  were  leaseholds  where annual
rentals were already due or about to be due. These non-cash write downs amounted
to $251,000 bringing the total impairment  provision during the third quarter of
1997 to $494,000.


                                       32
<PAGE>

     As fiscal 1997 closed,  it became clearer that because of increasing  water
cuts the Morrow  #23-1H's  oil  production  rates would be less than the initial
potential  tests had indicated.  Accordingly,  1997's  year-end  proved reserves
attributable  to both  horizontal  legs were reduced  which  resulted in further
impairment  charges of $1,140,000  related to this Louisiana well and $84,000 to
leaseholds.  As previously  indicated,  a general  provision for all undeveloped
leaseholds was recorded in the amount of $200,000 where, based upon management's
opinion,  further  development  probably could not be completed in time prior to
lease  expirations.  Also, two oil wells in Oklahoma which had failed to respond
to attempts to eliminate shifting frac sand from halting production were charged
with additional  impairment of $260,000 of the total 1997 year end amount. Those
wells have not been abandoned permanently and may be returned to production when
better crude prices are available.

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

1997 vs. 1996
    Gas .............      23 %              25 %              53 %
    Oil .............       1 %               1 %               3 %

     Columbus'  1998 record sales volumes of natural gas averaged  9,703 Mcf per
day while oil and liquids production  declined to 606 barrels per day and equate
to  daily  production  of  2,223  barrels  of oil  equivalent  (BOE).  This  was
essentially flat with daily production of 2,229 BOE during 1997.

     With the 4% increase in natural gas  production  during 1998 and a decrease
of 11% in oil  production,  the Company now  produces  approximately  73% of its
volumes from natural gas.  This swing in  percentage  resulted from the emphasis
change initiated by management last year and has proved to be a correct shift as
the price of crude oil remained at low levels.



                                       33
<PAGE>

     Natural gas revenues for 1998 decreased 14% compared to 1997 primarily as a
result of lower prices which overcame  improved gas production from new wells in
the Texas Gulf Coast area. These new discoveries offset normal annual production
declines  plus the sale of a Berry R. Cox field  property in Texas during fourth
quarter 1997. Average prices for natural gas decreased 18% compared to 1997 with
a lack of increased  demand due to a warm winter and the highest  percentage  of
storage refill ever accomplished during 1998.

     Oil revenues for 1998 were down by a significant  40% compared with 1997 as
a result of a  substantial  33% decrease in the average price plus a lower sales
volume of 11%. The latter directly reflected a very sharp decline of a 90%-owned
Montana oil well which had been  recompleted  uphole during 1997's third quarter
and  contributed  its initial flush  production  for the last few months of last
year.  Furthermore,  during  1998's  third  quarter,  several  oil wells  became
marginal because of low prices and were shut down. Also, any well which had pump
or tubing  problems  was not repaired  nor were  workovers  performed as needed.
Unfortunately  no crude oil swap was in place  during  1998 to offer  protection
from this latest  price  debacle but was in place  during a portion of 1997 when
prices were high.

     Natural gas revenues in 1997  increased 53% over 1996's as a result of both
higher volumes and prices.  Average prices for natural gas increased 23% in 1997
versus 1996 due to strong  demand and a fairly  tight supply of gas in excess of
storage  injection  requirements.  Gas revenues for 1997 were reduced by $86,400
($.03 per Mcf) and 1996's  revenues were reduced by $518,000 ($.19 per Mcf) from
swaps of natural gas in those years.  Sales volumes improved by 25% over 1996 as
a result of numerous gas wells being  completed  and connected in Texas later in
the preceding year and early 1997.

     Oil  revenues for 1997  managed 3%  improvement  over 1996 as a result of a
sales  volume  and  average  price  increase  of 1% each.  Crude oil  production
reversed its normal  decline  over a several  year period  because new oil wells
were  completed  in  1997  which  generated  such  an  improvement.  New oil and
condensate  production  in Montana and  Chambers  County,  Texas during 1997 was
essentially offset by reductions in Harris County, Texas and North Dakota and by
properties  that were sold in late 1996. Oil revenues for 1997 were decreased by
$13,600 ($.06 per barrel)  while 1996  revenues were reduced by $256,000  ($1.04
per barrel) from crude oil swaps.

     Natural gas revenues for 1996  compared to 1995 in the U.S.  increased  64%
despite  reductions  from  swaps as a result  of a 26%  higher  price  and a 32%
increase in production.  Average prices improved because of increased demand and
severely depleted storage levels following an extended  1995/1996 winter heating
season.  Natural gas revenues  for 1996 were reduced by $518,000  ($.19 per Mcf)
from swaps of natural gas while 1995 had  increased  revenues of $284,000  ($.14
per  Mcf).  Production  volumes  for  1996  increased  as a result  of  property
acquisitions and the effects of newly developed wells.


                                       34
<PAGE>

     Oil  revenues  in the U.S.  for 1996 were up 28% from 1995 as a result of a
16% increase in the average price received and 9% higher  volumes.  Oil revenues
and average  prices for 1996 were reduced by $256,000  ($1.04 per barrel) due to
hedging activity and no oil hedges existed in 1995. Crude oil production in 1996
improved because of two new Jackson sand oil well completions in the Sralla Road
field plus a third well (78% WI) gas condensate discovery extended the field one
mile southwest and commenced  production in November.  These increases  overcame
normal production declines elsewhere.

     U.S. oil prices have fluctuated for several years with the same wide swings
experienced in world crude oil price. During the spring of 1996 crude oil prices
rose quickly to above $20 per barrel,  declined briefly, then again rose rapidly
to almost $23 per  barrel by year end.  During  1997  crude oil prices  steadily
softened and declined each quarter. This trend continued during most of 1998 and
ended the year at about $11.50 per barrel.

     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  expenses for 1997 were 6% lower than 1996
despite  more wells in  operation  because the prior year had several  expensive
workovers performed and production equipment replaced.  Lease operating expenses
for U.S.  wells only  increased  23% in 1996 over 1995  because  of  incremental
working interest acquisitions and several extensive work-overs performed.  Lease
operating  costs on a barrel  of oil  equivalent  basis  for 1998  rose to $2.63
compared  to $2.27 in 1997 but down from  $2.80 for 1996.  Operating  costs as a
percentage  of revenues  increased to 20% in 1998 due to lower prices and higher
costs. During 1997 they decreased to 13% due to increased production and product
prices while they were 19% in 1996 with lower prices and production.

     Production and property taxes approximated 10% of revenues in 1998 and 1996
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
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.





                                       35
<PAGE>

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  gross profit was $276,000  during 1998
compared to a $349,000  profit  during  1997.  This decline was due to unusually
high 1998 workover  expenses  required to clean out sand from the well bore of a
salt water disposal well in Texas.  Revenues  improved during 1998's second half
as the number of operated wells and drilling  activity  increased  along with an
increase from 50% to 100% ownership  interest in four  compressors  operating in
South Texas.

     Operating and  management  services  1997 profit of $349,000  compared to a
$210,000  profit for 1996  because  the number of  operated  wells and  drilling
activity increased in 1997.

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 decreased in 1998 to $141,000 when compared to $147,000 in 1997,
reflecting  a decreased  amount of  investments  and lower  short-term  interest
rates.  Interest income increased  slightly in 1997 to $147,000 compared to 1996
as a result of higher short-term interest rates realized and despite a decreased
amount of investments.

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 1998 were 7% higher
than last year due primarily to higher  medical  claims and increased  incentive
bonuses.  These bonuses are  discretionary and directly related to the Company's
performance  during  the prior year (not 1998) and  totaled  $273,000  ($153,000
non-cash) as of May, 1998 compared to $220,000 ($70,000  non-cash) in May, 1997.
Also,  some cost  increases in 1998  resulted  from salary  adjustments  granted
effective December 1, 1997 for non-officer  employees as well as May 1, 1998 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  because 1997 had included costs related to a  registration  statement
which was canceled.

                                       36
<PAGE>

     Reimbursement  for services provided by Columbus officers and employees for
managing  Resources  decreased  during 1998 and is scheduled to end on March 31,
1999.  Columbus  provided  Resources  with a 90-day notice of termination of the
Services  Contract  and  will  completely   withdraw  from  providing  personnel
services.  Resources  elected a new  President and Chief  Executive  Officer who
purchased a 4.5% equity  position  in  Resources  as of June 30, 1998 and he has
subsequently  added to Resources' staff.  Columbus'  general and  administrative
expense  will rise  commensurately  since  staff  reductions  are not  presently
contemplated although some contract services should be reduced. Reimbursement of
$218,000 for 1998 compares  with  $255,000  during 1997 and $296,000 in 1996 was
received for providing services to Resources.

     The Company's  general and  administrative  expenses in 1997 were similarly
higher  than  1996's due to salary  increases  in May 1997 for  officers  and in
December 1996 for employees along with incentive bonuses in May 1997. The latter
were discretionary and were actually based on the Company's performance in 1996.
Total  bonuses of $220,000  ($70,000  non-cash) in 1997 compared to $83,000 (all
non-cash) in 1996.  Another  major source of this increase in 1997 was legal and
accounting  expenses which had been accrued in connection with  preparation of a
registration  statement which was withdrawn because of the rapid paydown of debt
from accelerating cash flow.

     The  Company's  expenses  for 1996 were lower than for all of 1995  because
salary and staff  reductions  occurred in August 1995 which  affected  the whole
year.  Also,  incentive  bonuses  (all  non-cash)  totaled  only $83,000 in 1996
compared to $110,000 granted in May, 1995.

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.

     This  expense  item for 1998  increased  over 1997 as a result of increased
production and development expenditures which occurred in the intervening period
while there was a reduction in reserves in several cost pools  brought  about by
lower crude oil prices.  Total  charges  for  depletion  expense for oil and gas
properties  increased for 1997 over 1996 due to increased  production  and added
development  expenditures  during the  intervening  period.  Total  charges  for
depletion expense for oil and gas properties  increased in 1996 over 1995 due to
greater  production and despite the benefit realized from the 1995 write-down of
the carrying value of certain properties upon adoption of SFAS-121.

                                       37
<PAGE>

     Directly  related to reduced  crude oil  reserves in certain cost pools the
depletion and depreciation  rate for fiscal 1998 reached $4.64 per barrel of oil
equivalent ("BOE"). This compared to $3.91 per BOE for fiscal 1997 and $3.86 per
BOE in 1996.

     Effective October 1, 1997 the Company sold its 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 for purposes of calculating  depletion so those sale proceeds were credited
to the  costs  of the  successful  efforts  pool  and no book  gain or loss  was
recognized.  The reduction in proved reserves connected with the sale may result
in a small increase in that pool's depletion rate in future periods.

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. 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  who
capitalize such costs.

     Exploration  expense  for 1998 of $722,000  included  two  exploratory  dry
holes.  In the S.E.  Froid area in Montana  $209,000 was  expensed  while in the
Texas  Gulf  Coast  area the  second  dry hole  cost  $142,000.  At  present  no
exploratory  oil wells can be  justified  on any of the 3-D  seismic  structures
mapped on the Company's  Williston Basin leasehold blocks in Montana until crude
oil prices  significantly  improve.  Early in 1998 3-D seismic costs of $135,000
were  incurred in this area in  anticipation  there would be an  improvement  in
crude oil prices and because of leasehold expirations due to occur during 1999.

     Exploration  charges for 1997 were also up  significantly  to $540,000 from
$318,000 in 1996.  These included  $224,000 of 3-D seismic costs incurred in the
S.E. Froid area in Montana which located new exploratory well sites, and $73,000
incurred for drilling a non-commercial exploratory oil well.

     During 1996  $184,000 was  expensed  when two  Oklahoma  exploratory  wells
drilled  proved  non-economic.  Most of the balance of the 1996  expense was for
geological  consulting.  During  1995,  seismic  survey  costs of  $46,000  were
incurred  in Canada and  expensed  while  undeveloped  leasehold  costs in North
Dakota were impaired by $69,000 both of which contributed to a total exploration
expense of $245,000.
  

                                       38
<PAGE>

Litigation Expense

     The litigation  expense in 1998 relates to the Maris E. Penn, et al lawsuit
previously described for which charges have only just begun.

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 1998 than in 1997.  The average bank interest rate paid for debt in 1998,
1997 and 1996 was 7.1%, 7.1%, and 7.2%, respectively.

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 a  current  Federal  tax  payable  of less than 2% of
pre-tax  earnings.  In 1998, the Company has a net operating  loss  carryforward
from 1995 and operating loss  carryforwards  remaining from periods prior to the
first Section 382 ownership  change.  Utilization  of those latter  benefits are
limited to $904,000 per year so that the Company's current Federal tax provision
and  liability  may increase in 1999 and  thereafter  unless an active  drilling
program is maintained. In addition, the Company pays state income taxes.

     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.


                                       39
<PAGE>

     During 1997,  there was a net deferred tax liability of $989,000  which was
comprised of $201,000  current  portion and $788,000 long- term  liability.  The
valuation  allowance  had a net  reduction  of $26,000 from 1996 to November 30,
1997. A deduction  of $76,000 for the benefit of  disqualifying  disposition  of
incentive stock options was added to additional paid-in capital.

     During  1996,  the net  deferred  tax asset was reduced to $1,000 which was
comprised  of  $631,000  current  deferred  tax  asset  and  $630,000  long-term
liability.  The valuation allowance had a net reduction of $268,000 from 1995 to
November 30,  1996.  A deduction  of $102,000  for the benefit of  disqualifying
disposition of incentive stock options was added to additional paid-in capital.

New Accounting Pronouncements

     SFAS No. 130, "Reporting Comprehensive Income," was issued in June 1997 and
establishes  standards for reporting and display of comprehensive income and its
components   (revenues,   expenses,   gains,  and  losses)  in  a  full  set  of
general-purpose financial statements.  This statement is effective for financial
statements  for periods  beginning  after  December 15, 1997 and adoption of the
statement will not have a material impact on the Company's financial statements.

     In June 1998,  the FASB  issued SFAS No. 133,  "Accounting  for  Derivative
Instruments and Hedging Activities,"  effective for fiscal years beginning after
June 15, 1999.  The Company  must apply this  statement no later than its fiscal
year ending  November 30, 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 two years but have  recently  begun to drop as  drilling
programs have been cutback by most  companies.  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.

                                       40
<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 44.

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

    None.

                                    PART III


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

     A  definitive  proxy  statement  related  to the  1999  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 1999 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 1999  Annual  Meeting  of  Stockholders  and is
incorporated herein by reference.




                                       41
<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 44.
 
     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 1998:

          None

(c)  Exhibits:
 
Exhibit No.
*3(a)             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(b)            Amended By-Laws of Columbus Energy Corp. amended as of
                  October 18, 1994 (Exhibit to Form 8-K dated October 20,
                  1994) and as of February 13, 1995 (Exhibit to Form 8-K dated
                  February 16, 1995).

*10(a)            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(b)            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(c)            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).


                                       42
<PAGE>

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

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

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

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

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

 22               Subsidiaries of the Registrant.

 23(a)            Consent of PricewaterhouseCoopers LLP.

 23(b)            Consent of Reed W. Ferrill & Associates, Inc.

 23(c)            Consent of Huddleston & Co., Inc.

 27               Financial Data Schedule

_______________
*Incorporated by reference

















                                       43

<PAGE>
                                               COLUMBUS ENERGY CORP.

                                    INDEX TO CONSOLIDATED FINANCIAL STATEMENTS





                                                                       PAGE
                                                                       ----
Report of Independent Accountants                                       45

Financial Statements:
   Consolidated Balance Sheets at
   November 30, 1998 and 1997                                           46

   Consolidated Statements of Operations for the
   years ended November 30, 1998, 1997 and 1996                         48

   Consolidated Statements of Stockholders'
   Equity for the years ended
   November 30, 1998, 1997 and 1996                                     49

   Consolidated Statements of Cash Flows for the
   years ended November 30, 1998, 1997 and 1996                         51

Notes to the Consolidated Financial Statements                          52























                                       44
<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, 1998 and 1997, and
the  consolidated  results of their  operations and their cash flows for each of
the three years in the period  ended at November 30, 1998,  in  conformity  with
generally  accepted   accounting   principles.   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 generally accepted auditing standards 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 10, 1999
















                                       45
<PAGE>



                              COLUMBUS ENERGY CORP.

                           CONSOLIDATED BALANCE SHEETS

                                     ASSETS

                                               November 30,
                                          ---------------------
                                            1998         1997
                                          --------     --------
                                             (in thousands)

Current assets:
  Cash and cash equivalents ..........    $  2,003     $  1,857
  Accounts receivable:
    Joint interest partners ..........       1,570        1,932
    Oil and gas sales ................       1,239        2,054
    Allowance for doubtful accounts ..        (116)        (116)
  Deferred income taxes (Note 5) .....         327           --
  Inventory of oil field equipment,
    at lower of average cost or market          95          102
  Other ..............................         106           82
                                          --------     --------

   Total current assets ..............       5,224        5,911
                                          --------     --------

Property and equipment:
  Oil and gas assets, successful
    efforts method (Notes 3 and 4) ...      36,039       33,803
  Other property and equipment .......       1,804        2,053
                                          --------     --------

                                            37,843       35,856

  Less:  Accumulated depreciation,
    depletion, amortization and
    valuation allowance
    (Notes 2 and 3) ..................     (19,118)     (15,632)
                                          --------     --------

    Net property and equipment .......      18,725       20,224
                                          --------     --------

                                          $ 23,949     $ 26,135
                                          ========     ========

                                   (continued)








                                       46
<PAGE>



                              COLUMBUS ENERGY CORP.

                    CONSOLIDATED BALANCE SHEETS - (continued)

                      LIABILITIES AND STOCKHOLDERS' EQUITY

                                                 November 30,
                                            ---------------------
                                              1998         1997
                                            --------     --------
                                                (in thousands)

Current liabilities:
  Accounts payable                          $  1,846    $  3,023
  Undistributed oil and gas
    production receipts                          317         393
  Accrued production and property taxes          677         551
  Prepayments from joint interest owners         374         565
  Accrued expenses                               415         377
  Income taxes payable (Note 5)                    2          42
  Deferred income taxes (Note 5)                   -         201
  Other                                           37          37
                                             -------      ------

    Total current liabilities                  3,668       5,189
                                             -------      ------

Long-term bank debt (Note 4)                   4,900       2,200
Deferred income taxes (Note 5)                   117         788

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; 4,611,001 shares
    issued in 1998 and 4,492,068 in 1997
    (outstanding 4,046,552 in 1998 and
    3,883,557 in 1997) (Notes 1 and 7)           922         898
  Additional paid-in capital                  19,656      18,124
  Retained earnings (accumulated deficit)     (1,440)      2,887
                                             -------     -------
                                              19,138      21,909
Less:
    Treasury stock, at cost (Note 7)
      564,449 shares in 1998 and
      608,511 shares in 1997                  (3,874)     (3,951)
                                             -------     -------
        Total stockholders' equity            15,264      17,958
                                             -------     -------
                                             $23,949     $26,135



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


                                       47
<PAGE>



                              COLUMBUS ENERGY CORP.

                      CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>

                                                                                     Year Ended November 30,
                                                                               ---------------------------------
                                                                                 1998         1997         1996
                                                                               --------     --------     -------
                                                                             (in thousands, except per share data)
<S>                                                                            <C>          <C>          <C>    
Revenues:
  Oil and gas sales .......................................................    $ 10,617     $ 13,815     $10,572
  Operating and management
    services ..............................................................       1,336        1,176       1,087
  Gain (loss) on sale of assets ...........................................        --            (60)         31
  Interest income and other ...............................................         141          165         125
                                                                               --------     --------     -------
         Total revenues ...................................................      12,094       15,096      11,815
                                                                               --------     --------     -------

Costs and expenses:
  Lease operating expenses ................................................       2,140        1,849       1,965
  Property and production taxes ...........................................       1,080        1,258       1,051
  Operating and management
    services ..............................................................       1,060          827         877
  General and administrative ..............................................       1,466        1,372         999
  Depreciation, depletion and
   amortization ...........................................................       3,846        3,295       2,835
  Impairments .............................................................       3,482        2,179         165
  Exploration expense .....................................................         722          540         318
  Litigation expense ......................................................           4           10          16
                                                                               --------     --------     -------

     Total costs and expenses .............................................      13,800       11,330       8,226
                                                                               --------     --------     -------

     Operating income (loss) ..............................................      (1,706)       3,766       3,589
                                                                               --------     --------     -------

Other (income) expense:
  Interest ................................................................         260          174         260
  Other ...................................................................          26           (4)          2
                                                                               --------     --------     -------
                                                                                    286          170         262
                                                                               --------     --------     -------
         Earnings (loss) before
         income taxes .....................................................      (1,992)       3,596       3,327
  Provision (benefit) for income
     taxes (Note 5) .......................................................        (757)       1,429       1,229
                                                                               --------     --------     -------

            Net earnings (loss) ...........................................    $ (1,235)    $  2,167     $ 2,098
                                                                               ========     ========     =======

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

Weighted average number of common and common equivalent shares outstanding:
    Basic .................................................................       4,194        4,299       4,211
                                                                               ========     ========     =======
    Diluted ...............................................................       4,194        4,392       4,259
                                                                               ========     ========     =======
</TABLE>

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

                                       48
<PAGE>

                              COLUMBUS ENERGY CORP.
                 CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
                   For the Three Years Ended November 30, 1998
<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, 1995 ............  3,328,580    $666    $ 15,842     $(1,378)     260,431     $(1,944)

Exercise of employee
  stock options ...............    161,433      32         948          --       43,800        (370)
Tax benefit of
  disqualifying
  disposition of
  incentive stock
  options .....................         --      --         102          --           --          --
Purchase of shares ............         --      --          --          --       86,100        (579)
Shares issued for oil and
  gas properties ..............         --      --          31          --      (30,000)        223
Shares issued for Stock
  Purchase Plan ...............      9,902       2          51          --       (2,492)         18
Shares issued for
  Incentive Bonus Plan and
  directors' fees .............         --      --         (22)         --      (13,270)         96
Income tax benefit of
  loss carryforwards
  arising prior to
  quasi-reorganization ........         --      --         409          --           --          --
Net earnings ..................         --      --          --       2,098           --          --
                                 ---------    ----    --------     -------     --------     -------

Balances,
  November 30, 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

</TABLE>





                                       49
<PAGE>



                              COLUMBUS ENERGY CORP.
          CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY - (continued)
                   For the Three Years Ended November 30, 1998
<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>     
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          --           --            --
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)
                                =========    ====    ========     =======      ========     =========   
</TABLE>

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

                                       50
<PAGE>


                              COLUMBUS ENERGY CORP.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
                                                                               Year Ended November 30,
                                                                           -------------------------------
                                                                             1998        1997        1996
                                                                           --------    -------     -------
                                                                                   (in thousands)

<S>                                                                        <C>         <C>         <C>    
Net earnings (loss) ...................................................    $(1,235)    $ 2,167     $ 2,098
Adjustments to reconcile net earnings (loss) to
  net cash provided by operating activities:
    Depreciation, depletion, and
     amortization .....................................................      3,846       3,295       2,835
    Impairments and loss on asset dispositions ........................      3,482       2,179         165
    Deferred income tax provision (benefit) ...........................       (822)      1,328       1,148
    Other .............................................................        199         163          94

Changes in operating assets and liabilities:
    Accounts receivable ...............................................      1,177      (1,554)       (358)
    Other current assets ..............................................         (7)         21         (38)
    Accounts payable ..................................................       (298)        352         (22)
    Undistributed oil and gas production receipts .....................        (76)        339        (294)
    Accrued production and property taxes .............................        126          (4)        (80)
    Prepayments from joint interest owners ............................       (191)        307          69
    Income taxes payable (receivable) .................................         18           9          41
    Other current liabilities .........................................         39          36         (20)
                                                                           -------     -------     -------

    Net cash provided by operating activities .........................      6,258       8,638       5,638
                                                                           -------     -------     -------

Cash flows from investing activities:
    Proceeds from sale of assets ......................................         36       1,005         606
    Additions to oil and gas properties ...............................     (6,642)     (8,172)     (6,863)
    Additions to other assets .........................................       (111)       (127)        (63)
                                                                           -------     -------     -------
    Net cash used in investing activities .............................     (6,717)     (7,294)     (6,320)
                                                                           -------     -------     -------

Cash flows from financing activities:
    Proceeds from long-term debt ......................................      3,400       3,000       3,400
    Reduction in long-term debt .......................................       (700)     (3,000)     (2,800)
    Proceeds from exercise of stock options ...........................        455         498         643
    Purchase of treasury stock ........................................     (2,550)     (1,381)       (579)
                                                                           -------     -------     -------
    Net cash provided by (used in)
      financing activities ............................................        605        (883)        664
                                                                           -------     -------     -------

Net increase (decrease) in cash and cash equivalents ..................        146         461         (18)
Cash and cash equivalents at beginning of year ........................      1,857       1,396       1,414
                                                                           -------     -------     -------
Cash and cash equivalents at end of year ..............................    $ 2,003     $ 1,857     $ 1,396
                                                                           =======     =======     =======

Supplemental disclosure of cash flow information:
    Cash paid during the period for:
      Interest ........................................................    $   254     $   182     $   250
                                                                           =======     =======     =======
      Income taxes, net of refunds ....................................    $    47     $    91     $    41
                                                                           =======     =======     =======

Supplemental disclosure of non-cash investing and financing activities:
    Non-cash compensation expense
      related to common stock .........................................    $   190     $    98     $   114
                                                                           =======     =======     =======
    Oil and gas property additions for stock ..........................    $  --       $  --       $   253
                                                                           =======     =======     =======
    Use of loss carryforwards credited to
      additional paid-in-capital ......................................    $   220     $   262     $   409
                                                                           =======     =======     =======
</TABLE>


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

                                       51
<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 the use
of  management's  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 statement 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.














                                       52
<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, 1998 and 1997 the Company had  investments
in commercial  paper of  $1,100,000  and  $900,000,  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,  counter parties 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.



                                       53
<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,
1998 and 1997.

         Other Property and Equipment

         Other property and equipment consists of office and computer equipment.
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.

         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.






                                       54
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


         Earnings Per Share

         The  Company  adopted  Statement  of  Financial   Accounting  Standards
("SFAS")  No. 128,  "Earnings  per Share,"  effective  for the 1998 fiscal year.
Prior period earnings per share data presented has been restated to conform with
the  provisions  of SFAS No. 128. The purpose of SFAS No. 128 is to simplify the
computation of earnings per share. The new standard  replaces the calculation of
"primary  earnings  per share" with a  calculation  called  "basic  earnings per
share" and redefines "diluted earnings per share".

         Earnings  per share is computed  using the weighted  average  number of
common  shares   outstanding.   Stock  options  are  included  as  common  stock
equivalents,  when  dilutive,  using the  treasury  stock  method.  Common stock
equivalents  include  shares  issuable upon assumed  exercise of dilutive  stock
options using the average price for diluted shares. 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

         SFAS No. 130, "Reporting Comprehensive Income," was issued in June 1997
and establishes  standards for reporting and display of comprehensive income and
its  components  (revenues,  expenses,  gains,  and  losses)  in a  full  set of
general-purpose financial statements.  This statement is effective for financial
statements  for periods  beginning  after  December 15, 1997 and adoption of the
statement will not have a material impact on the Company's financial statements.









                                       55
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     In June 1997, the FASB issued SFAS No. 131,  "Disclosures about Segments of
an Enterprise  and Related  Information,"  effective for fiscal years  beginning
after December 15, 1997. The Company must apply this statement no later than its
fiscal year ending November 30, 1999. SFAS No. 131 requires  disclosing  segment
information using the "management  approach" and replaces the "industry segment"
approach using SFAS No. 14. The segment information  previously presented is not
expected to materially change when SFAS No. 131 is adopted.

     In June 1998,  the FASB  issued SFAS No. 133,  "Accounting  for  Derivative
Instruments and Hedging Activities,"  effective for fiscal years beginning after
June 15, 1999.  The Company  must apply this  statement no later than its fiscal
year ending  November 30, 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.

(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,
                                                     -------------------
                                                      1998         1997
                                                     -------     -------
         Proved properties                           $35,290     $33,074
         Unproved properties                             749         729
                                                     -------     -------

                                                      36,039      33,803

         Less accumulated depreciation,
           depletion, amortization and
           valuation allowance                       (17,919)    (14,175)
                                                     -------     -------

         Total net properties                        $18,120     $19,628
                                                     =======     =======







                                       56
<PAGE>



                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


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

                           Year Ended November 30,
                        ---------------------------
                         1998       1997      1996
                        ------    -------    ------
Property acquisition
  costs:
         Proved         $   74    $    --    $3,025
     Unproved              764        508       976
Exploration costs          722        540       318
Development costs        4,925      9,043     3,115
                        ------    -------    ------

Total costs incurred    $6,485    $10,091    $7,434
                        ======    =======    ======


                 Results of Operations for Producing Activities
                                 (in thousands)

                              Year Ended November 30,
                         -------------------------------
                            1998        1997       1996
                         --------     -------    -------

Sales                    $ 10,617     $13,815    $10,572
Production (lifting)
  costs (a)                 3,220       3,107      3,016
Exploration expenses          722         540        318
Impairment of long-
  lived assets              3,482       2,179        165
Depreciation
  depletion and
  amortization (b)          3,743       3,194      2,703
                         --------     -------    -------
                             (550)      4,795      4,370

Imputed income tax
  provision (benefit)        (209)      1,905      1,614
                         --------     -------    -------
Results of operations
  from producing
  activities
  (excluding overhead
  and interest
  incurred)              $   (341)    $ 2,890    $ 2,756
                         ========     =======    =======

(a) Production costs include lease operating expenses, production
    and property taxes
(b) Amortization expense per equivalent barrel of production:
    1998 - $4.64   1997 - $3.91   1996 - $3.86



                                       57
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


         For the years ended  November 30, 1998,  1997 and 1996, 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.

                     1998                 1997                1996
              ------------------   ------------------  -------------------
              Amount   % Revenue   Amount   % Revenue   Amount   % Revenue
              ------   ---------   ------   ---------  -------   ---------
Customer A    $1,652     15.6%     $2,956      21.4%   $ 3,142      29.7%
Customer B     5,204     49.0       6,536      47.3      5,513      52.2
Customer C         -        -       1,395      10.1      1,212      11.5
Customer D     1,321     12.4           -         -          -         -

         In the Company's judgment, termination by any purchaser under 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.























                                       58
<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 September 8,
1998 the Credit  Agreement was amended to extend the revolving period to July 1,
2000 when it entirely  converts to an amortizing term loan which matures July 1,
2003. 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, 1998  outstanding  borrowings on the revolving  line of
credit were  $4,900,000 and the unused  borrowing base available was $5,100,000.
The $4,900,000 bears interest at LIBOR rate of 5.15% 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 are as follows (in thousands):

Year ending November 30,:


                                    1999             $     -
                                    2000                 544
                                    2001               1,633
                                    2002               1,634
                                    2003               1,089
                                                     -------

                                             Total   $ 4,900
                                                     =======







                                       59
<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):

                                   1998       1997      1996
                                -------     ------    ------

Current:
   Federal                      $  --       $   13    $    2
   State                             65         88        79
                                -------     ------    ------
                                     65        101        81
                                -------     ------    ------

Deferred:
   Federal                         (789)       942       288
   Use of loss carryforwards       --          347       848
   State                            (33)        39        12
                                -------     ------    ------
                                   (822)     1,328     1,148
                                -------     ------    ------

Total income tax
   provision (benefit)          $  (757)    $1,429    $1,229
                                =======     ======    ======

         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
                                   ---------------------------
                                    1998       1997       1996
                                   ------     ------     -----
U.S. Statutory rate                 (34)%      34 %       34 %
State income taxes                    2         2          6
Change in valuation
  allowance                          (4)        2          4
Percentage depletion                 --         -         (7)
Other                                (2)        2         --
                                    ---         -         --

Effective rate                      (38)%      40 %       37 %
                                    ===        ==         ==

         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.



                                       60
<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 1998,  certain tax assets (shown in the table below) were
utilized and the valuation  allowance was decreased  during the year by $35,000.
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,
                                                           1997     Equity       Other       1998
                                                          ------- -----------   -----------  --------
<S>                                                       <C>         <C>        <C>       <C>    
Deferred tax assets:
  Pre-1987 loss carryforwards                             $ 1,053     $--         $  71       $ 1,124
  Post-1987 loss carryforwards                                540      --            --           540
  Percentage depletion
    carryforwards                                           1,304      --           174         1,478
  State income tax loss
    carryforwards                                             105      --            13           118
  Other                                                       327      --             2           329
                                                          -------     ----        -----       -------
                  Total                                     3,329      --           260         3,589
    Valuation allowance (long-term)                        (1,443)     221(a)      (186)       (1,408)
                                                          -------     ----        -----       -------
         Deferred tax assets                                1,886      221           74         2,181
                                                          -------     ----        -----       -------

  Tax benefit of stock option
    exercises                                                --        156(a)      (156)           --
                                                          -------     ----        -----       -------

Deferred tax liabilities-
  Depreciation, depletion and
    amortization and other                                 (2,875)     --           904        (1,971)
                                                          -------     ----        -----       -------

    Net tax asset (liability)                             $  (989)    $377        $ 822       $   210
                                                          =======     ====        =====       =======
_____________
(a)  Credited to additional paid-in capital.
</TABLE>




                                       61
<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, 1998 as follows:

                                                  Net
                     Expiration Year        Operating Loss
                     ---------------        --------------
                           1999                $ 2,014
                           2000                    906
                           2001                    387
                           2010                  1,589
                                               -------
                                               $ 4,896
                                               =======

         For Alternative Minimum Tax purposes the Company had net operating loss
carryforwards of  approximately  $6,268,000 as of November 30, 1998. The Company
also has percentage  depletion  carryforwards of $3,890,000 which do not expire.
State income tax operating loss  carryforwards of  approximately  $1,950,000 are
available at November 30, 1998.

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

                                         1998        1997        1996
                                       -------     -------     -------

Earnings (loss) before income taxes
  per financial statements             $(1,992)    $ 3,596     $ 3,327

Differences between income
  before taxes for financial
  statement purposes and
  taxable income:
  Intangible drilling costs
    deductible for taxes                (2,771)     (6,158)     (1,520)
  Excess of book over tax
    depletion, depreciation
    and amortization                     1,816       1,683         754
  Tax benefit of stock option
    exercises                             (229)       (200)       (273)
  Impairment expense                     3,426       1,843         165
  Lease abandonments                       (74)        (13)       (117)
  Other                                    (23)        153         (95)
                                       -------     -------     -------
Federal taxable income                 $   153     $   904     $ 2,241
                                       =======     =======     =======



                                       62
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


         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, 1998 as well as  contemplated  drilling
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  $1,408,000  as of November  30,  1998,  $516,000
relates to  pre-quasi-  reorganization  tax assets and the  balance of  $892,000
relates to post-quasi-reorganization tax assets. In future periods, reduction of
the pre-quasi-reorganization portion of the valuation allowance will be credited
to additional  paid-in  capital and  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 $9,500,000 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  $3,589,000.  This level of income can be achieved  using the value of proved
reserves reported in the year end November 30, 1998 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 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.  During  1996  the  valuation  allowance  was
decreased  by  $409,000  related  to  pre-quasi-reorganization  tax  assets  and
increased by $141,000 for post-quasi-reorganization tax 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 $218,000 for fiscal 1998,
$255,000 for fiscal 1997 and $296,000 for fiscal 1996.

(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 10% stock dividends in fiscal
1998, 1995 and 1994.


                                       63
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     Columbus has several  stock option plans with  outstanding  options for the
benefit of all  employees.  Under the 1985 Plan,  options for 63,731 shares were
exercisable at November 30, 1998. No additional options may be granted under the
1985 Plan. At November 30, 1997, 82,878 shares were exercisable.

     Under the 1995 Plan, as of November 30, 1998,  6,937 option shares remained
available for granting, and options for 314,182 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, 1997,  45,711
shares  were  available  for  granting,  and  options  for  330,539  shares were
exercisable.

     The Board of Directors  has granted  non-qualified  stock  options of which
there were  231,803  exercisable  at November  30, 1998 and 128,728  shares were
exercisable  at November 30, 1997.  The Board of Directors has reserved  350,000
shares of treasury stock to be used for issuing common stock when  non-qualified
stock options are exercised.

     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 stock options  granted with an exercise price equal to 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:

                                  1998        1997        1996
                                --------     ------      ------
                              (thousands except per share amounts)
     Net income (loss)
          As reported           $(1,235)     $2,167      $2,098
          Pro forma              (1,392)     $1,968      $1,897

     Earnings (loss) per
       share (primary)
          As reported           $  (.29)     $  .50      $  .50
          Pro forma             $  (.33)     $  .46      $  .45



                                       64
<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, 1998:

                                 1998               1997               1996
                           -----------------  ----------------- ----------------
                                   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          557    $6.45       490    $5.65      388    $5.25
Granted                      182     6.76       191     7.38      338     5.27
Exercised                   (115)    5.34      (121)    4.70     (222)    4.42
Expired                       (5)    7.79        (3)    6.64      (14)    4.89
                            ----               ----              ----

Shares under option at
  end of year                619     6.73       557     6.45      490     5.65
                            ====               ====              ====
Options exercisable
  at November 30             610    $6.73       542    $6.42      476    $5.65
Shares available for
  future grant at end
  of year                    170                 46               194
Weighted-average fair value
  of options granted during
  the year                          $1.40              $2.04             $1.20

     The  following  table  summarizes  information  about the  Company's  stock
options outstanding at November 30, 1998:

                        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       124         1.0         $ 5.48         124         $ 5.48
$6.03 - $6.44       136         3.0           6.30         133           6.29
$7.00 - $7.84       359         2.5           7.33         353           7.33
                    ---         ---         ------         ---         ------

$4.68 - $7.84       619         2.3           6.73         610           6.73
                    ===         ===         ======         ===         ======

     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:

                                 1998         1997         1996
                                 ----         ----         ----

Expected option life - years     2.32         2.36         1.81
Risk-free interest rate          5.02%        6.08%        5.64%
Dividend yield                   0   %        0   %        0   %
Volatility                      25.87%       30.60%       23.14%


                                       65
<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  and the
Company will contribute an amount of shares  equivalent to 25% of those payments
which  will be issued out of the  Company's  treasury  stock as  vesting  occurs
semi-annually.  For the fiscal years 1998 and 1997 total matching  contributions
of $17,000 and $15,000, respectively, were accrued as an expense by the Company.
The price of the issued shares equals the average  trading price during each six
month purchase period or the ending price, whichever is less. During fiscal 1998
a total of 11,298 shares were purchased (2,275 shares from treasury stock as the
Company's  contribution  of 25%) at an average  cost of $7.73 per share.  During
fiscal 1997 a total of 8,758 shares were  purchased  (1,762 shares from treasury
stock  for the  Company  contribution  of 25%) at an  average  cost of $8.58 per
share.

      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*
       -----------     ------------     ---------    -------
          1996             86,100        118,388      $4.85
          1997            158,000        197,863      $6.92
          1998            352,750        357,715      $7.07

       *Restated for stock split and stock dividends













                                       66
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


          As of November 30, 1998 a total of 123,922 shares  remained out of the
most recent  authorizations  which may be  repurchased  at a price not to exceed
$8.25 per share.  As of  January  31,  1999,  52,600 of those  shares  have been
acquired at an average price of $6.60 per share.

(8)       EARNINGS PER SHARE

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

                                              Fiscal Year Ended November 30,
                                           ------------------------------------
                                               1998        1997        1996
                                           ----------  ----------  ------------
                                           (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)                  $(1,235)     $2,167     $2,098
                                              ======       =====      =====

Shares (denominator):
  Basic EPS                                    4,194       4,299      4,211
  Effect of dilutive option
    shares                                         -          93         48
                                               -----       -----      -----
  Diluted EPS                                  4,194       4,392      4,259
                                               =====       =====      =====

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

Number of shares not  included  
  in basic EPS that  would have 
  been  antidilutive because
  exercise price of options was 
  greater than the average market 
  price of the common shares                      138         73        152
                                                =====      =====      =====

          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.





                                       67
<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 office space for its present
building.  The total  rent  expense  for 1998,  1997 and 1996 was  approximately
$171,000, $161,000 and $133,000,  respectively.  Columbus has extended the lease
for an additional one year through  September 1999 at a base rate of $17,655 per
month.  Future rental payments required under this lease as of November 30, 1998
are $177,000 for fiscal year 1999.

       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, 1998
the accrued  liability  totals  $220,000  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  $18,000,
$23,000 and $16,000 in 1998, 1997 and 1996, respectively.












                                       68
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


      In prior years  Columbus  has hedged both natural gas and crude oil prices
by entering into "swaps". There was no hedging activity in fiscal 1998. The swap
was 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. The following table shows the results of these swaps:

                                                        Increase (decrease) in
                                                         oil and gas revenues
                     Volume                             ----------------------
Description          per mo.             Period           1997          1996
-----------          -------             ------           ----          ----
                 (Mmbtu or bbl)
Natural Gas

$2.20/Mmbtu            60,000          3/97-10/97       $(86,400)
Futures Contracts      60,000         10/96-11/96                    $  42,000
$1.74 & $1.88/Mmbtu   120,000          4/96-11/96                    $(560,000)

Crude Oil

$21.17/bbl             10,000         11/96-10/97       $  8,900     $ (23,800)
$17.25/bbl with
  $19.50/bbl cap      10,000           1/96-12/96       $(22,500)    $(232,300)

      The Company's  natural gas and crude oil swaps were  considered  financial
instruments  with  off-balance  sheet risk which were 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 no natural gas or crude oil swaps outstanding as
of November 30, 1998.

      The Company is not aware of any events of  noncompliance in its operations
with  any  environmental  laws and  regulations  nor of any  material  potential
contingencies related to environmental issues. The exact nature of environmental
control  problems,  if any, which the Company may encounter in the future cannot
be  predicted,  primarily  because of the changing  character  of  environmental
requirements that may be enacted with applicable jurisdictions.

         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 District  Court of
Harris County, Texas. The plaintiffs claim that Columbus breached the settlement
agreement  reached in  September  1994 of their  previous  lawsuit by failing to
develop  properties  located within the area of mutual interests and to act as a
reasonably  prudent  operator in the  development  of the  property.  Plaintiffs
allege  damages  under the  contract  but no amount is  specified.  Columbus has
responded with a First Set of Interrogatories to plaintiffs. Columbus has denied
the plaintiffs' allegations.


                                       69
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(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  $106,000,
$95,000, and $90,000 in the fiscal years 1998, 1997 and 1996, respectively.




































                                       70
<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:

                                             1998         1997          1996
                                             ----         ----          ----
                                                         (in thousands)

Operating revenues from 
  unaffiliated services:
     Oil and gas                           $10,631       $13,788      $10,617
     Services                                1,464         1,308        1,198
                                           -------       -------      -------

          Total                            $12,095       $15,096      $11,815
                                           =======       =======      =======

Depreciation, depletion 
  and amortization (a):
     Oil and gas                           $ 3,784       $ 3,238      $ 2,763
     Services                                   62            57           72
                                           -------       -------      -------

          Total                            $ 3,846       $ 3,295      $ 2,835
                                           =======       =======      =======

Operating income (loss):
     Oil and gas                           $  (582)(b)   $ 4,714(b)   $ 4,339(b)
     Services                                  342           424          249
     General corporate expenses             (1,466)       (1,372)        (999)
                                           -------       -------      -------

          Total operating income            (1,706)        3,766        3,589
Interest expense and other                    (287)         (170)        (262)
                                           -------       -------     --------

          Earnings before income taxes     $(1,992)      $ 3,596      $ 3,327
                                           =======       =======      =======

Identifiable assets (a):
     Oil and gas                           $19,587       $21,917      $18,910
     Services                                4,362         4,218        2,715
                                           -------       -------      -------

          Total                            $23,949       $26,135      $21,625
                                           =======       =======      =======

Additions to property and equipment:
     Oil and gas                           $ 5,872       $ 9,671      $ 7,167
     Services                                   45             7           12
                                           -------       -------      -------

          Total                            $ 5,917       $ 9,678      $ 7,179
                                           =======       =======      =======

(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 $3,482,000 in 1998,  $2,179,000 in 1997
and $165,000 in 1996.











                                       71
<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 12, 1999          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                    2/12/99
---------------------------                                           -------
Harry A. Trueblood, Jr.

                            Chief Operating Officer

                                 Executive Vice President
/s/ Clarence H. Brown            and Chief Operating Officer          2/12/99
---------------------------                                           -------
Clarence H. Brown

                   Principal Accounting and Financial Officer


/s/ Ronald H. Beck               Vice President                       2/12/99
---------------------------                                           -------
Ronald H. Beck

                         Majority of Board of Directors


/s/ Harry A. Trueblood, Jr.       Director                            2/12/99
---------------------------                                           -------
Harry A. Trueblood, Jr.


/s/ Clarence H. Brown             Director                            2/12/99
---------------------------                                           -------
Clarence H. Brown


/s/ J. Samuel Butler              Director                            2/12/99
---------------------------                                           -------
J. Samuel Butler


/s/ William H. Blount, Jr.        Director                            2/12/99
---------------------------                                           -------
William H. Blount, Jr.







                                       72
<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, 1998















                              COLUMBUS ENERGY CORP.
                           (Exact Name of Registrant)

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