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, 1996                                     1-9872


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

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

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

               Registrant's telephone number, including area code:
                                 (303) 861-5252
                        Securities registered pursuant to
                            Section 12(b) of the Act:

                                                        Name of each Exchange on
     Title of each class                                     which registered
Common Stock, ($.20 par value)                           American Stock Exchange
                                                         Pacific 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, 1997 is $23,497,000.

     Indicate  the  number of  shares  outstanding  of each of the  registrant's
classes of common stock, as of January 31, 1997

                                                 Outstanding at
          Class                                 January 31, 1997
Common Stock, ($.20 par value)                  3,180,035 shares

                       DOCUMENTS INCORPORATED BY REFERENCE

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


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

                                      INDEX

                       Securities and Exchange Commission
                           Item Number and Description

                                     PART I

                                                                           Page

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

                                     PART II

Item 5.  Market for the Registrant's Common Equity
                and Related Stockholder Matters.........................   24
Item 6.  Selected Financial Data........................................   25
Item 7.  Management's Discussion and Analysis of Financial
                Condition and Results of Operations.....................   26
Item 8.  Financial Statements and Supplementary Data....................   38
Item 9.  Changes in and Disagreements with Accountants
                on Accounting and Financial Disclosure..................   38

                                    PART III

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

                             PART IV AND SIGNATURES

Item 14. Exhibits, Financial Statement
                Schedules and Reports on Form 8-K.......................   40

         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.  Prior to February 1995 CEC
Resources  Ltd.  (Resources"),  an  Alberta,  Canada  corporation,  was  another
wholly-owned subsidiary. The term "Company" as used herein includes Columbus and
its subsidiaries.

     The  Company  currently  has 33  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  at  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
were subscribed (and  oversubscribed)  yielding an aggregate of $4,875,000.  The
total value  assigned to the rights on its books was  $582,000  for the dividend
portion of the  purchase of  Resources  shares.  A deduction of $126,000 for the
costs of the offering was recorded.  No gain or loss can be recognized  for book
purposes  in a spin-off.  No taxes were due  Revenue  Canada as a result of this
divestiture of common stock because the tax basis exceeds the proceeds  received
upon disposition.

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

                                       3
<PAGE>

Item 2.  PROPERTIES

                             Oil and Gas Properties

Reserves

     The estimated  reserve  amounts and future net revenues were  determined by
outside consulting petroleum engineers.  The reserve tables presented below show
total proved  reserves and changes in proved  reserves owned by Columbus for the
three  years  ended  November  30,  1996,   1995  and  1994  and  including  its
wholly-owned Canadian subsidiary, Resources, for 1994.

                           PROVED OIL AND GAS RESERVES
<TABLE>
<CAPTION>
                                                 Oil                          Natural Gas
                                        (Thousands of Barrels)          (Millions of Cubic Feet)
                                        ----------------------          ------------------------
                                                United                           United
                                      Total     States     Canada      Total     States     Canada
                                     -------    -------    -------    -------    -------    -------
<S>                                  <C>        <C>        <C>        <C>        <C>        <C>
Proved reserves:
December 1, 1993 .................     2,413      2,187        226     34,383     17,456     16,927
 Revision to previous estimates ..       162        159          3     (6,341)    (5,005)    (1,336)
 Purchase of reserves ............        78         78       --        7,946      7,946       --
 Extensions, discoveries and other
  additions ......................       281         24        257     10,019        732      9,287
 Production ......................      (263)      (223)       (40)    (4,207)    (2,810)    (1,397)
                                     -------    -------    -------    -------    -------    -------

November 30, 1994 ................     2,671      2,225        446     41,800     18,319     23,481
 Revision to previous estimates ..       (61)      (113)        52     (2,698)    (2,330)      (368)
 Purchase of reserves ............       117        117       --          397        397       --
 Extensions, discoveries and other
  additions ......................        31         31       --          505        505       --
 Production ......................      (236)      (225)       (11)    (2,479)    (2,033)      (446)
 Sale of reserves (divestiture) ..      (487)      --         (487)   (22,667)      --      (22,667)
                                     -------    -------    -------    -------    -------    -------

November 30, 1995 ................     2,035      2,035       --       14,858     14,858       --
 Revision to previous estimates ..      (278)      (278)      --       (1,335)    (1,335)      --
 Purchase of reserves ............        17         17       --        4,808      4,808       --
 Sale of reserves ................       (35)       (35)      --         (170)      (170)      --
 Extensions, discoveries and other
  additions ......................       150        150       --        3,190      3,190       --
 Production ......................      (246)      (246)      --       (2,686)    (2,686)      --
                                     -------    -------    -------    -------    -------    -------

November 30, 1996 ................     1,643      1,643       --       18,665     18,665       --
                                     =======    =======    =======    =======    =======    =======

Proved developed reserves
 (producing and non-producing):
November 30, 1994 ................     1,887      1,619        268     27,768     13,205     14,563
                                     =======    =======    =======    =======    =======    =======
November 30, 1995 ................     1,384      1,384       --       11,282     11,282       --
                                     =======    =======    =======    =======    =======    =======
November 30, 1996 ................     1,211      1,211       --       15,758     15,758       --
                                     =======    =======    =======    =======    =======    =======
</TABLE>
                                       4
<PAGE>

Proved Developed Producing Reserves

     As of November 30, 1996,  Columbus has  approximately  1,139,000 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 almost 100% of the reserves in the
proved  developed  producing  category  with 207,000  barrels of the Sralla Road
(Vicksburg) field,  Harris County,  Texas,  receiving some pressure  maintenance
assistance from produced water being injected into the aquifer.

     The U.S. gas producing  properties  owned by Columbus are located in Texas,
North Dakota, Oklahoma and Montana and contain 11.2 billion cubic feet of proved
developed producing gas 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.

Proved Developed Non-Producing Reserves

     The reserves in this  category are located in the states of Texas,  Montana
and North Dakota.  Generally,  these are reserves  behind the casing in existing
wells and recompletion of those wells will be required prior to the commencement
of production.

     Columbus' (U.S.) non-producing  reserves are 71,600 barrels of oil, or 4.4%
of its total proved oil reserves,  and 4.6 billion cubic feet of natural gas, or
25% of its total proved natural gas reserves.

Proved Undeveloped Reserves

     Columbus' (U.S.) proved  undeveloped  reserves were  approximately  432,000
barrels  and 2.9  billion  cubic  feet of  natural  gas.  Almost  all of the oil
reserves in this category are in Montana, North Dakota and Texas, and all of the
proved  undeveloped  gas  reserves  are  attributable  to  undrilled   locations
offsetting production in Webb, Zapata and Jim Hogg Counties,  Texas, Montana and
North Dakota.

     These reserves are expected to be developed  during 1997 or in future years
assuming oil and gas prices stabilize at prices which yield a satisfactory  rate
of return on investment when developed.

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 Financial
Accounting  Standards  Board  Statement 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.

                                       5
<PAGE>

            STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
                RELATING TO ESTIMATED PROVED OIL AND GAS RESERVES
                             (thousands of dollars)
<TABLE>
<CAPTION>
                                                             United
                                                 Total       States      Canada
                                                --------    --------    --------
<S>                                             <C>         <C>         <C>   
NOVEMBER 30, 1996
Future oil and gas revenues .................   $ 98,555    $ 98,555    $   --
Future cost:
  Production cost ...........................    (25,620)    (25,620)       --
  Development cost ..........................     (4,264)     (4,264)       --
Future income taxes .........................    (14,198)    (14,198)       --
                                                --------    --------    --------
Future net cash flows .......................     54,473      54,473        --
Discount at 10% .............................    (16,313)    (16,313)       --
                                                --------    --------    --------
Standardized measure of discounted future net
  cash flows ................................   $ 38,160    $ 38,160    $   --
                                                ========    ========    ========

NOVEMBER 30, 1995
Future oil and gas revenues .................   $ 58,083    $ 58,083    $   --
Future cost:
  Production cost ...........................    (18,214)    (18,214)       --
  Development cost ..........................     (4,743)     (4,743)       --
Future income taxes .........................     (5,466)     (5,466)       --
                                                --------    --------    --------
Future net cash flows .......................     29,660      29,660        --
Discount at 10% .............................     (8,268)     (8,268)       --
                                                --------    --------    --------
Standardized measure of discounted future net
  cash flows ................................   $ 21,392    $ 21,392    $   --
                                                ========    ========    ========

NOVEMBER 30, 1994
Future oil and gas revenues .................   $ 96,408    $ 63,137    $ 33,271
Future cost:
  Production cost ...........................    (29,506)    (19,476)    (10,030)
  Development cost ..........................     (7,673)     (6,233)     (1,440)
Future income taxes .........................    (11,856)     (6,384)     (5,472)
                                                --------    --------    --------
Future net cash flows .......................     47,373      31,044      16,329
Discount at 10% .............................    (14,598)     (9,272)     (5,326)
                                                --------    --------    --------
Standardized measure of discounted future
  net cash flows ............................   $ 32,775    $ 21,772    $ 11,003
                                                ========    ========    ========
</TABLE>
                                       6
<PAGE>

          CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
                FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES
                   FOR THE THREE YEARS ENDED NOVEMBER 30, 1996
                             (thousands of dollars)
<TABLE>
<CAPTION>
                                                           United
                                               Total       States      Canada
                                              --------    --------    --------
<S>               <C>                         <C>         <C>         <C>     
Balance, December 1, 1993 .................   $ 36,256    $ 27,278    $  8,978
                                              --------    --------    --------

Sale of oil and gas net of production costs     (8,138)     (6,513)     (1,625)
Net changes in prices and production costs      (4,424)     (3,389)     (1,035)
Purchase of reserves ......................      6,275       6,275        --
Extensions, discoveries and other additions      6,576         692       5,884
Revisions to previous estimates ...........     (4,895)     (4,178)       (717)
Previously estimated development costs
  incurred during the period ..............      1,891       1,200         691
Changes in development costs ..............     (2,577)     (1,658)       (919)
Accretion of discount .....................      4,299       3,141       1,158
Other .....................................     (2,775)     (1,976)       (799)
Change in future income taxes .............        287         900        (613)
                                              --------    --------    --------

Net increase (decrease) ...................     (3,481)     (5,506)      2,025
                                              --------    --------    --------

Balance, November 30, 1994 ................     32,775      21,772      11,003

Sale of oil and gas net of production costs     (5,311)     (4,926)       (385)
Net changes in prices and production costs      (3,574)      1,294      (4,868)
Purchase of reserves ......................      1,693       1,693        --
Sale of reserves ..........................     (8,498)       --        (8,498)
Extensions, discoveries and other additions        616         616        --
Revisions to previous estimates ...........     (2,648)     (2,642)         (6)
Previously estimated development costs
  incurred during the period ..............        716         716        --
Changes in development costs ..............        111         656        (545)
Accretion of discount .....................      2,501       2,501        --
Other .....................................       (664)       (751)         87
Change in future income taxes .............      3,675         463       3,212
                                              --------    --------    --------

Net increase (decrease) ...................    (11,383)       (380)    (11,003)
                                              --------    --------    --------

Balance, November 30, 1995 ................     21,392      21,392        --
</TABLE>
                                   (continued)

                                       7
<PAGE>

          CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
                FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES
            FOR THE THREE YEARS ENDED NOVEMBER 30, 1996 - (continued)
                             (thousands of dollars)
<TABLE>
<CAPTION>
                                                           United
                                               Total       States      Canada
                                              --------    --------    --------
<S>                                           <C>         <C>         <C>    
Sale of oil and gas net of production costs   $ (7,556)   $ (7,556)   $    --
Net changes in prices and production costs      19,446      19,446         --
Purchase of reserves ......................      5,158       5,158         --
Sale of reserves ..........................       (229)       (229)        --
Extensions, discoveries and other additions      8,309       8,309         --
Revisions to previous estimates ...........     (4,905)     (4,905)        --
Previously estimated development costs
  incurred during the period ..............        729         729         --
Changes in development costs ..............        570         570         --
Accretion of discount .....................      2,416       2,416         --
Other .....................................     (1,571)     (1,571)        --
Change in future income taxes .............     (5,599)     (5,599)        --
                                              --------    --------    ---------

Net increase ..............................     16,768      16,768         --
                                              --------    --------    ---------

Balance November 30, 1996 .................   $ 38,160    $ 38,160    $    --
                                              ========    ========    =========
</TABLE>

     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, 1996,  1995 and
1994.  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 U.S. reserves were
$46,530,000 in 1996,  $24,163,000 in 1995, and  $25,006,000 in 1994.  Discounted
future net cash flows before  income  taxes for  Canadian  reserves in 1994 were
$14,215,000.  As required by SFAS-69,  the tax computation 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  shown do not represent the expected lower future tax expense to
the Company as long as it remains an active operating company.

                                       8
<PAGE>

     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,  1996 the U.S.  oil  price
(including  natural gas  liquids)  was $22.81 per barrel and gas price was $3.54
per thousand cubic feet. The SEC requires that this computation utilize year end
product 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  use of prices that  prevail on a single  date can have an  inordinate
influence  on its  year-end  reserves as well as on the  resulting  year to year
change that a company reports for estimated  discounted future net cash flows by
the  standardized  measure  calculation.  Management  has long  advocated  using
weighted  average of annual prices actually  received to make this  standardized
measure  calculation  less  susceptible  to the impact of wide  fluctuations  in
prices which have occurred so frequently in recent years.  The use of a weighted
average annual price may or may not be indicative of future cash flows depending
on whether future average prices increase or decrease.  This 1996 fiscal year is
a good example of why the average price would be  preferable  since the year end
prices for natural gas were higher than the average received during the year.

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  (SEC  Case I) as of
November 30, 1996,  1995 and 1994. 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. The reports are required in connection with the
Company's bank line of credit.

                                       9
<PAGE>

Production

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

                       Fiscal Year
                ------------------------
                1996      1995      1994
                ----      ----      ----
USA
Oil-barrels   246,000   225,000   223,000
Gas-Mmcf ..     2,686     2,033     2,810

CANADA
Oil-barrels      --      11,000    40,000
Gas-Mmcf ..      --         446     1,397
              -------   -------   -------

TOTAL
Oil-barrels   246,000   236,000   263,000
Gas-Mmcf ..     2,686     2,479     4,207

     During the  fiscal  year  1996,  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
1995.  This data was  reported on a gross  operated  basis  inclusive of royalty
interest and,  therefore,  does not compare with Columbus' net reserves reported
for 1995.

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

                                                  Fiscal Year
                                            1996      1995      1994
                                            ----      ----      ----

Average sales price per barrel of oil
  USA ...............................      $19.42    $16.75    $15.28
  Canada (U.S.$)(1) .................        --       11.61     10.13
  Total Company .....................       19.42     16.48     14.47

Average sales price per Mcf of gas
  USA ...............................      $ 2.15    $ 1.71    $ 1.92
  Canada (U.S.$) ....................         --       1.09      1.39
  Total Company .....................        2.15      1.60      1.74

Average production cost per
  equivalent barrel
  USA ...............................      $ 4.35    $ 4.16    $ 3.31
  Canada (U.S.$) ....................         --       2.89      2.94
  Total Company .....................        4.35      3.99      3.20

     Natural gas  converted to oil at the ratio of six Mcf of natural gas to one
barrel of oil.  Production  costs for fiscal  years 1996,  1995 and 1994 include
production taxes.

(1)  Natural gas liquids are combined with oil.

                                       10
<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, 1996           Gross                       Net
-----------------      -----------------         -------------------
                       Oil           Gas         Oil             Gas
                       ---           ---         ---             ---

Wells - USA            76            149          19              18

Acres - USA                  34,218                     9,435

Undeveloped Properties

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

November 30, 1996                       Gross Acres                 Net Acres

  Louisiana                               31,565                        3,946
  Montana                                  7,802                        4,806
  New Mexico                                 840                          630
  North Dakota                             3,750                        1,615
  Oklahoma                                 2,040                          510
  Texas                                    1,279                          722
                                          ------                       ------

Total Undeveloped Properties              47,276                       12,229
                                          ======                       ======

(a) Additional  undeveloped  leaseholds  under option in Louisiana  total 12,845
    gross acres and 1,606 net acres.

                                       11
<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.

                                         Year Ended November 30,
                      ----------------------------------------------------------
                            1996                 1995                  1994
                      ---------------       --------------       ---------------
                      Gross       Net       Gross      Net       Gross       Net

EXPLORATORY
Wells Drilled:
  United States
    Oil                --          --         1        .68          1        .09
    Gas                --          --        --         --         --         --
    Dry                 2         .68        --         --          1        .68
  Canada
    Oil                --          --        --         --          1        .33
    Gas                --          --        --         --          1        .32
    Dry                --          --        --         --          1        .50
DEVELOPMENT
Wells Drilled:
  United States
    Oil                 2        1.00         1        .19         --         --
    Gas                14        2.60         8        .62         18       2.73
    Dry                 6        2.95         3       1.16          2        .34
  Canada
    Oil                --          --        --         --          1        .33
    Gas                --          --        --         --          3       1.46
    Dry                --          --        --         --          2        .67
TOTAL
Wells Drilled:
   Oil                  2        1.00         2        .87          3        .75
   Gas                 14        2.60         8        .62         22       4.51
   Dry                  8        3.63         3       1.16          6       2.19
                       --        ----       ---       ----         --       ----

       Total           24        7.23        13       2.65         31       7.45
                       ==        ====       ===       ====         ==       ====

                                       12
<PAGE>

Current Activities

     The Company concentrated on development of its properties and expanding its
undeveloped acreage in Louisiana during fiscal 1996. Capital expenditures by the
Company in the United States totaled  $7,116,000 for development and exploration
drilling  and property  acquisitions  in the natural gas prone areas of Webb and
Zapata   counties  near  Laredo,   Texas  and  in  the  Austin  Chalk  trend  of
midLouisiana.

     A  review  of the  more  significant  results  follow  below  and has  been
segregated by Columbus' major areas of operations.

South Texas - Laredo Area

     Though  not its  largest  source of lease  level  cash  income for the past
several  years,  this area remains its single most important from an operational
standpoint.  The  Company is  operator  of over 100 natural gas wells in various
fields  from the  southern  city  limits of Laredo to the B.R.  Cox field in Jim
Hogg, County, almost 80 miles to the south.

     Columbus  owns working  interests  which range from 1% to 53% in all of the
wells which it  operates.  One  acquisition  was closed in December  which added
small  interests in a total of 107 mostly mature wells (6.2 net).  This purchase
was  effective as of November 1, 1995 and daily  production  approximated  2,000
Mcf/d and 10 barrels of condensate per day. A similar  acquisition of additional
interests in 22 (3.9 net) producing wells in Webb and Zapata Counties, Texas was
completed in June 1996.  During 1996 a total of 12 gas wells were drilled in the
Laredo area with 11 (1.3 net) successfully completed.

     In the B.R.  Cox  field,  a new  operator  conducted  a minor  recompletion
program of new  behind-the-pipe  intervals in four wells  during 1996.  Two (0.5
net) attempts were  successful  and two (1.5 net) were  uneconomic and the wells
were abandoned. This recompletion program's lack of success was disappointing as
has been  Columbus'  investment  in this field almost from the beginning in 1994
when  significant  problems  developed  with  the  two  initial  wells  drilled.
Substantial cost overruns were encountered and eventually they were completed in
intervals  which  were  not  the  primary   objectives.   The  likelihood  of  a
satisfactory  return ever occurring improved somewhat during 1996 as a result of
higher prices and limited recompletion success.

                                       13
<PAGE>

Sralla Road Field Area - Harris County, Texas

     This operational area has been Columbus' primary source of field level cash
flow for the past several years and is expected to be reasonably important for a
few more  years.  During the fourth  quarter  the  Wiggins  Unit #1 (78% WI) was
completed in the upthrown  fault block of the West Jackson Sralla Road oil field
and extended the productive  limits of its gas cap by almost one mile southwest.
Logs indicated a similar thickness (about 6 feet) to other Jackson sand wells in
the field,  but appeared to have somewhat higher porosity which  undoubtedly has
contributed  to the new well's  capability  of  producing  natural  gas at rates
several times its state-assigned allowable of about 1,400 Mcfd. However, even at
this  restricted flow rate it contributed an immediate 10% increase in Columbus'
daily gas  production  following  its  connection  in early  November  1996.  In
addition,  the Wiggins Unit #1 has been yielding  approximately 35 to 40 barrels
of  condensate  in  conjunction  with  each  Mmcf  of  gas  produced  since  its
connection.

     Earlier  during the first  quarter 1996, a 160-acre unit was formed and the
Brewer #2 (.66 WI) was  completed as a high ratio oil well which  extended  this
upthrown block field about 0.8 miles  southwest of the Ferguson #1 oil discovery
in October 1995. A third  160-acre  drilling unit to the west of that  discovery
well was drilled  during  second  quarter of 1996 but the  Jackson  sand was not
present so that well bore was abandoned.

Williston Basin Area

     The  Company  encountered  equipment  shortages  and was  forced  to  delay
drilling plans for this area of its operations during 1996.  However, a geologic
study of certain  fields in Montana and North  Dakota was  conducted in order to
ascertain  what  workovers  of  current   producing   zones,   recompletions  of
behind-the-pipe  zones  or  possible  horizontal  drilling  candidates  could be
justified. Also, the Company completed a 3-D seismic program early in the fourth
quarter,  aimed at locating the best structural well site to replace an existing
90%-owned  12,200 foot Red River oil well producer in the Southeast  Froid field
in Montana.  This twin well is expected to be a  substitute  for the junked well
bore which is located  approximately  300 feet to the east and has been  pumping
for about ten years from a depth of only 7,600 feet due to a  collapsed  section
of its 5 1/2 inch production  casing at about 8,000 feet.  Because  Columbus was
unable to contract for a large drilling rig during the fourth quarter, it had to
postpone  drilling the new well until January  1997.  This  replacement  well is
expected to drain the  remaining  Red River oil  reserves in the field much more
quickly while assuring that the Company can hold a substantial  leasehold  block
for a few more years.  During the first quarter of 1997 the McCabe 1-X twin well
has been  drilled,  logged and cased and will  shortly be  completed  in the Red
River. Assuming no problem in obtaining a successful completion,  it is proposed
that the  McCabe  #1 Red River  zone be  abandoned  and its  cased  well bore be
utilized to produce from a potential uphole oil zone. This will require

                                       14
<PAGE>

cutting a window  immediately  above the  collapsed  interval  and drilling in a
side-tracked  hole down to complete the  Winnipegosis  formation at about 11,000
feet and  complete  as an oil well  there or in  another  prospective  shallower
interval if it proves unsuccessful.  Crude oil was previously produced from that
zone from an offsetting but  structurally  lower well. While conducting this 3-D
seismic program the Company also encountered several leads which lend support to
old 2-D seismic data which had indicated  the possible  existence of two or more
separate Red River  structures on this same acreage  block.  Based upon this new
3-D data,  Columbus  added  several  hundred  more  acres of new  leases and has
scheduled a supplemental 3-D seismic program for March 1997 jointly with another
oil company.  Columbus now holds a 90% working  interest in about 2,000 acres of
leaseholds immediately  surrounding the Southeast Froid field which also overlie
those  potential  new  structures.  Encouraged  by the current oil price levels,
Columbus fully expects that the Williston  Basin in general,  and this Southeast
Froid field area in particular,  will yield  significant  additions to its daily
oil production during 1997. At $1 million for a successfully completed Red River
oil producer  and $600,000 for a  12,200-foot  dry hole,  these  prospects  will
undoubtedly  command a substantial part of the Company's  drilling budget for at
least the next year or two. Also,  Columbus plans to drill shortradius  laterals
during 1997 in a few of its existing older Mission Canyon  formation  producers.
Based upon the reported  successes by other operators who have utilized this new
technology,  management has been encouraged  that meaningful  increases in daily
oil production and reserves can be added as a result of this effort.

Oklahoma - Anadarko Basin

     There were two (0.675  net)  exploratory  wells that  resulted in dry holes
although one had initially  indicated a potential gas discovery  until acidized,
produced unacceptable rates of water along with the gas and had to be abandoned.
A third well (0.3375 net) in this area was completed as a small oil producer.  A
fourth well was scheduled but drilling  equipment  delays postponed its drilling
until the first quarter. It has apparently found Morrow formation oil production
and  is  initially  undergoing  testing  in  one of  its  two  prospective  sand
intervals.

Goudeau Prospect - Avoyelles & St. Landry Parishes, Louisiana

     Columbus   added  an  entirely  new  area  of  interest  in  late  1995  in
mid-Louisiana  when it joined with three co-venturers to promote the acquisition
of leaseholds and the drilling of deep (15,500 feet vertical depth) wells,  with
single and dual horizontal extensions therefrom. The co-venturers formed a three
township  Area of Mutual  Interest  ("AMI") in the deep Austin  Chalk trend in a
known oil productive  area.  This was fortunately a few months prior to the time
the leasing activity level began to accelerate as a result of several successful
completions  of high volume  producers in new fields to the northwest of the AMI
on a production trend extending west to the Texas border. The Company throughout
fiscal  1996  continually  emphasized  the  potential  importance  of this  area
beginning  with its annual report and Form 10-K for the year ended  November 30,
1995 published in March,  1996 and subsequently in each of its regular quarterly
shareholder  reports.  A Special Interim Report to shareholders  dated September
27, 1996 was specifically devoted to the Company's  involvement in this prospect
area and  presented  far more details than could  possibly have been included in
those prior reports.

                                       15
<PAGE>

     Management  has stated on several  occasions  that this new area offers the
most  potential to add sizable new oil reserves  fairly  quickly than any of its
other core  operating  areas.  This AMI is located in St.  Landry and  Avoyelles
Parishes  and  the   leaseholds   are  known  to  overlie  a  250-foot  zone  of
geo-pressured,  fractured Austin Chalk. This onshore play has received extensive
publicity  recently in various trade  publications  because several dual lateral
wells have been completed along that trend which were drilled 4,000 feet or more
horizontally  from vertical bore hole depths ranging from 14,000 to 17,000 feet.
These high pressure completions have been large capacity natural  gas/condensate
and crude oil producers whose reported  initial  productivity  tests have ranged
from 2,000 to 6,000  barrels of oil or  condensate  per day along with 2.5 to 25
Mmcfd for some of those wells.  A few  uneconomic  wells have also been recently
drilled  along this trend using  up-to-date  technology  but these appear not to
have dampened the enthusiasm of the principal  operators in this new play as new
locations and joint ventures have been announced  fairly  frequently  during the
past few months.

     The Company and its three individual  co-venturers had originally  proposed
to promote several  companies'  participation  in a drilling program of at least
two  wells  on our  initially  assembled  block  of  issued  and  option  leases
consisting  of  approximately  24,000 acres.  However,  in the spring of 1996, a
large independent  operator,  Belco Oil & Gas Corporation  ("Belco"),  agreed to
acquire a 75% working  interest in that block,  agreed to accept the  previously
designated  three  township  AMI,  and then  undertook  to  acquire  substantial
additional acreage on behalf of the group. Because of an intervening increase in
acreage  bonuses had  occurred  along the trend  following  the block's  initial
assemblage,  the  co-venturers  (including  Columbus  for its 6.25%)  realized a
profit from Belco's acquisition of the base acreage block. The co-venturers were
also to be carried by Belco for an after-payout 25%  participation in a new well
drilled from the  grassroots to  approximately  15,000 feet vertical  depth with
dual  opposing  laterals  of about  4,000 feet each.  Belco also  undertook  the
group's  prior farmout  obligation  to re-enter and drill a single  lateral hole
from a previously abandoned vertical cased wellbore within the AMI. This farmout
had  initially  been acquired in order to have  available a cased  vertical well
bore from which to test  recent  horizontal  drilling  technology  and  drilling
fluids  which  the  co-venturers  had  planned  to  utilize  had  they  retained
operatorship.  After yielding that re-entry  prospect to Belco,  Columbus had no
further  participation  rights and was relieved of incurring any expenses in the
farmout.

                                       16
<PAGE>

     Belco  subsequently moved in a rig and completed that farmout re-entry well
in August  1996.  To date,  it has made only one press  release  regarding  that
well's  initial  results in which it revealed a test having an initial flow rate
of 2,500  BOPD and 2.7  Mmcfd  from a single  3,900-foot  lateral  hole  drilled
horizontally  from a 15,333 foot vertical depth. This test was conducted through
a 1/2 inch  choke  with a flowing  tubing  pressure  of 1,000  psi.  No  further
official announcements have been made but industry press has speculated that the
flow rate has declined  fairly rapidly after being placed on production to about
200 barrels of oil per day.

     As  discussed  in  that  Special   Interim   Report  in  September,   Belco
subsequently acquired additional leaseholds within the AMI over the summer which
increased  the  block's  total to more than  44,000  gross  acres and 39,700 net
acres. As of that report,  Columbus owned varying  interests from 6.25% to 12.5%
under all issued leases and had a 6.25% interest in  approximately  14,000 acres
of leasehold  options which are  exercisable  in 6-month  intervals,  in minimum
options  of 2,000  acres of newly  issued  leases,  each  having a 5-year  term.
Assuming all of those leasehold options are exercised over the next three years,
Columbus  and  its  co-venturers  will  not  only  have  a  fully  paid  up  25%
participation  in those newly  issued  leases but also will  realize a profit of
about $300,000 to each party.

     As more fully described in Special Interim Report, Columbus' 12.50% working
interest  in the  16,000  gross  acres  within  the AMI added by Belco  could be
reduced by 3.125% (to 9.375%) if one of the co-venturers exercised his option to
acquire that interest at cost on or before  October 28. The  co-venturer in fact
did timely exercise his option;  however, on November 29, 1996, the Company paid
$275,000 in cash and issued  30,000 shares of its Common Stock to acquire all of
that  co-venturers'  interest  throughout  the  AMI.  This  transaction  brought
Columbus'  interest up to a uniform 12.50%  throughout the assembled 44,000 acre
block plus such other additionally  acquired  leaseholds yet to be identified or
assigned by Belco  estimated to be about 6,000 to 8,000 acres.  The  transaction
also  included the  purchase of that  co-venturer's  15% working  interest in an
existing  vertical well bore  completion in the Austin Chalk and his  overriding
royalty  interests of  approximately  1.3% and 1.6% in two existing Austin Chalk
single  lateral oil wells.  The  co-venturer  retained  his right to receive the
$300,000 of future  profits to be earned  should  Belco elect to exercise all of
the remaining leasehold options.

     It had been  expected  that Belco  would  have  before  year end  commenced
drilling the carried-interest  grassroots dual lateral well. However,  delays in
receiving approval from government  regulatory agencies for the surface location
forced the deferral of contracting  for a drilling rig. In order to speed up the
timetable for commencement of operations,  the co-venturers  recently negotiated
an amendment to Belco's  original  agreement  related to the  co-venturers'  25%
carried  working  interest  after  payout  in  that  grassroots  well.  The  new
arrangement  basically spreads that undertaking over two wells by allowing for a
portion of the

                                       17
<PAGE>

obligation to be satisfied by utilizing an existing  vertical well bore owned by
all parties  which  already has casing in place  almost to the top of the Austin
Chalk. This Morrow #1-23 well is located in Section 23 of Township 2 South Range
4 East around which a  1,960-acre  rectangular  unit has now been created  which
will permit acceptable length opposing dual laterals of about 4,000 feet each to
be drilled by Belco.  The Company and its  co-venturers  will be responsible for
paying  their  25%  (12.5% to  Columbus)  share of the cost of  re-entering  the
existing  cased well bore,  analyzing the  integrity of the existing  casing and
adding a liner into the top of the Austin Chalk, if required. Thereafter, Belco,
at its sole expense,  will drill the two horizontal  opposing lateral holes from
this  wellbore,  run slotted  liners in each,  add  production  equipment in the
vertical hole, and complete with surface equipment as appropriate.  Columbus and
its  co-venturers  will share in the initial  revenues  from this first well but
only for a  fraction  of their  regular  25%  revenue  stream  that will be in a
proportion  which their  respective  costs incurred bears to total  expenditures
incurred by all parties in  re-entering  and placing the well into a  productive
status.  Following recovery by Belco of its disproportionate  share of the total
well  costs,  the  regular  25%  working  interest  revenue  stream will flow to
Columbus (12.5%) and its co-venturers (12.5%) as opposed to the lower percentage
of revenues received during the payout period.

     A second  well will be at the site of the  originally  selected  grassroots
well with its vertical  wellbore  located on the section line between Section 20
and 29 of Township 2 South, Range 5 East in the middle of a 1960-acre unit which
will be declared for this well. A similar cost and percentage of revenue sharing
approach  will  apply to this  second  well,  except the roles  essentially  are
reversed.  That is, Belco will be responsible for paying all of the expenditures
necessary to drill and case the well to a vertical depth of approximately 15,000
feet in preparation  for the drilling of dual opposing  lateral  holes.  At that
point, the Company and its co-venturers  will pay 25% of the expenses  (one-half
borne by Columbus)  required to drill two laterals of approximately  4,000 feet,
run  slotted  liners,  and install  downhole  equipment  and surface  facilities
required  to  place  the  well  on  production.  Once  again,  Columbus  and its
co-venturers  will  realize only a portion of their  regular 25% revenue  stream
during  payout  which is  equal  to a  fraction  determined  by  their  share of
expenditures  as the numerator and the total of all  expenditures by all parties
as the denominator.  When Belco has fully recovered its disproportionate  costs,
then  the  full  25%  revenue  stream  will  flow to  Columbus  (12.5%)  and its
co-venturers (12.5%).

     Assuming one or both of the wells are  successfully  completed (as to which
there can be no  assurance),  the  length of the  payout  period for each of the
wells will be dependent upon the total costs  incurred,  the initial  completion
rates  achieved,  and  the  rate  of  production  decline  thereafter.   Initial
completion  rates are basically an outgrowth of and  determined by the extent of
the natural vertical fracturing encountered in the lateral segments of

                                       18
<PAGE>

these well bores.  These fractures in turn will have a significant effect on the
subsequent  rate of  productivity  decline plus the eventual oil and natural gas
reserves to be  recovered  from each well bore.  Without  actually  drilling the
holes,  the frequency or size of fracturing which will be encountered in each of
the  horizontal  laterals  cannot be  forecasted  with any  accuracy  whatsoever
although  some  companies  are relying on seismic to help find areas where heavy
fracturing is thought to be present.  Therefore the Company cannot  forecast the
payout period for either of the two wells or to  unequivocally  state there will
even be a payout in either well. However,  based on performance of several wells
recently  completed  in this same Austin Chalk  interval  along the trend to the
northwest of the AMI,  payouts  could be as short as three to six months as have
been  experienced  in those  wells or in the case of others may  recover  only a
small portion of their costs. Management expects that the success of these first
two  wells in the AMI will be  similarly  measured  by not  only the  degree  of
fracturing  encountered in the dual laterals but also on the ability of Belco to
complete  the wells  without  incurring  costs in excess of  budget.  Should the
development of the AMI prove only  moderately  successful and assuming  Columbus
participates in the 25 or so possible  locations on its leaseholds that could be
drilled over the next five years, this new prospect area possesses the potential
to significantly  increase  Columbus'  proved  developed crude oil reserves.  If
these  initial  two tests prove  unsatisfactory,  the  Company's  share of costs
should be no more than a dry hole Red River wildcat in its Montana program.

     Management is confident  that its  leaseholds are located "on trend," since
there  have  been  numerous  wells  drilled  in the  past  within  this AMI that
penetrated  the Austin Chalk on the way to the deeper high  pressure  Tuscaloosa
formation.  Logs from those wells have  exhibited a fairly  uniform  prospective
zone of fractured  Austin Chalk  having  about 250 feet in  thickness.  In fact,
several wells encountered such severe fracturing while drilling the Austin Chalk
interval  that the wells were later  completed in the zone using  vertical  well
bores  only.  These  completions  occurred  several  years  ago  before  present
horizontal  drilling  technology  was  available.  Some of those  well bores are
located  on  leases  in which  Columbus  holds a working  interest  which  could
contribute to  significant  future cost savings from the drilling of one or more
laterals from those well bores which had originally been cased to 15,000 feet or
more.

     Currently Belco has completed building location, the drilling rig has moved
in and it has begun  operations  to  re-enter  the Morrow  well in  Section  23.
Management  believes  that the  delays in  obtaining  approval  for the  surface
location of the second  well  should be  overcome in time for the  drilling of a
well at that site shortly after completion of Morrow #1-23.

                                       19
<PAGE>

Titles

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

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

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

Competition, Marketing and Customers

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

                                       20
<PAGE>

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

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

     Customers.  Sales to three  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,  1996,  1995  and  1994,  are set  forth in Note 3 to Notes to the
Consolidated  Financial  Statements.  In the opinion of management,  a loss of a
customer has not to date,  and should not in the future,  materially  affect the
Company  since the nature of the oil and gas  industry is such that  alternative
purchasers are normally available on very short notice.

Government Regulations

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

     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.

                                       21
<PAGE>

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.

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.

                                       22
<PAGE>

Item 3.  LEGAL PROCEEDINGS

     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 1996, no matters were  submitted to a vote of
security holders.

                                       23
<PAGE>

                                     PART II

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

     The  common  stock of  Columbus  commenced  trading on the  American  Stock
Exchange on March 11, 1993. The common stock  previously  traded on the American
Stock Exchange  Emerging  Companies  Marketplace since July 30, 1992, and on the
Pacific  Stock  Exchange  since April 15, 1988.  The reported high and low sales
prices for the periods ending below were as follows:

                                        High(1)               Low(1)

1997:
  December 1, 1996 through
     January 31, 1997                   $11.00                $ 9.125

1996:
  First quarter                         $ 5.75                $ 5.00
  Second quarter                          8.00                  5.375
  Third quarter                          11.375                 7.00
  Fourth quarter                         10.875                 9.50

1995:
  First quarter                         $ 8.07                $ 7.25
  Second quarter                          8.25                  7.375
  Third quarter                           7.875                 6.375
  Fourth quarter                          6.75                  5.625

1994:
  First quarter                         $ 8.78                $ 7.75
  Second quarter                          9.32                  8.41
  Third quarter                           8.75                  8.41
  Fourth quarter                          8.52                  7.95

(1) Price  per  share  amounts  have been  adjusted  for the 10% stock  dividend
    distributions  to  shareholders  of record on February 24, 1995 and March 2,
    1994.

     As of January 31, 1997 the reported  closing sales price of Columbus common
stock was $10.13 per share.

       As of November 30, 1996, there were  approximately  480 holders of record
of Columbus'  common stock and an estimated 1,200 or more beneficial  owners who
hold their shares in brokerage accounts.

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

                                       24
<PAGE>



Item 6.  SELECTED FINANCIAL DATA

     The following  table sets forth selected  financial data of the Company and
its  consolidated  subsidiaries  for each of the years in the  five-year  period
ended November 30, 1996,  which  information has been derived from the Company's
audited financial statements. This information should be read in connection with
and is qualified in its entirety by the more detailed  information and financial
statements under Item 8 below.
<TABLE>
<CAPTION>
                                                                      Year Ended November 30,
                                              1996            1995(a)          1994            1993             1992
                                              ----            ----             ----            ----             ----
                                                                 (in thousands, except per share data)
<S>                                         <C>             <C>              <C>             <C>              <C>     
Operating data:
  Revenues                                  $ 11,815        $  9,400         $ 13,141        $ 12,913         $ 11,124
  Loss on asset disposition,
    impairment of long-lived
    properties, and abandonments                (165)         (3,055)            --              (258)            --
  Earnings (loss) before cumulative
    effect of accounting change                2,098          (1,495)           2,190           2,814            2,415
  Cumulative effect of accounting
    change                                      --               --              --               992             --
                                            --------        --------         --------        --------         --------
  Net earnings (loss)                           2,098         (1,495)           2,190           3,806            2,415
                                            =========       ========         ========        ========         ========
  Earnings (loss) per share (primary):
    Before cumulative effect of
      accounting change                     $     .68       $   (.48)        $    .67        $    .83         $    .70
    Cumulative effect of
      accounting change                          --             --               --                29             --
                                            ---------       --------         --------        --------         --------
    Net earnings (loss)(b)                        .68           (.48)             .67            1.12              .70
                                            =========       ========         ========        ========         =========
    Fully dilutive earnings per share             .64            N/A              N/A             N/A               .68
                                            =========                                                         =========
  Average number of common
  and common equivalent
  shares outstanding:
    Primary                                     3,097          3,143            3,269           3,404             3,461
                                            =========       ========         ========        ========         =========
    Fully dilutive                              3,269            N/A              N/A             N/A             3,577
                                            =========                                                         =========
  Cash flow data(d):
    Cash from operating activities          $   5,638       $  3,929         $  6,194        $  5,540         $   4,933
    Cash used in investing activities       $  (6,320)      $   (119)        $ (7,194)       $ (5,652)        $  (2,621)
    Cash provided by (used  in)
      financing activities                  $     644       $ (4,233)        $    519        $     79         $  (2,419)
    Cash flow before changes in
      operating assets and liabilities      $   6,340       $  3,920         $  6,254        $  6,468         $   5,307
    Discretionary cash flow                 $   6,658       $  4,096         $  6,715        $  6,633         $   5,360
 Balance sheet data:
  Total assets                              $  21,625       $ 18,321         $ 24,955        $ 22,938         $  17,811
  Long-term debt, excluding
    current maturities - bank debt          $   2,200       $  1,600         $  4,200        $  3,200         $   2,100
 Stockholders' equity                       $  16,225       $ 13,186         $ 16,202        $ 14,400         $  11,069
</TABLE>
(a)  Does not include  results of CEC Resources  Ltd.  after its  divestiture on
     February 24, 1995.
(b)  Reflects restated amounts for 1992 through 1994 after stock dividends.
(c)  No cash dividends have been declared or paid in any period presented.
(d)  See  discussion of cash flows in  "Management's  Discussion and Analysis of
     Financial Condition and Results of Operations".

                                       25
<PAGE>

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

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

Liquidity and Capital Resources

     Columbus' financial  condition  continues to be very satisfactory.  As 1996
closed,  shareholders'  equity was $16,225,000 after repurchase of 86,100 shares
of treasury  stock  compared to  $13,186,000  at November 30, 1995.  Substantial
positive working capital of $1,966,000 plus the Company's forecasted future cash
flow remains a sufficient source of capital to develop its undeveloped  reserves
as well as fund a modest exploratory program. The $7,000,000 bank borrowing base
of its credit facility has been designated by management for acquisitions of new
oil and gas  properties  although  the loan can be used for any legal  corporate
purpose.

     Revenues for 1996 (without benefit of Canada)  increased by 26% compared to
1995 (which did include three months of Canadian  operations)  while comparative
U.S. only revenues increased by 37%. This was primarily the result of 64% higher
natural gas  revenues  due to price and  production  increases.  Net earnings of
$2,098,000  or $.68  per  share  (primary)  for 1996  compared  to a net loss of
$1,495,000, or $.48 per share, in 1995.

     Generally,  accepted accounting principles ("GAAP") require cash flows from
operating activities to be presented.  Net cash provided by operating activities
has ranged from  $4,000,000 to $6,000,000  during the last three years.  Coupled
with the available  borrowing base under the Company's  credit facility this has
provided the liquidity required to finance oil and gas capital  expenditures and
make  treasury  stock  repurchases.  Management  believes  that another  measure
(commonly used in the industry  although not "GAAP") of a company's cash flow is
one determined  before any consideration is given to working capital changes and
without  deduction  of  explora  tion  expenses.  This  is  generally  known  as
discretionary  cash  flow  ("DCF")  for  successful  efforts  companies.  DCF is
important to present for  successful  efforts  companies  because under the full
cost  accounting  method  exploration  costs are  capitalized  and do not affect
operating  cash flow.  Exploration  costs can be increased or decreased  and DCF
would still be comparable to cash flow of full cost companies. Columbus' DCF for
1996 was $6,658,000  compared to $4,096,000 in 1995 which 63% increase  reflects
higher  natural gas and crude oil prices and  production  attained for the year.
DCF is calculated  before debt service.  However,  the Company's  long-term debt
does not require  principal  payments  before July 1999 and interest  expense on
outstanding debt has been relatively insignificant each of the last three years.

                                       26
<PAGE>

     Management takes strong exception with the Financial  Accounting  Standards
Board  Statement  No.  95 which  directs  that  operating  cash  flow  should be
determined  after  consideration  of working  capital  changes and  reflects its
position  on this  matter  in all of its  public  filings  and  reports.  Such a
requirement   ignores  entirely  the  significant  impact  on  working  capital,
including the timing of income  received for and expenses  incurred on behalf of
third  party  owners in wells,  where a company  such as  Columbus  serves as an
operator of properties with only a small working interest.

     Both discretionary cash flow and operating cash flow before working capital
do not represent cash flows as defined by GAAP and are not to be substituted for
net income or cash available from  operations  and do not  necessarily  indicate
that cash flows are sufficient to fund all cash requirements.

     The Company's  U.S.  sales volume of natural gas averaged 7,927 Mcfd during
fourth  quarter  of  1996  was  up  17%  from  1995's  average  of  6,792  Mcfd.
Management's 1996 goal had been to surpass the former record of 2,200 barrels of
oil equivalent per day benchmark attained for U.S.  production during the 1994's
third quarter but was unsuccessful although for the month of November, 2,059 BOE
per day was reached.

     During  1994,  Columbus  hedged  natural  gas prices by selling a "swap" of
100,000  Mmbtu per month for the twelve month period from May 1994 through April
1995 at an average daily price of $2.12 per Mmbtu.  The swap was matched against
the calendar monthly average price on the NYMEX and settled monthly resulting in
an increase in  revenues  of $204,600  for the period from May through  November
1994 and an  increase in  revenues  of  $283,900  during  fiscal 1995 before its
expiration in April 1995.

     The Company  subsequently entered into two new natural gas swaps by selling
60,000 Mmbtu per month for the period from April 1996 through November 1996 with
one at  $1.74  per  Mmbtu  and a  second  at  $1.88  per  Mmbtu.  These  volumes
represented  approximately  65% of  Columbus'  gas  production  at the time.  To
partially protect itself against possible  escalating gas prices for October and
November  1996,  the Company  purchased  NYMEX  futures  contracts for those two
months for 60,000 Mmbtu of natural gas at $1.805 and $1.875,  respectively.  The
October  call  contract  was sold for a profit of  $37,500  in June 1996 and the
November  call option was sold for $4,500 in  September  1996.  These  partially
offset losses from the swaps for those months.  For the eight month period,  gas
sales  revenues  were  reduced by $560,000 as a result of the swaps  because the
market price at settlement exceeded the contract swap price.

     Columbus  also  entered  into a swap of crude oil prices by selling  10,000
barrels per month for the twelve month period from January 1996 through December
1996 at an average  daily  price of $17.25  per  barrel  with a cap of $19.50 as
upside  protection  should  crude oil futures  soar for an unseen  reason.  This
volume represented approximately 50% of its then current monthly production. The
difference  between the hedge price and the actual  daily  closing  price on the
NYMEX was settled  monthly.  Through November 1996 the swap reduced oil revenues
by $232,000 with another  $22,500  deducted for December 1996 because the market
price at settlement exceeded $19.50 per barrel.

                                       27
<PAGE>

     Columbus  entered into another  crude oil swap by selling a strip of 10,000
barrels  per month for the twelve  month  period  from  November,  1996  through
October,  1997 at an average  daily  price of $21.17  per  barrel.  This  amount
represents  approximately 50% of Columbus' current crude oil production.  A loss
of $24,000 was incurred for the month of November 1996.  Also,  Columbus entered
into a natural  gas swap by selling  60,000  Mmbtu per month for the period from
March 1997 through October 1997 at $2.20 per Mmbtu. This volume represents about
20% of Columbus' current natural gas production.

     The  Company's  natural  gas and crude oil swaps are  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 involve, to varying degrees,  elements of
market and credit risk in excess of the amount recognized in the balance sheets.
As  calculated  as of November  30,  1996,  the Company had 1997 natural gas and
crude oil swaps with a notional value of  approximately  $3,557,000 and a market
value of approximately $3,424,000.  The market value changes constantly and over
the term of the  contracts  could even result in a gain for the Company.  Should
the price of crude oil and natural gas futures  remain above the swap price each
month, then the Company revenues would be reduced.  In the case of crude oil for
calendar year 1996, the Company capped that exposure.

     Columbus'  average daily rate of oil production (U.S. only) for 1996 was 9%
more than 1995.

     The Company's  operation and management services segment remains profitable
despite  divesting the principal  source of past profit generated in Canada from
processing fees.

     Columbus had  outstanding  borrowings of $2,200,000 as of November 30, 1996
against its line of credit with  Norwest Bank  Denver,  N.A.  having a borrowing
base which was lowered in 1995,  at the request of the Company,  to  $7,000,000.
The credit is collateralized by oil and gas properties.  At the end of 1996, the
ratio of bank debt to  shareholders'  equity  was 0.14 and to total  assets  was
0.10.  The debt  outstanding  used a LIBOR  option at an interest  rate of 6.9%.
Subsequent to year end through  February 15, 1997, the debt was further  reduced
by $600,000 to  $1,600,000.  The net  increase  or  decrease in  long-term  debt
directly  affects  financing  activities  cash  flow.  This  cash flow item also
reflects the purchase of treasury  stock  discussed  below and benefits from the
proceeds from the exercise of stock options.

                                       28
<PAGE>



     Working capital at 1996 year end remained  positive at $1,966,000  compared
to $1,941,000 at November 30, 1995.  This was achieved  despite  expenditures of
$7,116,000 (including $3,510,000 for acquisitions) for new additions to U.S. oil
and gas  properties as well as the purchase of 86,100  shares of treasury  stock
for $579,000 during the year.

     In February 1995 a 300,000-share  repurchase from the market was authorized
and was  restricted to a maximum price of $8.75.  These could be purchased  from
time to time during 1995,  1996 and beyond out of  available  cash but not using
bank  borrowings.  Through January 1997, the Company  acquired 284,000 shares of
that total,  including  1996's 86,100  shares,  at an average price of $7.12 per
share.

     During  1996,  capital  expenditures  incurred  on oil and  gas  properties
totaled  $7,116,000 for acquisitions and development  drilling and recompletions
primarily in the South Texas and Gulf Coast areas.  This amount differs from the
capital  expenditure  shown in the  Consolidated  Statement  of Cash Flows which
includes cash payments made during 1996 for 1995  expenditures  incurred but not
yet paid as of 1995's year end. Similarly,  there have been expenditures accrued
in 1996 that will not be actually paid until 1997.  Therefore,  that Statement's
reported capital expenditure total is somewhat meaningless and amounts to little
more than an  accounting  for bills paid during a given  period.  The cash flows
from  investing  activities  benefited  in 1995 by the  $4,075,000  net proceeds
received from the divestiture of Resources.

Results of Operations

     It should be obvious  that 1996  revenues  and  expenses  are not  entirely
comparable  to 1995 because of the  aforementioned  divestiture  of the Canadian
subsidiary  toward the end of the first quarter of 1995.  Total Company revenues
increased by 26% in 1996 and if Canadian  operations are excluded from 1995, the
Company's revenues increased by 37%. Higher crude oil and natural gas prices and
production  are  responsible.  The Company's  revenues  decreased by 28% in 1995
compared to 1994 but only by 15% if Canadian operations are excluded.

     Operating income  increased to $3,589,000 in 1996 due to improved  revenues
compared  to 1995's loss of  $1,811,000,  which was  affected by the  impairment
losses  discussed  below.  The  operating  loss in 1995 was  caused by the lower
revenues and higher  depletion  expense.  Even without  Canadian  operations and
impairment losses included, 1995 operating income decreased 57% from 1994.

     The table included below in "Oil and Gas  Operations"  reflects the changes
in both U.S.  and Canada for the  important  areas of  revenue,  production  and
prices.

                                       29
<PAGE>

     The Company had record revenues in 1994 but operating  income  decreased 9%
from 1993's results, which itself had been a record. Litigation expenses in 1994
were  mostly  related to two settled  lawsuits.  Interest  expense  rose in 1994
because of increased  interest rates and amounts borrowed compared to 1993 which
had  decreased as rates and average bank  borrowings  declined.  Net earnings in
1995 (before  impairment  charge)  were at their  lowest  level since 1991.  Net
earnings in 1994 did not match  1993's for reasons  previously  discussed  but a
quick reiteration of those include  increased  exploration  expense,  litigation
expense,  interest  expense,  depreciation  and depletion  charge,  and a higher
effective tax rate.

Impairment of Long-Lived Assets

     The  Company  elected  to adopt  early as of the  beginning  of the  fourth
quarter  of  1995   Statement  of  Financial   Accounting   Standards   No.  121
("SFAS-121"),  "Accounting  for the  Impairment  of  Long-Lived  Assets  and for
Long-Lived  Assets to be Disposed Of". SFAS-121 requires that an impairment loss
be  recognized  when the  carrying  amount  of an asset  exceeds  the sum of the
undiscounted  estimated  future  cash flow of the asset.  The  Company  reviewed
impairment of oil and gas properties  using expected  prices and year end proved
reserves which had been significantly  reduced.  Four areas in Texas,  Oklahoma,
New Mexico and North Dakota  indicated that impairment  losses were greater than
previously   estimated  and  that  it  was  prudent  to  elect  early  adoption.
Accordingly, a non-cash loss of $3,055,000 ($2,260,000 after tax) was recognized
which was equal to the difference  between the carrying value and the fair value
of each asset group. As a result of the adoption of SFAS-121 future amortization
and depletion  expenses were expected to be lower since the total carrying value
has been significantly reduced.

     Prior  to  September  1,  1995,  a  valuation  provision  was made if total
capitalized costs of oil and gas properties,  excluding unproved properties,  by
country,  exceeded (1) the present value of future net revenues  from  estimated
production of proved oil and gas reserves  using constant  prices  discounted at
10% less (2) income tax  effects  related to  differences  between  book and tax
basis  of the  properties.  Therefore,  no  impairment  was  necessary  prior to
adopting SFAS-121 because total capitalized costs in the U.S. were far less than
discounted future net revenues.

     During 1996 an additional  impairment of $165,000 was made for the Oklahoma
area because of abandonment  of a new well drilled which caused the  capitalized
costs to again exceed the fair value in that area.

                                       30
<PAGE>

Oil and Gas Operations

     The following  discussion of the Company's oil and gas  operations is based
upon the tables of production and average prices shown separately for the United
States and Canada. See 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

1996 vs. 1995
    Gas - U.S.                    26 %               32 %                 64 %
    Gas - Canada                   - %             (100)%               (100)%
                               -------            -------              -------
    Total Company gas             26 %                8 %                 44 %

    Oil - U.S.                    16 %                9 %                 28 %
    Oil - Canada                   - %             (100)%               (100)%
                               -------            -------              -------
    Total Company oil             16 %                4 %                 23 %

1995 vs. 1994
    Gas - U.S.                   (11)%              (28)%                (33)%
    Gas - Canada                 (22)%              (68)%                (75)%
                               -------            -------              -------
    Total Company gas             (8)%              (41)%                (45)%

    Oil - U.S.                    10 %                1 %                  8 %
    Oil - Canada                  15 %              (72)%                (67)%
                               -------            -------              -------
    Total Company oil             14 %              (10)%                  0 %

     Natural gas revenues in the U.S.  increased  64% (despite  reductions  from
swaps)  for 1996  compared  to 1995 as a result  of 26%  higher  prices  and 32%
increase in  production.  Average  prices for  natural  gas rose with  increased
demand and severely  depleted  storage  levels  following an extended  1995/1996
winter  heating  season.  Reported  1996  natural gas  revenues  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 increased as a result of
additional  interests  from  property  acquisitions  and  the  effect  of  newly
developed  wells.  Average  prices in the spot market  remain  quite high during
1997's first quarter due to very cold winter weather and low storage.

     Oil revenues in the U.S. for 1996 were up 28% from last year as a result of
a 16% increase in the average price received and 9% higher volumes. Oil revenues
and average prices for 1996 have been reduced by $256,000 ($1.04 per barrel) due
to hedging losses.  The Company had no oil hedges in 1995.  Crude oil production
improved  because of two new Jackson sand oil wells in the Sralla Road field and
a third discovery (78% WI) almost one mile southwest which commenced  production
in November 1996. These increases were sufficient to overcome normal  production
decline elsewhere.

                                       31
<PAGE>


     Natural gas revenues and  production  for 1995  decreased  compared to 1994
primarily as a result of lower prices,  lower gas  production in the Sralla Road
field, and a reversionary  interest in the Company's most productive gas well in
the  Laredo  area  which  accounted  for  about  one-half  of  the  reduced  gas
production.   These  more  than  offset  new  production  from  additional  well
connections in Texas and Oklahoma,  Average prices for natural gas decreased 11%
compared to 1994 but began to increase toward the end of fiscal 1995.

     Oil  revenues  for the U.S.  for 1995 were up 8% from 1994 as a result of a
10%  increase  in the  average  price  received.  In 1995 low crude  oil  prices
dictated  continued  deferral  of any full  scale  oil  development  program  of
undeveloped oil reserves  located in the Williston  Basin.  However,  a moderate
amount of drilling  was planned for 1996 as a result of the 1996 oil swap.  This
at least  afforded some  protection  from previous  drastic  downturns in prices
which had halted drilling plans before anything could be commenced.

     U.S. natural gas revenues and production for 1994 were significantly higher
than 1993 because of new gas well  completions in Texas and Oklahoma.  Even with
the inclusion of the unusual  revenue gains from the 1994 natural gas swap,  the
average  price  realized in 1994 still  decreased by 12%  compared to 1993.  The
Company  experienced  normal decline in oil production in 1994, but a few wells,
which had been made  uneconomic  by oil  prices  and whose  production  had been
curtailed awaiting improvement in oil prices, were returned to production during
fourth quarter of 1994. Also, the flooding of a river near Houston in late 1994,
which required  shutting-in several wells, was primarily  responsible for a drop
in oil  production  of 77  barrels  per day  compared  to the 1994  average  and
resulted in a reduction in gas  production of 2,100 Mcfd for the fourth  quarter
of 1994, compared to 1994's third quarter.

     U.S. oil prices have fluctuated for several years with the same wide swings
experienced  in world  crude oil price.  In 1994 there was a very slow  recovery
with the  average  price for the year  about 13% below  1993.  In 1995 crude oil
prices  declined  during  mid-year  months but recovered by year-end so that the
average  annual  prices were  higher than 1994.  In the spring of 1996 crude oil
prices rose quickly to above $20 per barrel, declined briefly, then rose rapidly
to almost $23 per barrel by year end.

     Fluctuations  of  oil  and  gas  revenues  and  operations  in  Canada  are
consistent  with the spin-off of Resources in February 1995,  i.e. 1995 vs. 1994
revenues decreased 75% which reflects the fact 1995 included only one quarter of
Canadian activity. Similarly, lease operating costs declined when comparing 1995
to 1994.

     Lease operating expenses in the U.S. increased 23% in 1996 compared to 1995
because of  incremental  working  interest  acquisitions  and several  extensive
work-overs  performed  in an effort  to make some  wells  more  economic.  Lease
operating costs on a barrel of oil equivalent basis for 1996 were up slightly to
$2.80 compared to $2.78 for 1995. Lease operating expenses in the U.S. increased
19% in 1995  compared  to 1994  because  of a few  expensive  work-overs.  Lease
operating  costs on a barrel of oil  equivalent  basis for 1995 were up to $2.78
compared to $1.93 for 1994.  Lease operating  expenses in the U.S. had decreased
7% in 1994 compared to 1993 because of fewer  workovers and because  several oil
wells with high operating costs were shut in due to low crude oil prices.  Also,
most new well  additions  in 1994  were  gas  wells  which  usually  have  lower
operating  costs.  Operating  costs  in the U.S.  as a  percentage  of  revenues
decreased to 19% in 1996 due to higher unit prices. This compares to 22% in 1995
and 15% in 1994.

                                       32
<PAGE>

     Production and property taxes have approximated 10% of revenues in 1996 and
1995 and  varies  somewhat  annually  based on  production  in Texas  where  oil
production tax rates are lower than gas  production  tax rates.  In the U.S. the
relationship  of taxes and revenue is not always directly  proportional  because
some local jurisdiction's taxes are based upon reserve evaluations as opposed to
actual revenues or production for a given period.

Operating and Management Services

     This segment of the Company's U.S.  business is comprised of operations and
services conducted on behalf of third parties and includes compressor rentals.

     In 1996, a profit of $210,000 was generated from this segment. Prior to the
Company's  divestiture of Resources,  the Company received significant operating
service  revenue  from its share of  processing  fees at the Carbon  area liquid
extraction  plant.  Those  revenues also  included  fees from the  processing of
Resources'  own gas, but no profit was  generated  from that portion of revenues
since it was offset by a  commensurate  increase  in  Columbus'  well  operating
expenses.

     Operating and  management  services U.S.  revenue has increased each of the
last three years.  Until divested in 1995,  Canadian  operations had contributed
far greater  operating margins but 1995 revenues in the U.S. improved because of
additional billings for operator services related to 3-D seismic testing program
and past audit  adjustments.  These factors  generated a $199,000 profit for the
U.S. segment compared to a $197,000 profit in 1994.

     Specific  amounts of  reimbursed  revenues from  operating  and  management
services received from formerly operated partnerships are disclosed in Note 7 of
the Notes to the Financial Statements.

                                       33
<PAGE>

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 1996 to  $125,000  compared to $160,000 in 1995,
primarily as a result of a decreased  amount of investments and lower short-term
interest rates.  The increase in interest income in 1995 over 1994 was primarily
the result of an increase in the amount of investments  early in the year (after
divestiture of Resources) and higher short term interest rates.

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 although other nonbillable expenses are included herein.

     The Company's  1996 expenses were lower  compared to 1995 because of salary
and staff reductions made in August 1995. Also, incentive bonuses (all non-cash)
totaled only $83,000 in 1996 compared to $110,000 in 1995.

     Reimbursement  for services provided by Columbus officers and employees for
managing Resources for fiscal 1996 had been expected to decrease in anticipation
that Canadian-based  management would take over following a business combination
with another junior oil and gas company. However, merger discussions were placed
on hold in September due to an indicated  oil discovery by Resources  that could
require a substantial  evaluation  period.  Columbus' general and administrative
expense will  increase  when  Resources'  merger occurs in 1997 since no further
staff reductions are planned. Reimbursement of $296,000 was realized in 1996 and
$281,000 for all of fiscal year 1995 for providing these services to Resources.

     The  Company's  U.S.  only  expenses  for 1995 were 6% higher  than  1994's
because employee salary and staff reductions were offset by higher  compensation
from cashless stock option  exercises,  increased fees associated with a regular
listing  on the Amex,  shareholder  and  stock  transfer  expense,  professional
services (which included the fees of a second petroleum  engineering firm) and a
higher matching  percentage  contribution to the Company's 401(k) Plan. Expenses
for 1994 were  higher  than 1993  because  of  employee  salary  increases  plus
incentive  bonuses  of  $111,000  that were  awarded  to all  officers  based on
achievements of the Company in 1993.  Also,  employees had higher medical claims
under the  Company's  self-insured  plan and the Company made a higher  matching
contribution   to  its  401(k)   Plan.   Overall,   the  total  of  general  and
administrative expenses declined in 1995 compared to 1994 due to the spin-off of
Resources.

                                       34
<PAGE>

Depreciation, Depletion and Amortization

     Depreciation,  depletion  and  amortization  of  oil  and  gas  assets  are
calculated  based upon the units of  production  compared to proved  reserves of
each field. The expense is not only directly related to the level of production,
but also is  dependent  upon  past  costs to find,  develop  and  recover  those
reserves.  Depreciation  and  amortization  of  office  equipment  and  computer
software is also included in the total charge.

     Total charges for depletion expense for oil and gas properties increased in
1996 over 1995 due to greater  production  despite the benefit realized from the
1995  write-down of the carrying  value of certain  properties  upon adoption of
SFAS 121.  During 1995 and 1994,  depletion  expense for oil and gas  properties
increased by greater  percentages than the increase in production.  Contributing
to the disproportionately higher depletion expense were much lower gas and crude
oil prices during 1995 and 1994,  which tended to reduce  reserves,  shorten the
estimated  reserve  life and  change  the  economic  limits  of  certain  of the
Company's  properties.  The  lower  carrying  values  of  certain  oil  and  gas
properties  after the  impairment  loss with the adoption of SFAS 121  effective
September 1, 1995 helped to reduce  depletion  expense for the fourth quarter of
1995.

     For 1996 the depletion and depreciation  rate for the Company was $3.86 per
barrel of oil  equivalent  compared  to $3.83 per barrel of oil  equivalent  for
fiscal 1995 and $2.78 per barrel of oil  equivalent  in 1994.  These amounts are
still below the industry average  primarily  because of historically low finding
costs.  However,  without  including  the  benefit of lower  depletion  costs of
Canadian gas properties for one quarter,  the higher cost U.S.  additions  would
have raised the 1995 charge to $4.21 per barrel of oil equivalent.

     During 1994 the Company  wrote-down  U.S. oil and gas  properties  that had
been fully depleted in previous  years totaling  $17,342,000 as a charge against
accumulated  depreciation,  depreciation and amortization.  There was no gain or
loss to the Company because the properties had been fully depleted.

Exploration Expense

     In  general,   the  exploration  expense  category  includes  the  cost  of
Company-wide  efforts  to acquire  and  explore  new  prospective  areas.  Until
Resources was divested in February 1995, the Company's  exploration  expense was
primarily  attributable  to geological  consulting  work provided in Canada plus
limited seismic expense in Canada and the U.S. The successful  efforts method of
accounting  for  oil and gas  properties  requires  that  the  cost of  drilling
unsuccessful   exploratory  wells  and  other  exploratory  costs  be  currently
expensed.

                                       35
<PAGE>

     During 1996 two exploratory  wells drilled in Oklahoma  proved  noneconomic
and  $184,000  was  expensed.  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 an  exploration
expense of $245,000. In 1994 two unsuccessful  exploratory wells were drilled at
a net cost to the Company of $307,000, including one in Saskatchewan, Canada and
one in Harris County,  Texas, about two miles west of the Sralla Road field. The
Texas well also condemned  certain  leaseholds,  while the Company allowed other
leases to expire. Altogether these resulted in an additional charge of $202,000.
These  exploration  expenses  reduce  reported  cash  flow from  operations,  in
addition to net earnings, even though they are discretionary expenses;  however,
these  charges are added back for  purposes of  calculating  discretionary  cash
flow.

Retirement and Separation Expense

     During 1995 a total of $32,000  separation  expense  was paid to  employees
whose  positions  were  eliminated  and a total  of  $109,000  was  accrued  for
retirement  compensation  for past years'  service for two employees who reached
age 65 and were approved by the Board of Directors to receive such compensation.

Litigation Expense

     The litigation expenses in 1995 and 1994 related to two lawsuits previously
discussed in detail in prior Annual Reports. The first, Michael Mattalino, Bruce
L. Davis and Maris E. Penn vs. Columbus Energy Corp. filed on April 23, 1993 was
settled by  agreement  in  September  1994.  The second,  Porter  Farrell II vs.
Columbus  Energy Corp.  filed October 14, 1993 had Columbus'  motion for summary
judgment granted on April 12, 1995 and the lawsuit was dismissed.

Interest Expense

     Interest  expense varies in a direct  proportion to the amount of bank debt
and the level of bank  interest  rates.  The average bank interest rate paid for
U.S. debt in 1996, 1995 and 1994 was 7.2%, 7.9%, and 5.9%, respectively.

Income Taxes

     The Company's income tax position is somewhat  complex.  Resources'  income
was consolidated  with the Company's U.S. income until Columbus'  divestiture of
Resources in 1995. Also, 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  is
expected  to  limit  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.

                                       36
<PAGE>

     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. Beginning in 1997, the Company expects that the only operating
loss carryforwards remaining will be from periods prior to the first Section 382
ownership change. Utilization of those benefits are limited to $904,000 per year
so that the Company's  current  Federal tax provision and liability may increase
in 1997 and  thereafter  unless an active  drilling  program is  maintained.  In
addition,  the  Company  pays  state  income  taxes  and  previously,  until its
divestiture, also included Canadian taxes on Resources' income.

     As  of  November  30,  1994,  additional  carryforward  tax  benefits  were
considered realizable and the post quasi-reorganization  valuation allowance was
reduced by $303,000.  A deduction of $29,000 for  disqualifying  disposition  of
incentive  stock options was taken and was added to additional  paid-in  capital
along with $182,000 for the reduction in the pre quasi-reorganization  valuation
allowance.  The 1994  effective  income  tax rate  increased  because  of higher
Canadian  deferred  taxes.  No tax credit for U.S. income taxes was available to
offset the effect of payment of Canadian taxes.

     During 1995,  the U.S. net deferred tax asset was reduced to $638,000 which
is comprised of a $1,290,000 current deferred tax asset and a $652,000 long-term
tax liability.  The deferred tax asset increased by an estimated $537,000 during
1995. The valuation allowance was increased by a net $96,000 even after Canadian
deferred  taxes were  reduced by $233,000  since such a provision  was no longer
required  following the divestiture.  The estimated  effective tax rate for 1995
was a 26% book benefit.

     During  1996,  the net  deferred  tax asset was reduced to $1,000  which is
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 added to additional paid-in capital.

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  will be  affected  by any  recurrence  of such  economic  conditions.
Recently, inflation has had a minimal affect on the Company.

                                       37
<PAGE>

     In recent years,  oil and natural gas prices have fluctuated  widely so the
Company's results of operations and cash flow have been directly  affected.  Oil
and gas prices have also been significantly  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 year.  Competition  in the  industry  can  significantly
affect the cost of acquiring leases, although in the past decade competition has
lessened as more  operators have  withdrawn  from active  exploration  programs.
Inflation, as well as a recessionary period, can cause significant swings in the
interest  rates  the  Company  pays  on  bank  borrowings.   These  factors  are
anticipated to continue to affect the Company's operations,  both positively and
negatively, for the foreseeable future.

Item 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 42.

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

     None.

                                       38
<PAGE>

                                    PART III


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

     A  definitive  proxy  statement  related  to the  1997  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 1997 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 1997  Annual  Meeting  of  Stockholders  and is
incorporated herein by reference.

                                       39
<PAGE>

                                     PART IV


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

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

    See "Index to Consolidated Financial Statements".....................   42

       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 1996:

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

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

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

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

                                       40
<PAGE>

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

 11       Statement of computation of per share earnings.

 22       Subsidiaries of the Registrant.

 23(a)    Consent of Coopers & Lybrand L.L.P.

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

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

 27       Financial Data Schedule

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

                                       41
<PAGE>

                              COLUMBUS ENERGY CORP.

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



                                                                          PAGE

Report of Independent Accountants ......................................   43

Financial Statements:
   Consolidated Balance Sheets at
   November 30, 1996 and 1995 ..........................................   44

   Consolidated Statements of Operations for the
   years ended November 30, 1996, 1995 and 1994 ........................   46

   Consolidated Statements of Stockholders'
   Equity for the years ended
   November 30, 1996, 1995 and 1994 ....................................   48

   Consolidated Statements of Cash Flows for the
   years ended November 30, 1996, 1995 and 1994 ........................   50

Notes to the Consolidated Financial Statements .........................   51

                                       42
<PAGE>

                        REPORT OF INDEPENDENT ACCOUNTANTS



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


     We have audited the  accompanying  consolidated  balance sheets of Columbus
Energy Corp. and  subsidiaries as of November 30, 1996 and 1995, and the related
consolidated  statements of operations,  stockholders' equity and cash flows for
each  of  the  three  years  in  the  period  ended  November  30,  1996.  These
consolidated  financial  statements  are  the  responsibility  of the  Company's
management.  Our  responsibility is to express an opinion on these  consolidated
financial statements based on our audits.

     We conducted  our audits in accordance  with  generally  accepted  auditing
standards.  Those standards 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.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
consolidated  financial  statement  presentation.  We  believe  that our  audits
provide a reasonable basis for our opinion.

     In our opinion,  the consolidated  financial  statements  referred to above
present fairly, in all material respects, the consolidated financial position of
Columbus Energy Corp. and subsidiaries as of November 30, 1996 and 1995, and the
consolidated  results of their  operations  and their cash flows for each of the
three years in the period ended November 30, 1996, in conformity  with generally
accepted accounting principles.

     As explained in Note 2 to the consolidated financial statements,  effective
September  1,  1995,  the  Company  changed  its  method of  accounting  for the
impairment of long-lived assets.




                                   COOPERS & LYBRAND L.L.P.



Denver, Colorado
February 11, 1997

                                       43
<PAGE>

                              COLUMBUS ENERGY CORP.

                           CONSOLIDATED BALANCE SHEETS

                                     ASSETS

                                             November 30,
                                       -------------------------
                                       1996                 1995
                                       ----                 ----
                                             (in thousands)


Current assets:
  Cash and cash equivalents            $ 1,396           $ 1,414
  Accounts receivable:
    Joint interest partners                889             1,258
    Oil and gas sales                    1,544               817
    Less allowance for doubtful
      accounts                            (116)             (116)
  Deferred income taxes (Note 6)           631             1,290
  Inventory of oil field equipment,
    at lower of average cost or market     115                76
  Other                                     77                85
                                       -------           -------

   Total current assets                  4,536             4,824
                                       -------           -------

Property and equipment:
  Oil and gas assets, successful
    efforts method (Notes 3 and 5)      28,031            22,244
  Other property and equipment           2,001             2,028
                                       -------           -------

                                        30,032            24,272

  Less:  Accumulated depreciation,
    depletion, amortization and
    valuation allowance
    (Notes 2 and 3)                    (12,943)          (10,775)
                                      --------           -------

    Net property and equipment          17,089            13,497
                                      --------           -------

                                      $ 21,625           $18,321
                                      ========           =======

                                                     (continued)

                                       44
<PAGE>

                              COLUMBUS ENERGY CORP.

                    CONSOLIDATED BALANCE SHEETS - (continued)

                      LIABILITIES AND STOCKHOLDERS' EQUITY

                                                 November 30,
                                             -------------------
                                             1996           1995
                                             ----           ----
                                                 (in thousands)


Current liabilities:
  Accounts payable                          $  1,292    $  1,314
  Undistributed oil and gas
    production receipts                           54         348
  Accrued production and property taxes          555         635
  Prepayments from joint interest owners         258         189
  Accrued expenses                               348         318
  Income taxes payable (Note 6)                   33           -
  Other (Note 4)                                  30          79
                                             -------      ------

    Total current liabilities                  2,570       2,883
                                             -------      ------

Long-term bank debt (Note 5)                   2,200       1,600
Deferred income taxes (Note 6)                   630         652

Commitments and contingent liabilities
  (Notes 4, 7, and 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; 3,499,915 shares
    issued in 1996 and 3,328,580 in 1995
    (outstanding 3,155,346 in 1996 and
    3,068,149 in 1995) (Notes 1 and 8)           700         666
  Additional paid-in capital                  17,361      15,842
  Retained earnings (accumulated deficit)
    since December 1, 1987 (Note 2)              720      (1,378)
                                             -------     -------
                                              18,781      15,130
Less:
    Treasury stock, at cost (Note 8)
      344,569 shares in 1996 and
      260,431 shares in 1995                  (2,556)     (1,944)
                                             -------     -------
        Total stockholders' equity            16,225      13,186
                                             -------     -------
                                             $21,625     $18,321
                                             =======     =======



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

                                       45
<PAGE>

                              COLUMBUS ENERGY CORP.

                      CONSOLIDATED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>

                                                                    Year Ended November 30,
                                                                ---------------------------------
                                                                1996         1995            1994
                                                                ----         ----            ----
                                                              (in thousands, except per share data)
<S>                                                           <C>          <C>             <C>    
Revenues:
  Oil and gas sales                                           $10,572      $ 7,902         $11,227
  Operating and management
    services (Note 7)                                           1,087        1,338           1,807
  Gain on sale of assets                                           31            -               -
  Interest income                                                 125          160             107
                                                              -------      -------         -------
         Total revenues                                        11,815        9,400          13,141
                                                              -------      -------         -------

Costs and expenses:
  Lease operating expenses                                      1,965        1,811           2,017
  Property and production taxes                                 1,051          780           1,072
  Operating and management
    services (Note 7)                                             877        1,017           1,052
  General and administrative                                      999        1,278           1,549
  Depreciation, depletion and
   amortization                                                 2,835        2,757           2,965
  Impairments of long-lived
    assets (Note 2)                                               165        3,055               -
  Exploration expense                                             318          245             600
  Retirement and separation                                         -          141               -
  Litigation expense                                               16          127             244
                                                              -------      -------         -------

     Total costs and expenses                                   8,226       11,211           9,499
                                                              -------      -------         -------

     Operating income (loss)                                    3,589       (1,811)          3,642
                                                              -------      -------         -------

Other expense:
  Interest                                                        260          185             253
  Other                                                             2           26              19
                                                              -------      -------         -------
                                                                  262          211             272
                                                              -------      -------         -------
         Earnings (loss) before
         income taxes                                           3,327       (2,022)          3,370
  Provision (benefit) for income
     taxes (Note 6)                                             1,229         (527)          1,180
                                                              -------      -------         -------

            Net earnings (loss)                               $ 2,098      $(1,495)        $ 2,190
                                                              =======      =======         =======
</TABLE>
                                                                     (continued)

                                       46
<PAGE>

                              COLUMBUS ENERGY CORP.

               CONSOLIDATED STATEMENTS OF OPERATIONS - (continued)

<TABLE>
<CAPTION>
                                                             Year Ended November 30,
                                                      1996           1995            1994
                                                      ----           ----            ----
                                                     (in thousands, except per share data)
<S>                                                  <C>             <C>             <C>    
Earnings (loss) per share:
  Primary                                            $   .68         $  (.48)        $   .67
                                                     =======         =======         =======
  Fully diluted                                      $   .64             N/A             N/A
                                                     =======

Average number of common and
  common equivalent shares
  outstanding:
    Primary                                            3,097           3,143           3,269
                                                     =======         =======         =======
    Fully diluted                                      3,269             N/A             N/A
                                                     =======
</TABLE>
  The accompanying notes are an integral part of these consolidated financial
                                  statements.

                                       47
<PAGE>

                              COLUMBUS ENERGY CORP.
                 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                   For The Three Years Ended November 30, 1996
<TABLE>
<CAPTION>
                                                                               Cumulative
                                                                    Retained    Foreign
                                                       Additional   Earnings    Currency
                                    Common Stock        Paid-In  (Accumulated  Translation        Treasury Stock
                                 Shares      Amount     Capital     Deficit)   Adjustments      Shares      Amount
                               ---------   ---------   ---------   ---------   -----------    ---------    ---------
                                           (dollar amounts in thousands)

<S>        <C>                 <C>         <C>         <C>         <C>          <C>            <C>        <C>       
Balances,
  December 1, 1993 .........   3,234,956   $     647   $  14,965   $   3,155    $    (428)     531,737    $  (3,939)

Exercise of employee
  stock options ............      35,730           7         185        --           --           --           --
Tax benefit of
  disqualifying disposition
  of incentive stock options        --          --            29        --           --           --           --
Adjustment for foreign
  currency translation, net
  of $43,000 income tax ....        --          --          --          --            (68)        --           --
Purchase of shares .........        --          --          --          --           --         83,674         (781)
Shares issued for Stock
  Purchase Plan ............      11,423           2         111        --           --         (2,875)          22
10% stock dividend .........        --          --           515      (2,531)        --       (269,777)       2,014
Shares issued for
  Incentive Bonus Plan
  and directors' fees ......        --          --          --          --           --         (8,162)          57
Income tax benefit of
  loss carryforwards
  arising prior to
  quasi-reorganization .....        --          --            50        --           --           --           --
Net earnings ...............        --          --          --         2,190         --           --           --
                               ---------   ---------   ---------   ---------    ---------    ---------    ---------
Balances,
  November 30, 1994 ........   3,282,109         656      15,855       2,814         (496)     334,597       (2,627)

Exercise of employee
  stock options ............      35,658           8         158        --           --           --           --
Adjustment for
  foreign currency
  translation, net of
  $326,000 income tax ......        --          --          --          --            496         --           --
Tax benefit of
  disqualifying
  disposition of
  incentive stock
  options ..................        --          --            25        --           --           --           --
Purchase of shares .........        --          --          --          --           --        246,631       (1,860)
Shares issued for Stock
  Purchase Plan ............      10,813           2          85        --           --         (2,719)          22
</TABLE>

                                                                     (continued)
                                       48
<PAGE>

                              COLUMBUS ENERGY CORP.
          CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - (continued)
                   For The Three Years Ended November 30, 1996
<TABLE>
<CAPTION>

                                                                                              Cumulative
                                                                                   Retained     Foreign
                                                                     Additional    Earnings    Currency
                                               Common Stock           Paid-In    (Accumulated Translation       Treasury Stock
                                            Shares       Amount       Capital       Deficit)  Adjustments   Shares        Amount
                                          ----------   ----------    ----------    ---------  -----------   -------       -------
                                           (dollar amounts in thousands)
<S>                                       <C>          <C>           <C>           <C>         <C>         <C>            <C> 
Dividend related to
  Resources rights
  offering (Note 1)....................         --     $     --      $   --        $    (582)  $  --           --         $  --
10% stock dividend ....................         --           --           (202)       (2,115)     --       (291,399)        2,314
Shares issued for
  Incentive Bonus Plan,
  directors' fees
  and retirement ......................         --           --            (79)         --        --        (26,679)          207
Net loss ..............................         --           --           --          (1,495)     --           --            --
                                          ----------   ----------    ----------    ---------   -----       --------       -------

Balances,
  November 30, 1995 ...................    3,328,580          666       15,842        (1,378)     -0-       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  $  -0-       344,569     $   (2,556)
                                          ==========   ==========   ==========    ==========  ======    ==========     ==========
</TABLE>
   The accompanying notes are an integral part of these consolidated financial
                                   statements.

                                       49
<PAGE>


                              COLUMBUS ENERGY CORP.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
                                                        Year Ended November 30,
                                                        -----------------------
                                                      1996       1995       1994
                                                      ----       ----       ----
                                                               (in thousands)
<S>                                                 <C>        <C>        <C>    
Net earnings (loss) .............................   $ 2,098    $(1,495)   $ 2,190
Adjustments to reconcile net earnings (loss) to
  net cash provided by operating activities:
    Depreciation, depletion, and
     amortization ...............................     2,835      2,757      2,965
    Impairments and loss on asset dispositions ..       165      3,055          6
    Deferred income tax provision ...............     1,148       (576)       889
    Exploration expense, noncash portion ........      --           69        139
    Other .......................................        94        110         65

Changes in operating assets and liabilities:
    Accounts receivable .........................      (358)       411        264
    Other current assets ........................       (38)        40         23
    Accounts payable ............................       (22)       147       (445)
    Undistributed oil and gas production receipts      (294)       (89)       125
    Accrued production and property taxes .......       (80)       (35)       (33)
    Prepayments from joint interest owners ......        69       (264)        27
    Income taxes payable (receivable) ...........        41        (32)        66
    Other current liabilities ...................       (20)      (169)       (87)
                                                    -------    -------    -------

    Net cash provided by operating activities ...     5,638      3,929      6,194
                                                    -------    -------    -------
Cash flows from investing activities:
    Proceeds from sale of assets ................       606         34          7
    Proceeds from sale of Resources
      common stock, net of cash .................      --        4,075       --
    Additions to oil and gas properties .........    (6,863)    (4,144)    (7,044)
    Additions to other assets ...................       (63)       (84)      (157)
                                                    -------    -------    -------
    Net cash used in investing activities .......    (6,320)      (119)    (7,194)
                                                    -------    -------    -------
Cash flows from financing activities:
    Proceeds from long-term debt ................     3,400      2,090      2,200
    Reduction in long-term debt .................    (2,800)    (4,690)    (1,200)
    Proceeds from exercise of stock options .....       643        209        271
    Purchase of treasury stock ..................      (579)    (1,830)      (750)
    Other .......................................      --           (2)        (2)
                                                    -------    -------    -------
    Net cash provided by (used in)
      financing activities ......................       664     (4,223)       519
                                                    -------    -------    -------
    Effect of exchange rate on cash .............      --            8        (19)
                                                    -------    -------    -------
Net decrease in cash and cash equivalents .......       (18)      (405)      (500)
Cash and cash equivalents at beginning of year ..     1,414      1,819      2,319
                                                    -------    -------    -------
Cash and cash equivalents at end of year ........   $ 1,396    $ 1,414    $ 1,819
                                                    =======    =======    =======

Supplemental disclosure of cash flow information:
    Cash paid during the period for:
      Interest ..................................   $   250    $   214    $   235
                                                    =======    =======    =======
      Income taxes (net of refunds) .............   $    41    $    82    $   225
                                                    =======    =======    =======

Supplemental disclosure of non-cash
investing and financing activities:
    Non-cash compensation expense
      related to common stock ...................   $   114    $   162    $    65
                                                    =======    =======    =======
    Oil and gas property additions ..............   $   253    $   185    $  --
                                                    =======    =======    =======
    Dividend for Resources rights ...............   $  --      $   582    $  --
                                                    =======    =======    =======
</TABLE>
  The accompanying notes are an integral part of these consolidated financial
                                  statements.

                                       50
<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 (see below).  Columbus and its
subsidiary  are referred to in these Notes to the  Financial  Statements  as the
"Company".

     On February 24, 1995,  Columbus completed a rights offering to the Columbus
shareholders  to purchase  one share of  Resources  at  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
were  subscribed  (and  oversubscribed)  and yielded an aggregate of  $4,875,000
before  deduction of  Resources'  cash of $674,000 and $126,000 for the costs of
the  offering.  At the  date  of  divestiture  Resources'  book  assets  totaled
$5,434,000  and  liabilities  were  $977,000 with  $874,000  cumulative  foreign
currency loss in equity. The total value assigned to the rights on its books was
$582,000 for the dividend portion of the purchase of Resources  shares.  No gain
or loss can be recognized  for book purposes in a spin-off.  The  combination of
the cash offering price of $3.25 per share plus the value of the rights dividend
assigned was equal to the U.S.  historical book cost of Columbus'  investment in
Resources.  The divestiture was the sale of a foreign  subsidiary engaged in the
same business as Columbus.  No taxes were due Revenue Canada as a result of this
divestiture of common stock because the tax basis exceeded the proceeds received
upon disposition.

(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
managements' 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 Resources through February
24,  1995.  All  significant  intercompany  balances  have  been  eliminated  in
consolidation.

                                       51
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     Cash Equivalents

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

     Oil and Gas Properties

     The Company  follows the successful  efforts  method of  accounting.  Lease
acquisition  and development  costs  (tangible and intangible) for  expenditures
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.

     Provision for  depreciation  and depletion of capitalized  exploration  and
development costs are computed on the unit-of-production  method based on proved
developed  reserves of oil and gas, as estimated by  petroleum  engineers,  on a
property by property basis. Prior to September 1, 1995, an additional  valuation
provision  was  made if  total  capitalized  costs  of oil  and gas  properties,
excluding  unproved  properties,  by country  exceeded (1) the present  value of
future net revenues  from  estimated  production  of proved oil and gas reserves
using constant  prices  discounted at 10% less (2) income tax effects related to
differences  between book and tax basis of the properties.  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.
Depreciation of other assets are provided on the straight line method over their
estimated useful lives.

                                       52
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     Effective for the fourth  quarter  beginning  September 1, 1995 the Company
adopted Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of  Long-Lived  Assets and for  Long-Lived  Assets to be Disposed Of"
("SFAS 121").  This  statement  prescribes  the accounting for the impairment of
long-lived  assets,  such as oil  and  gas  properties.  An  impairment  loss 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.

     Adoption of this statement resulted in an impairment loss (non-cash charge)
of  $3,055,000  for the fourth  quarter 1995 and was  recognized  as  impairment
expense to the oil and gas business segment. The Company reviewed the impairment
of oil and gas properties  for each  successful  efforts pool.  Based on the new
impairment policy, the B. R. Cox field in Texas and the Oklahoma, New Mexico and
North Dakota property pools were determined to be impaired.

     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 gas balancing
of gas  production.  The Company's gas imbalances are immaterial at November 30,
1996 and 1995.

     Quasi-reorganization

     In fiscal 1988, the Board of Directors adopted a corporate resolution which
approved  a  quasi-reorganization  effective  December  1, 1987 and  transferred
$13,441,000 from additional paid-in capital to offset the accumulated deficit.

     Other Property and 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.

     Reclassification

     The prior years  expense  categories  for  litigation  and  retirement  and
separation  expenses  have  been  reclassified  to be  consistent  with the 1996
presentation.

                                       53
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     Income Taxes

     The Company files a  consolidated  income tax return with CGSI.  Resources,
its Canadian  subsidiary,  was also included in the consolidated U.S. income tax
return  through  February 24, 1995 before  terminating  with  completion  of the
divestiture.  Resources  was also subject to tax under  applicable  Canadian tax
law.  Columbus and its  consolidated  subsidiary  have executed a tax allocation
agreement  which  provides for an  allocation  and payment of U.S.  income taxes
based upon each Company's separate tax liability calculation.

     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.

     Earnings Per Share

     Earnings per share are 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.  For 1996 common stock  equivalents
include  shares  issuable upon assumed  exercise of dilutive stock options using
the  average  price for  primary  shares and the much  higher year end price for
fully diluted shares.  For 1995 and 1994 such common stock  equivalents were not
dilutive.  Historical  amounts  have been  adjusted  for the 10% stock  dividend
distributions, in 1995 and 1994.

     Accounting for Stock-Based Compensation

     The Financial  Accounting  Standards Board issued  Statement No. 123 on the
"Accounting  for  Stock-Based  Compensation".   This  statement  prescribes  the
accounting and reporting standards for stock-based  employee  compensation plans
and is effective for the Company's  1997 fiscal year. The Company has determined
it will use the alternative pro forma disclosures as provided.

                                       54
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)



(3) OIL AND GAS PRODUCING ACTIVITIES

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

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

                                     November 30,
                                   ----------------
                                   1996        1995
                                   ----        ----

                                  United      United
                                  States      States

Proved properties ............   $ 27,156    $ 22,153
Unproved properties ..........        875          91
                                 --------    --------

                                   28,031      22,244

Less accumulated depreciation,
  depletion, amortization and
  valuation allowance ........    (11,519)     (9,414)
                                 --------    --------

Total net properties .........   $ 16,512    $ 12,830
                                 ========    ========

                                       55
<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)

<TABLE>
<CAPTION>

                                          Year Ended November 30,
                       ---------------------------------------------------------------
                        1996                 1995                       1994
                       ------      ------------------------   ------------------------
                       United               United                     United
                       States       Total   States   Canada   Total    States   Canada
                       ------      ------   ------   ------   ------   ------   ------
<S>                    <C>         <C>      <C>      <C>      <C>      <C>      <C> 
Property acquisition
  costs:

     Proved ........   $3,025      $1,443   $1,443   $ --     $2,501   $2,501   $ --

     Unproved ......      976          85       85     --         96       59       37

Exploration costs ..      318         245      196       49      600      464      136

Development costs ..    3,115       2,843    2,771       72    3,885    2,360    1,525
                       ------      ------   ------   ------   ------   ------   ------

Total costs
  incurred .........   $7,434      $4,616   $4,495   $  121   $7,082   $5,384   $1,698
                       ======      ======   ======   ======   ======   ======   ======
</TABLE>



                 RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
                                 (in thousands)

<TABLE>
<CAPTION>

                                                      Year Ended November 30,
                        --------------------------------------------------------------------------------
                          1996                        1995                              1994
                        --------        --------------------------------   -----------------------------
                         United                      United                            United
                         States           Total      States      Canada     Total      States     Canada
                        --------        --------    --------    --------   --------   --------   --------
<S>                     <C>             <C>         <C>         <C>        <C>        <C>        <C>     
Sales ...............   $ 10,572        $  7,902    $  7,269    $    633   $ 11,227   $  8,798   $  2,429

Production (lifting)
  costs (a) .........      3,016           2,591       2,343         248      3,089      2,285        804

Exploration expenses         318             245         196          49        600        464        136

Impaiment of long-
  lived assets ......        165           3,055       3,055        --         --         --         --

Depreciaton
  depletion and
  amortization (b) ..      2,703           2,543       2,410         133      2,742      2,355        387
                        --------        --------    --------    --------   --------   --------   --------
                           4,370            (532)       (735)        203      4,796      3,694      1,102
Imputed income
  tax ...............      1,614            (138)       (209)         71      1,691      1,311        380
                        --------        --------    --------    --------   --------   --------   --------

Results of oeprations
  from producing
  activities
  (excluding overhead
  and interest
  incurred ..........   $  2,756        $   (394)   $   (526)   $    132   $  3,105   $  2,383   $    722
                        ========        ========    ========    ========   ========   ========   ========
</TABLE>
(a)  Production costs include lease operating expenses,  production and property
     taxes
(b)  Amortization expense per equivalent barrel of production:
     1996 - $3.86               1995 - $3.83    1994 - $2.78

                                       56
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     For the years ended  November 30, 1996,  1995 and 1994, 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.

                     1996                 1995                1994
              ------------------   ------------------  -------------------
              Amount   % Revenue   Amount   % Revenue   Amount   % Revenue

Customer A    $3,142     29.7%     $2,027      27.9%   $ 1,755      13.4%
Customer B     5,513     52.2       2,635      36.2      4,072      31.0
Customer C     1,212     11.5       1,046      14.4      1,423      10.8

     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.

(4)      INVESTMENT IN PARTNERSHIP

     Columbus was formerly the managing  general partner of Consolidated  Energy
Partners L.P. (the "partnership or "CPS"),  and also operated almost all oil and
gas  properties  owned by its  subsidiary  partnership,  Consolidated  Operating
Partners L.P. ("COP"). When these partnerships were dissolved effective November
30, 1989, no partners  received a cash distribution from their investment in CPS
as the proceeds from the sale of the properties were less than the bank debt and
other partnership liabilities.

     Columbus,  as managing  general  partner of COP,  and  Columbus as managing
general partner had an obligation to pay for the respective  partnership's costs
incurred.  Included in other  current  liabilities  as of November  30, 1995 was
$16,000 which represented  remaining cash available to pay any valid claims that
might become payable related to either  liquidation or prior operations.  During
1996,  this amount was fully used to pay  obligations  of COP.  During  1995,  a
settlement was reached with Jicarilla  Apache Tribe relative to their claims for
additional royalty owed for the period 1985 through 1992 from gas wells on their
leaseholds in which COP owned varying interests and Columbus was operator. COP's
share of the  settlement  was  $95,000  which  was  paid  during  1995  from the
available cash on hand.

                                       57
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(5)  LONG-TERM DEBT

     The Company has a Credit Agreement  ("Agreement") with Norwest Bank Denver,
N.A.  ("Bank")  having a borrowing  base which has been recently  reduced at the
request  of   Columbus   to   $7,000,000,   which  is  subject  to   semi-annual
redetermination  for any  increase or  decrease.  On October 23, 1996 the Credit
Agreement was amended and restated to extend the  revolving  period and maturity
date. The loan revolves until July 1, 1999 and then in its entirety  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 1/2%. In addition,  a commitment fee of 1/4 of
1% of the average unused portion of the credit is payable quarterly.

     At November 30, 1996 outstanding borrowings on the revolving line of credit
were  $2,200,000 and the unused  borrowing base  available was  $4,800,000.  The
$2,200,000 bears interest at LIBOR rate of 5.44% plus 1 1/2%.

     The Agreement as amended provides that certain  financial  covenants be met
which  include a minimum  net worth of  $8,300,000  plus 50% of  Cumulative  Net
Income after  November 30, 1991, 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 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,:


                                    1997                      $     -
                                    1998                            -
                                    1999                          183
                                    2000                          550
                                    2001 and after              1,467
                                                              -------

                                             Total            $ 2,200
                                                              =======

                                       58
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(6) INCOME TAXES

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

                                1996       1995       1994
                                ----       ----       ----

Current:
   Federal .................   $     2    $  --      $    57
   Foreign (Canada) ........      --           29        162
   State ...................        79         20         72
                               -------    -------    -------
                                    81         49        291
                               -------    -------    -------

Deferred:
   Federal .................       288       (612)       227
   Use of loss carryforwards       848       --          366
   Foreign (Canada) ........      --           44        253
   State ...................        12         (8)        43
                               -------    -------    -------
                                 1,148       (576)       889
                               -------    -------    -------

Total income tax
   (benefit) expense .......   $ 1,229    $  (527)   $ 1,180
                               =======    =======    =======

     The components of earnings (loss) before income taxes are (in thousands):

                                         1996           1995           1994
                                         ----           ----           ----

         U.S.                          $ 3,327        $(2,231)       $ 2,167
         Canada                              -            209          1,203
                                       ------         -------        -------

         Total                         $ 3,327        $(2,022)       $ 3,370
                                       =======        =======        =======

     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
                                             1996          1995          1994

         U.S. Statutory rate                  34 %         (34)%          34%
         Foreign taxes (Canada)                -             4            12
         State income taxes                    6            (4)            2
         Change to post-1987
           carryforwards                       4            13            (7)
         Percentage depletion                 (7)           (5)           (4)
         Foreign tax credit/deduction          -            (4)           (4)
         Other                                 -             4             2
                                             ---            ---          ---

         Effective rate                       37 %          (26)%         35%
                                             ===            ====         ===

                                       59
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     The Company files a consolidated  income tax return with its subsidiary and
has executed a tax  allocation  agreement  which  provides for an allocation and
payment of U.S.  income taxes based upon each  company's  separate tax liability
calculation.

     The net operating loss  carryforwards and percentage  depletion  deductions
are for U.S.  tax purposes  only.  For Canadian  income tax  purposes,  when the
annual  taxable  income  of  Resources   exceeded  its  available  Canadian  tax
allowances and deductions for that year,  current income taxes were provided and
a tax liability  recorded.  Canadian  taxes were  currently  payable in 1995 and
1994.  Consolidated  U.S.  income  taxes are payable  only when  taxable  income
exceeds available U.S. net operating loss carryforwards and other credits.

     Pursuant  to  provisions  enacted  as part of the Tax  Reform  Act of 1986,
utilization  of these  corporate  tax  carryforwards  in any one taxable year is
limited  if a  corporation  experiences  a 50%  change  of  ownership.  Columbus
experienced such a change of ownership in October, 1987 effectively limiting the
utilization  of  pre-change  ownership  net  operating  losses to  approximately
$900,000  in each  subsequent  year.  Subsequent  additional  ownership  changes
accumulated  to more  than 50% by  August  25,  1993  thereby  causing  a second
ownership change to occur. During 1996 Columbus utilized  approximately $433,000
of remaining  post-1987 net operating loss carryforwards  which were limited and
approximately $160,000 are available for fiscal 1997 and subsequent years.

     Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("SFAS 109") requires the asset and liability approach be used 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.  U.S.  tax assets (net of a
valuation  allowance)  primarily  result from net operating loss  carryforwards,
percentage  depletion and certain  accrued but unpaid  employee  benefits.  U.S.
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-organization,  SFAS  109
requires the Company 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.

                                       60
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     During fiscal 1996, certain U.S. tax assets (shown in the table below) were
utilized.  Projected taxable income caused the Company to increase the valuation
allowance during the year by $141,000.

     The tax  effect of  significant  temporary  differences  representing  U.S.
deferred tax assets and liabilities and changes were as follows (in thousands):

                                                     Current Year
                                         ------------------------------------
                                 Dec. 1, Stockholders'               Nov. 30,
                                   1995     Equity      Operations    1996
                                 -------    -------     ----------   -------
Deferred tax assets:
  Pre-1987 loss carryforwards    $ 1,976    $  --        $  (615)   $ 1,361
  Post-1987 loss carryforwards       720       --           (124)       596
  Percentage depletion
    carryforwards ............       894       --            236      1,130
  State income tax loss
    carryforwards ............       197       --           (109)        88
  Other ......................       289       --             19        308
                                 -------    -------      -------    -------
                  Total ......     4,076       --           (593)     3,483
     Valuation allowance .....    (1,737)       409(a)      (141)    (1,469)
                                 -------    -------      -------    -------
         Deferred tax assets .     2,339        409         (734)     2,014
                                 -------    -------      -------    -------
  Tax benefit of disqualifying
    disposition of incentive
    stock options ............      --          102(a)      (102)      --
                                 -------    -------      -------    -------

Deferred tax liabilities-
  Depreciation, depletion and
    amortization and other ...    (1,701)      --           (312)    (2,013)
                                 -------    -------      -------    -------
    Net tax asset ............   $   638    $   511      $(1,148)   $     1
                                 =======    =======      =======    =======


(a)  Credited to additional paid-in capital.

     The Company has approximate net operating loss carryforwards (in thousands)
available at November 30, 1996 as follows:

                                                           Net
                  Expiration Year                    Operating loss

                           1999                          $2,710
                           2000                             907
                           2001                             386
                           2003                              45
                           2004                             115
                           2010                           1,593
                                                        -------
                                                        $ 5,756
                                                        =======

                                       61
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     For U.S.  Alternative  Minimum Tax purposes  the Company had net  operating
loss  carryforwards  of  approximately  $6,900,000 as of November 30, 1996.  The
Company also has percentage  depletion  carryforwards of $2,974,000 which do not
expire.   State  income  tax  operating  loss   carryforwards  of  approximately
$1,450,000 are available at November 30, 1996.

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

                                       1996       1995       1994
                                       ----       ----       ----

Earnings loss) before income taxes
  per financial statements .......   $ 3,327    $(2,022)   $ 3,370

Differences between income
  before taxes for financial
  statement purposes and
  taxable income:
  Intangible drilling costs
    deductible for taxes .........    (1,520)    (3,125)    (2,372)
  Excess of book over tax
    depletion, depreciation
    and amortization .............       754        607      1,020
  Disqualifying disposition of
    incentive stock options ......      (273)       (88)       (76)
  Impairment expense .............       165      3,055       --
  Lease abandonments .............      (117)      (258)      --
  Dividend of rights of Resources       --          234       --
  Other ..........................       (95)        72       (105)
                                     -------    -------    -------
Federal taxable income ...........   $ 2,241    $(1,525)   $ 1,837
                                     =======    =======    =======

     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, 1996 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 partially  utilize the NOL's before they expire.  Of the
total  valuation  allowance of  $1,469,000  as of November  30,  1996,  $998,000
relates  to  pre-quasi-reorganization  tax assets  and the  balance of  $471,000
relates to post-quasireorganization  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  postquasi-reorganization
portion of the valuation allowance will be credited to income.

                                       62
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     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 $9,000,000 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  $3,483,000.  This level of income can be achieved  using the value of proved
reserves reported in the year end November 30, 1996 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 1996 the valuation  allowance
was  decreased  by $409,000  related to  pre-quasireorganization  tax assets and
increased by $141,000 for  post-quasireorganization  tax assets. During 1995 the
valuation  allowance was increased $96,000.  During 1994 the valuation allowance
was  decreased by $182,000  related to  pre-quasi-reorganization  tax assets and
decreased by $303,000 for post-quasi-reorganization assets.

                                       63
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(7) RELATED PARTY TRANSACTIONS

     Columbus,   as   managing   general   partner,   previously   had   certain
responsibilities to CPS and COP.  Additionally,  Columbus is contingently liable
for any debts and obligations of COP, excluding the non-recourse  long-term debt
to the bank, even though there has been a dissolution of CPS and COP. This would
only occur after liquidation proceeds available have been exhausted. Columbus is
not aware of any  debts or  obligations  of COP that it may be  liable  for over
those for which those proceeds have ben utilized.

     Certain direct and indirect  general and  administrative  costs incurred by
CPS and COP were  paid  for by  Columbus  and  reimbursed  by CPS and  COP.  The
following  table  sets  forth   reimbursements   (included  with  operating  and
management services revenue) received for each period from COP.

                                                         G & A
                                                       Allocated

     Year Ended November 30, 1996                      $  5,000
     Year Ended November 30, 1995                        11,000
     Year Ended November 30, 1994                        22,000

     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 $296,000 for fiscal 1996 and
$213,000 for the nine months in 1995 following the divestiture of Resources.

(8) CAPITAL STOCK

     Columbus has several stock option plans with outstanding options. Under the
1985 Plan,  options for 73,431 shares were  exercisable at November 30, 1996. No
additional  options may be granted  under the 1985 Plan.  At November  30, 1995,
87,360 shares were exercisable.

     Under the 1995  Plan,  as of  November  30,  1996,  141,044  option  shares
remained   available  for  granting,   and  options  for  180,434   shares  were
exercisable.  At November 30, 1995,  220,185 shares were available for granting,
and options for 166,830 shares were exercisable.

     The Board of  Directors  has granted  nonqualified  stock  options of which
there were  92,196  exercisable  at  November  30,  1996 and 5,296  shares  were
exercisable at November 30, 1995.

                                       64
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     Options  are  granted at 100% of fair  market  value on date of grant.  The
following table represents a summary of stock option  transactions for the three
years ended November 30, 1996:

                                    Shares              Option Price

Balance, November 30, 1993         180,018            $ 3.72 to $ 8.42
   Granted                         202,829              8.26 to   8.47
   Exercised                       (39,924)             4.13 to   7.70
   Expired                          (5,897)             4.86 to   8.26
                                  --------

Balance, November 30, 1994         337,026              3.72 to   8.47
   Granted                         181,965              6.44 to   7.94
   Exercised                       (40,227)             3.72 to   5.89
   Expired, exchanged or
      surrendered                 (196,745)             5.89 to   8.47
                                  --------

Balance, November 30, 1995         282,019              4.34 to   8.47
   Granted                         245,800              5.25 to  10.63
   Exercised                      (161,433)             4.34 to   8.30
   Expired or exchanged            (10,603)             6.44 to   8.30
                                  --------

Balance, November 30, 1996         355,783              4.85 to  10.63
                                  ========

     As of August 1, 1995, the Board of Directors  authorized an exchange of new
stock option grants at the closing price ($6.625) on that date which equaled 80%
of all  previously  granted stock  options.  These could be  surrendered  at the
election  of the holder  provided  that the holder  previously  had his  monthly
salary  reduced as a part of the downsizing  and  administrative  cost reduction
program.  Share options in the amount of 170,521 granted at prices from $5.87 to
$8.47 were  canceled and 66,015 share options were reissued as of August 1, 1995
and 70,400  non-statutory share options were reissued on February 5, 1996 at the
fair market value of the Company shares on that date.

     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 1996 and 1995 years a total of $13,000 and $17,000
matching contribution was 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 1996 a total of
12,394 shares were purchased  (2,492 shares from treasury stock as the Company's
contribution of 25%) at an average cost of $7.32 per share. During fiscal 1995 a
total of 13,532 shares were purchased  (2,719 shares from treasury stock for the
Company contribution of 25%) at an average cost of $8.01 per share.

                                       65
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     During 1993 the Board of Directors  authorized  purchase from the market up
to  350,000  shares  of  common  stock  (375,000  shares  after  stock  dividend
adjustment)  to be held as  treasury  stock.  A total  of  249,200  shares  were
purchased  during  fiscal  1993 at an average  cost of $9.18 per  share.  During
fiscal 1994 an  additional  80,500  shares were  purchased at an average cost of
$9.32 per share.  This was  followed by 45,300  shares  purchased  during  first
quarter 1995 at an average cost of $8.56 per share.

     Another 300,000-share repurchase authorization was approved by the Board in
February  1995,  restricted to a maximum  purchase  price of $8.75 per share.  A
total of 197,900 shares were purchased  during fiscal 1995 at an average cost of
$7.29 per share.  This was followed by 86,100 shares purchased during 1996 at an
average cost of $6.73 per share.

(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.

     Lease - In June 1991,  Columbus  executed a lease for office  space for its
present  building  which  provides  for  monthly   payments  of  $11,123,   plus
inflationary adjustments to an annual base operating expense, for a period of 60
months from October 1991 through  October 1996. The total rent expense for 1996,
1995 and 1994 was approximately  $133,000,  $126,000 and $129,000  respectively.
Columbus has renewed the lease for an  additional  two years  through  September
1998 at a base rate of $13,536 per month. Future rental payments, without regard
to operating cost adjustments, required under this lease as of November 30, 1996
are $162,000 and $135,000 for fiscal years 1997 and 1998, respectively.

     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.

                                       66
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     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 average  year's average  compensation.  Such  compensation  has been
approved for three  individuals who have reached age 65. As of November 30, 1996
the accrued  liability  totals  $178,000  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 $16,000 and
$56,000 in 1996 and 1995, respectively.

     During  1994,  Columbus  hedged  natural  gas prices by selling a "swap" of
100,000  Mmbtu per month for the twelve month period from May 1994 through April
1995 at an average daily price of $2.12 per Mmbtu.  The swap was matched against
the calendar monthly average price on the NYMEX and settled monthly resulting in
an increase in  revenues  of $204,600  for the period from May through  November
1994 and an  increase in  revenues  of  $283,900  during  fiscal 1995 before its
expiration in April 1995.

     The Company  subsequently entered into two new natural gas swaps by selling
60,000 Mmbtu per month for the period from April 1996 through November 1996 with
one at  $1.74  per  Mmbtu  and a  second  at  $1.88  per  Mmbtu.  These  volumes
represented  approximately  65% of  Columbus'  gas  production  at the time.  To
partially protect itself against possible  escalating gas prices for October and
November  1996,  the Company  purchased  NYMEX  futures  contracts for those two
months for 60,000 Mmbtu of natural gas at $1.805 and $1.875,  respectively.  The
October  call  contract  was sold for a profit of  $37,500  in June 1996 and the
November  call option was sold for $4,500 in  September  1996.  These  partially
offset losses from the swaps for those months.  For the eight month period,  gas
sales  revenues  were  reduced by $560,000 as a result of the swaps  because the
market price at settlement exceeded the contract swap price.

     Columbus  also  entered  into a swap of crude oil prices by selling  10,000
barrels per month for the twelve month period from January 1996 through December
1996 at an average  daily  price of $17.25  per  barrel  with a cap of $19.50 as
upside  protection  should  crude oil futures  soar for an unseen  reason.  This
volume represented approximately 50% of its then current monthly production. The
difference  between the hedge price and the actual  daily  closing  price on the
NYMEX was settled  monthly.  Through November 1996 the swap reduced oil revenues
by $232,000 with another  $22,500  deducted for December 1996 because the market
price at settlement exceeded $19.50 per barrel.

                                       67
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     Columbus  entered into another  crude oil swap by selling a strip of 10,000
barrels  per month for the twelve  month  period  from  November,  1996  through
October,  1997 at an average  daily  price of $21.17  per  barrel.  This  amount
represents  approximately 50% of Columbus' current crude oil production.  A loss
of $24,000 was incurred for the month of November 1996.  Also,  Columbus entered
into a natural  gas swap by selling  60,000  Mmbtu per month for the period from
March 1997 through October 1997 at $2.20 per Mmbtu. This volume represents about
20% of Columbus' current natural gas production.

     The  Company's  natural  gas and crude oil swaps are  considered  financial
instruments  with  off-balance  sheet risk  which  were in the normal  course of
business to reduce its  exposure to  fluctuations  in the price of crude oil and
natural gas. Those instruments  involve, to varying degrees,  elements of market
and credit risk in excess of the amount  recognized in the balance  sheets.  The
Company had natural gas and crude oil swaps  outstanding  subsequent to November
30, 1996 as follows:

                                            Market or Settled Value
                                                    as of
                           Notional         ----------------------
                             Value           11/30/96     2/7/97
                             -----           --------     ------

      Natural gas
        (3/97-10/97)       $ 1,056,000     $  988,000   $ 1,110,000
      Crude oil
        (12/96)                172,500        150,000       150,000
      Crude oil
        (12/96-10/97)        2,328,700      2,286,000    2,248,000

     The litigation expenses in 1995 and 1994 relate to two lawsuits. The first,
Michael  Mattalino,  Bruce L. Davis and Maris E. Penn vs.  Columbus Energy Corp.
filed on April 23, 1993 was settled by agreement in September  1994. The second,
Porter Farrell II vs. Columbus Energy Corp. filed October 14, 1993 had Columbus'
motion for  summary  judgment  granted  on April 12,  1995 and the  lawsuit  was
dismissed.

(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  $90,000,
$101,000, and $77,000 in the fiscal years 1996, 1995 and 1994, respectively.

                                       68
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(11) INDUSTRY SEGMENTS

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

     Summarized  financial  information  concerning the business  segments is as
follows:
<TABLE>
<CAPTION>
                                                          1996          1995          1994
                                                          ----          ----          ----
                                                                   (in thousands)
<S>                                                     <C>             <C>          <C>    
Operating revenues from unaffiliated services (a):
     Oil and gas                                        $10,617         $ 7,927      $11,246
     Services                                             1,198           1,473        1,895
                                                        -------         -------      -------

          Total                                         $11,815         $ 9,400      $13,141
                                                        =======         =======      =======

Depreciation, depletion and amortization (b):
     Oil and gas                                        $ 2,763         $ 2,638      $ 2,788
     Services                                                72             119          177
                                                        -------         -------      -------

          Total                                         $ 2,835         $ 2,757      $ 2,965
                                                        =======         =======      =======

Operating income (loss):
     Oil and gas                                        $ 4,339(c)      $  (870)(c)  $ 4,526
     Services                                               249             337          665
     General corporate expenses                            (999)         (1,278)      (1,549)
                                                        -------         -------      -------

          Total operating income                          3,589          (1,811)       3,642
Interest expense and other                                  262             211          272
                                                        -------         -------     --------

          Earnings before income taxes                  $ 3,327         $(2,022)     $ 3,370
                                                        =======         =======      =======

Identifiable assets (b):
     Oil and gas                                        $18,911         $15,238      $20,642
     Services                                             2,715           3,083        4,313
     Other corporate                                          -               -            -
                                                        -------         -------      -------

          Total                                         $21,625         $18,321      $24,955
                                                        =======         =======      =======

Additions to property and equipment:
     Oil and gas                                        $ 7,167         $ 4,423      $ 6,544
     Services                                                12              31           95
                                                        -------         -------      -------

          Total                                         $ 7,179         $ 4,454      $ 6,639
                                                        =======         =======      =======
</TABLE>

(a)  Approximately  $294,000 of  inter-segment  revenues are included in service
revenues in 1994, $105,000 in 1995 and are offset by the same amounts in oil and
gas operating expenses.

(b) 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.

(c) Includes  non-cash  impairment  loss of $165,000 in 1996 and  $3,055,000  in
1995.

                                       69
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     The Company conducted its foreign  operations in Canada until February 1995
through its wholly-owned subsidiary, CEC Resources Ltd.

     Summarized financial information concerning the foreign operations which is
included in the preceding table is as follows:

                                               1995          1994
                                                  (in thousands)

Operating revenues from unaffiliated services (a):
    Oil and gas                               $  639        $ 2,436
    Services                                     150            563
                                              ------        -------
          Total                               $  789        $ 2,999
                                              ======        =======

Depreciation, depletion and
  amortization:
    Oil and gas                               $  116        $   325
    Services                                      17             63
                                              ------        -------
          Total                               $  133        $   388
                                              ======        =======

Operating income:
    Oil and gas                               $  225        $ 1,171
    Services                                     106            497
    General corporate expenses                  (121)          (457)
                                              ------        -------
          Total operating income                 210          1,211

Interest expense and other                         1              8
                                              ------        -------

    Earnings before income taxes              $  209        $ 1,203
                                              ======        =======

Identifiable assets:
    Oil and gas                               $    -        $ 4,680
    Services                                       -            675
                                              ------        -------
          Total                               $    -        $ 5,355
                                              ======        =======

Additions to property and equipment:
    Oil and gas                               $   45        $ 1,499
    Services                                      27             63
                                              ------        -------
          Total                               $   72        $ 1,562
                                              ======        =======


(a)  Approximately  $294,000 of inter-segment  revenues are included in services
revenues in 1994, $105,000 in 1995 and are offset by the same amounts in oil and
gas operating expenses.

(12) 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, 1996 and 1995 the Company had  investments
in commercial paper of $1,000,000 and $1,200,000, respectively.

                                       70
<PAGE>

                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     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.

(13) ACQUISITION OF OIL AND GAS PROPERTIES (Unaudited)

     In December 1995  Columbus  purchased  producing oil and gas  properties in
Texas which was  recorded on December 1, 1995.  Revenues  and  expenses for 1996
related  to the  acquisition  have been  included  for the 12 months of the 1996
fiscal year. The pro forma results below are not necessarily  indicative of what
actually  would  have  occurred  if the  acquisition  had been in effect for the
entire  period  presented.  These results are not intended to be a projection of
future results.  The  incremental  effect of the acquired oil and gas properties
summarized  financial  information (in thousands of dollars) for the 1995 fiscal
year is as follows:

                 Revenues, net of operating expenses $1,152
                 Operating income(a)                 $  469
                 Net income(b)                       $  347
                 Earnings per share                  $  .11

                 (a) Net of pro forma depreciation and depletion
                     and interest expense.
                 (b) Net of pro forma income taxes at 26% effective
                     rate.

                                       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 21, 1997          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
By: /s/ Harry A. Trueblood, Jr.  Executive Officer                  2/21/97
-------------------------------                                     -------
Harry A. Trueblood, Jr.

                             Chief Operating Officer

                                 Executive Vice President
By: /s/Clarence H. Brown         and Chief Operating Officer        2/21/97
-------------------------------                                     -------
Clarence H. Brown

                   Principal Accounting and Financial Officer


By: /s/Ronald H. Beck            Vice President                     2/21/97
-------------------------------                                     -------
Ronald H. Beck

                         Majority of Board of Directors


By: /s/ Harry A. Trueblood, Jr.   Director                          2/21/97
-------------------------------                                     -------
Harry A. Trueblood, Jr.


By: /s/Clarence H. Brown          Director                          2/21/97
-------------------------------                                     -------
Clarence H. Brown


By: /s/J. Samuel Butler           Director                          2/21/97
-------------------------------                                     -------
J. Samuel Butler


By: /s/William H. Blount, Jr.     Director                          2/21/97
-------------------------------                                     -------
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, 1996


                              COLUMBUS ENERGY CORP.
                           (Exact Name of Registrant)

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