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, 1997                                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, 1998 is $25,374,000.

     Indicate  the  number of  shares  outstanding  of each of the  registrant's
classes of common stock, as of January 31, 1998

                                                       Outstanding at
                  Class                               January 31, 1998
                  -----                               ----------------
     Common Stock, ($.20 par value)                   3,863,907 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 .............................. 5
Item 3.  Legal Proceedings.................................................22
Item 4.  Submission of Matters to a
            Vote of Security Holders.......................................22

                                     PART II

Item 5.  Market for the Registrant's Common Equity
            and Related Stockholder Matters................................23
Item 6.  Selected Financial Data...........................................24
Item 7.  Management's Discussion and Analysis of Financial
            Condition and Results of Operations............................25
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" or "EGY" as used herein  includes
Columbus and its subsidiaries.

     The  Company  currently  has 34  employees.  The current  technical  staff,
including management,  is comprised of four petroleum engineers and one landman.
The  administrative  staff  provides  support  required for  accounting and data
processing  including  disbursement  of  monthly  oil  and gas  revenues,  joint
interest billing functions, and accounts payable.

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

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

                                        3

<PAGE>


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

                                        4

<PAGE>


Item 2.  PROPERTIES

                             Oil and Gas Properties

Reserves

     The estimated  reserve  amounts and future net revenues were  determined by
outside consulting petroleum engineers.  The reserve tables presented below show
total proved  reserves and changes in proved  reserves owned by Columbus for the
three years ended November 30, 1997, 1996 and 1995.

                           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, 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        -
 Revision to previous estimates      (127)   (127)     -       226      226        -
 Sale of reserves                       -       -      -    (2,067)  (2,067)       -
 Extensions, discoveries and other
  additions                           538     538      -     5,066    5,066        -
 Production                          (249)   (249)     -    (3,370)  (3,370)       -
                                   ------- ------- ------ --------- -------- --------

November 30, 1997                   1,805   1,805      -    18,520   18,520        -
                                   ======= ======= ====== ========= ======== ========

Proved developed reserves
(producing and non-producing):
November 30, 1995                   1,384   1,384      -    11,282   11,282        -
                                   ======= ======= ====== ========= ======== ========
November 30, 1996                   1,211   1,211      -    15,758   15,758        -
                                   ======= ======= ====== ========= ======== ========
November 30, 1997                   1,333   1,333      -    16,122   16,122        -
                                   ======= ======= ====== ========= ======== ========
</TABLE>

                                       5

<PAGE>


Proved Developed Producing Reserves

     As of November 30, 1997,  Columbus has  approximately  1,042,000 barrels of
proved developed producing oil and condensate in the United States most of which
are  attributable to primary  recovery  operations.  Producing oil properties in
North  Dakota,  Montana and Texas  account  for over 95% of the  reserves in the
proved developed producing category.

     The gas producing  properties owned by Columbus are located in Texas, North
Dakota,  Louisiana,  Oklahoma and Montana and contain 12.2 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,
Louisiana,  Montana and North Dakota.  Generally,  these are reserves behind the
casing in existing  wells with  recompletion  required  before  commencement  of
production or else are in wells being  completed  and/or  completed but awaiting
pipeline connections at year end.

     Columbus'  non-producing  reserves equal 292,000  barrels of oil, or 16% of
its total proved oil reserves, and 3.9 billion cubic feet of natural gas, or 21%
of its total proved natural gas reserves.

Proved Undeveloped Reserves

     Columbus' proved undeveloped  reserves were  approximately  472,000 barrels
and 2.4 billion  cubic feet of natural  gas.  Almost all of the oil  reserves in
this  category  are in  Montana,  North  Dakota  and  Texas.  All of the  proved
undeveloped  gas reserves are  attributable  to undrilled  locations  offsetting
production  in Webb,  Zapata and Jim Hogg  Counties,  Texas,  Montana  and North
Dakota.

     These reserves are expected to either be developed during 1998 or in future
when oil prices again  stabilize at levels which will yield a satisfactory  rate
of return on investment when developed.

                                       6

<PAGE>


Standardized Measure

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

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

                                                   1997       1996       1995
                                                   ----       ----       ----

Future oil and gas revenues                      $79,381    $98,555     $58,083
Future cost:
  Production cost                                (21,856)   (25,620)    (18,214)
  Development cost                                (5,401)    (4,264)     (4,743)
Future income taxes                              (11,531)   (14,198)     (5,466)
                                                 -------    -------     -------
Future net cash flows                             40,593     54,473      29,660
Discount at 10%                                  (10,422)   (16,313)     (8,268)
                                                 -------    -------     -------
Standardized measure of discounted future net
  cash flows                                     $30,171    $38,160     $21,392
                                                 =======    =======     =======

          CHANGE IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
                FLOWS FROM ESTIMATED PROVED OIL AND GAS RESERVES
                   FOR THE THREE YEARS ENDED NOVEMBER 30, 1997
                             (thousands of dollars)
                                                             United
                                                   Total     States   Canada
                                                   -----     ------   ------

Balance, December 1, 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        -

                                                                     (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, 1997 - (continued)
                             (thousands of dollars)
                                                            United
                                                   Total    States    Canada
                                                   -----    ------    ------

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

Sale of oil and gas net of production costs      (10,708)  (10,708)        -
Net changes in prices and production costs       (10,502)  (10,502)        -
Sale of reserves                                  (1,320)   (1,320)        -
Extensions, discoveries and other additions        9,660     9,660         -
Revisions to previous estimates                     (710)     (710)        -
Previously estimated development costs
  incurred during the period                       1,089     1,089         -
Changes in development costs                         229       229         -
Accretion of discount                              4,653     4,653         -
Other                                             (1,620)   (1,620)        -
Change in future income taxes                      1,240     1,240         -
                                                 --------  -------    ------

Net increase                                      (7,989)   (7,989)        -
                                                 --------  -------    ------

Balance November 30, 1997                        $30,171   $30,171    $    -
                                                 ========  =======    ======

     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, 1997,  1996 and
1995.  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,

                                       8

<PAGE>


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
$37,301,000 in 1997,  $46,530,000 in 1996, and  $24,163,000 in 1995. As required
by SFAS-69,  the future tax  computation  appearing  in the above table does not
consider the Company's annual interest  expenses and general and  administrative
expenses nor future expenditures for intangible drilling costs. Because of these
factors,  the tax provisions are not truly  representative of the expected lower
future  tax  expense to the  Company  so long as it remains an active  operating
company.

     The reserve  and  standardized  measure  tables  prescribed  by the SEC and
presented  above are prepared on the basis of a weighted  average  price for all
properties  as of each year end. At November  30, 1997 the U.S.  crude oil price
(including  natural gas liquids) was $18.36 per barrel and the natural gas price
was $2.50 per  thousand  cubic  feet.  The SEC  requires  that this  computation
utilize those year end prices and expenses which are then held constant,  except
for contractual escalations, over the life of the property.

     The calculation of discounted future cash flows can be materially  affected
by being  compelled  to use only those  prices  that happen to be  effective  on
November 30 each year (Columbus'  fiscal year end) because of price  volatility.
Mandatory  usage of prices  which happen to prevail on a single date can have an
inordinate  influence on year-end  reserves as well as on the resulting  year to
year  change  that a  company  reports  for  discounted  future  net cash  flows
determined  using this  standardized  measure  calculation.  Management has long
advocated using a weighted  average of prices actually  received  throughout the
year to make this  standardized  measure  calculation  less  susceptible  to the
impact of wide monthly  fluctuations in prices which have occurred so frequently
in recent years.  Even using weighted average annual prices still may or may not
be very  indicative of future cash flows because  average prices may vary widely
in future fiscal  years.  This most recent 1997 fiscal year is a good example of
why an average  price would be preferable  in  management's  opinion as year end
prices  for  natural  gas and crude oil were  significantly  different  from the
average annual prices received.

Outside Consultant's Report

     An outside consulting firm, Reed Ferrill & Associates, was retained for the
purpose of preparing a report covering the reserves of the Company's  properties
and a future production  forecast using constant prices as of November 30, 1997,
1996 and 1995.  The  reports  on  the  reserves of the properties located in the

                                       9

<PAGE>


Berry Cox field in Texas  were  prepared  by  Huddleston  & Co.,  Inc.,  another
outside consulting firm. These reports are prepared each year as required by the
Company's bank line of credit.

Production

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

                                               Fiscal Year
                                    ---------------------------------
                                    1997          1996           1995
                                    ----          ----           ----
USA
Oil-barrels                        249,000       246,000        225,000
Gas-Mmcf                             3,370         2,686          2,033

CANADA
Oil-barrels                              -             -         11,000
Gas-Mmcf                                 -             -            446
                                  --------      --------       --------

TOTAL
Oil-barrels                        249,000       246,000        236,000
Gas-Mmcf                             3,370         2,686          2,479

     During the  fiscal  year  1997,  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
1996.  This data was  reported on a gross  operated  basis  inclusive of royalty
interest and,  therefore,  does not compare with Columbus' net reserves reported
for 1996.

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

                                                    Fiscal Year
                                         ---------------------------------
                                         1997          1996           1995
                                         ----          ----           ----

Average sales price per barrel of oil
  USA                                   $19.62        $19.42         $16.75
  Canada (U.S.$)(1)                          -             -          11.61
  Total Company                          19.62         19.42          16.48

Average sales price per Mcf of gas
  USA                                   $ 2.65        $ 2.15         $ 1.71
  Canada (U.S.$)                             -             -           1.09
  Total Company                           2.65          2.15           1.60

Average production cost per
  equivalent barrel
  USA                                   $ 3.83        $ 4.35         $ 4.16
  Canada (U.S.$)                             -             -           2.89
  Total Company                           3.83          4.35           3.99

                                       10

<PAGE>


     Natural gas  converted to oil at the ratio of six Mcf of natural gas to one
barrel of oil.  Production  costs for fiscal  years 1997,  1996 and 1995 include
production taxes.

(1) Natural gas liquids are combined with oil.

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, 1997                   Gross                         Net
-----------------               -------------                 -----------
                                Oil       Gas                 Oil     Gas
                                ---       ---                 ---     ---

Wells - USA                      79       154                  19      19

Acres - USA                        35,118                        9,747

Undeveloped Properties

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

November 30, 1997                 Gross Acres         Net Acres
-----------------                 -----------         ---------

  Louisiana                         40,632              4,086
  Montana                           11,279              7,644
  New Mexico                           840                630
  North Dakota                       2,070                419
  Oklahoma                             320                108
  Texas                              2,591              1,005
                                    ------             ------

Total Undeveloped Properties        57,732             13,892
                                    ======             ======

                                       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,
                     -----------------------------------------------------------
                           1997                  1996                  1995
                     ---------------       ---------------        --------------
                     Gross       Net       Gross       Net        Gross      Net
                     -----       ---       -----       ---        -----      ---

EXPLORATORY
Wells Drilled:
    Oil                2        1.45         -           -           1       .68
    Gas                1         .37         -           -           -         -
    Dry                1         .34         2         .68           -         -
DEVELOPMENT
Wells Drilled:
    Oil                4        1.91         2        1.00           1       .19
    Gas               18        2.71        14        2.60           8       .62
    Dry                3         .65         6        2.95           3      1.16
TOTAL
Wells Drilled:
   Oil                 6        3.36         2        1.00           2       .87
   Gas                19        3.08        14        2.60           8       .62
   Dry                 4         .99         8        3.63           3      1.16
                      --        ----        --        ----          --      ----

     Total            29        7.43        24        7.23          13      2.65
                      ==        ====        ==        ====          ==      ====

                                       12

<PAGE>


Current Activities

     The Company continued a development  program on its properties and expanded
its exploration efforts during fiscal 1997.  Expenditures by the Company reached
a record  $10,088,000 for development and exploration  drilling primarily on its
oil-oriented  properties in the Williston Basin of Montana and natural gas prone
areas  east of Houston  and in Webb and  Zapata  Counties  near  Laredo,  Texas.
However,  the  Austin  Chalk  trend  of  mid-Louisiana  was a new  province  for
Columbus'  exploratory  efforts and unfortunately,  Columbus' share of the first
well exceeded  expected costs by over $1,500,000.  Fortunately,  exploratory and
development  activity in the onshore upper Gulf Coast area continued to be EGY's
most  successful core area from the standpoint of both crude oil and natural gas
reserve and productivity additions.

     A review  of the more  significant  operations  follow  below and have been
segregated into Columbus' primary areas of operations.

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

     As the second most  important  source of lease level cash flow for the past
several  years,  this area remains its most important as a source of operational
income.  The Company serves as operator of in excess of 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 the wells  which it operates  and less than 10% WI
in those wells in which it does not operate.

     At least one drilling rig was utilized continuously  throughout the year to
drill infill and extension  locations that had been  identified by a 3-D seismic
program conducted in 1995 and 1996. This suggested there were numerous new fault
blocks which had not been previously drained by offset wells in one or more Lobo
sands that produce in the area and would require drilling 40 to 50 new locations
in order to exploit those reserves.  A development program was begun during 1996
with 12 wells drilled and was continued throughout 1997 with participation in 18
additional  wells  resulting  in three  (0.65  net) dry holes and 15 (1.74  net)
successful  gas wells.  Two (0.11 net) wells were in  progress at year end which
have since been completed as gas wells.

     In the B.R. Cox field,  Columbus'  working  interest in the five  remaining
wells (two active) on the Ruben Gonzalez  producing  property was sold for a net
of $750,000  effective as of October 1, 1997. No new recompletions  into new gas
zones in wells on the remaining leases were undertaken in 1997 by Columbus as it
awaited  pre-payment  for expected costs on one planned project from the largest
working interest owner who had been very slow paying its prior operating bills.

                                       13

<PAGE>


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

     This  operational  area  continues to be Columbus'  primary source of field
level cash flow and is expected to be reasonably important for a few more years.
During fiscal 1997 one (0.78 net) operated gas well, the  James-Fielder  #1, was
completed in the upthrown  fault block of the West Jackson Sralla Road field and
extended the productive limits of the gas cap by another mile southwest.  It had
a  similar  thickness  to other  Jackson  sand  wells in the field and has since
produced at its state-assigned  allowable of about 1,300 Mcfd. An offset well to
the Fielder and Wiggins units, the Hargrove #2 (0.13 net), is a non-operated gas
well that was  completed  shortly  thereafter  and has been  selling its monthly
allowable also. In addition,  that same operator drilled two other gas cap wells
in the same general area but where Columbus had no interest.  They also extended
the  field's  oil zone  limits  by one mile to the  northeast  of the  Company's
original  Ferguson  #1  discovery  oil well.  As the fiscal  year  closed,  that
extension oil well was being offset by EGY's  67%-owned  Waitkus B #2 (0.67 net)
which has  subsequently  been  completed  as a  successful  flowing  oil well in
January at about 50 BOPD.

     About 20 miles southeast of the Sralla Road field, the Company participated
in an exploratory  test of a 2-D seismic anomaly in search of gas in the Frio 16
sand at 9,000 feet. It was located in a separate  fault block which was adjacent
to the old Anahuac field in Chambers County, Texas that produced several hundred
million barrels of oil from uphole Frio sands over several decades. The Syphrett
Heirs #1 wildcat  resulted in a natural gas  discovery in the Frio 16 sand after
which a  production  unit of 480  acres in size was  agreed  upon.  The  Company
initially owned about 37% WI which was subject to a 25% reduction after it fully
recovered all of its costs of acreage plus drilling and completion costs of this
initial  well.  Excellent  log and gas  shows  in the mud  were  encountered  so
Columbus  assumed  operatorship,  set casing and built a gathering  system and a
pipeline  connection in advance of perforating  only ten feet of a 40-foot gross
interval of F-16 sand.  The well was tested in early July at a daily rate of 4.6
million cubic feet of gas and 90 barrels of condensate  through a 14/64ths choke
with a flowing tubing  pressure of 4,950 psig.  The well has been  restricted to
about 120  million  cubic feet per month but  nevertheless  payout  occurred  in
November thereby reducing Columbus' working interest to 27.75%.

     A similar  interest  is owned in an  additional  600  acres of  prospective
acreage  to the  south  and  east of the  discovery  and  will  require  its own
exploratory  test as it is a separate  fault  block.  A well is  expected  to be
commenced  early in 1998 and may be drilled as deep as 11,000  feet to also test
the underlying Vicksburg formation.  A gas discovery was made in that zone about
two miles east of the Syphrett  fault block while a dry hole has been drilled to

                                       14

<PAGE>


that formation at a location closer to this southeast acreage block. The Frio 15
sand is  considered  prospective  for oil  production at a  structurally  higher
position in the Syphrett well discovery fault block and could also be productive
in the southeast block.

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

     Most of 1997's efforts in this area were related to workovers, short radius
lateral  recompletions,  3-D seismic programs,  plus drilling two new deep wells
because crude oil prices  stayed  consistently  above $17 per barrel  throughout
1996 and 1997.  This was further  supported by futures  swaps but  unfortunately
this practice was not repeated so crude prices  (which have fallen  dramatically
thus far in fiscal 1998) have not been protected by swaps.

     A  3-D  seismic  effort  which  included  the  Southeast  Froid  field  had
previously been conducted over several  sections during the last quarter of 1996
which pinpointed the highest structural location at which to drill a 12,000 foot
replacement  oil well to the Red River  formation  in that  field.  It also gave
indications  that another  structure  existed  west of that field so  additional
leases were  acquired  bringing the total  leaseholds  owned to over 2,000 acres
with a 90% WI. Supplemental 3-D seismic coverage was undertaken in the spring of
1997 to further delineate that potential structure as well as follow up on other
leads including a Tyler sand river bed channel which appeared to meander through
the acreage around those deep Paleozoic highs.

     During 1997's second  quarter,  the 90% WI-owned McCabe #1-X Red River zone
replacement  well was  drilled  and  completed  in 20 feet of  porosity  in that
formation.  It also  encountered  several shows of oil in other horizons  uphole
before production casing was set. After perforating,  the 1-X well was initially
tested on pump at the rate of 86 barrels of oil per day but also produced a like
amount of water  despite the fact this  location was about 10 feet  structurally
higher than the initial  McCabe #1 Red River  discovery  well which it replaced.
The latter well was then  recompleted  as an oil  discovery in the  Winnepegosis
formation  at about  11,100  feet  following  removal of junk which  plugged the
casing at about  9,400  feet.  It  initially  pumped  oil at rates of 116 to 141
barrels per day and water of 51 to 85 barrels  per day.  While each of those two
wells added  materially to third  quarter oil  production,  steadily  increasing
water cuts during the fourth  quarter have reduced  their  contribution  to this
area's daily oil production.

     Following  completion of the second 3-D seismic program in late spring,  an
exploratory  Red River test well  location  was  staked on one of several  small
bumps on a fairly broad  closure of almost a section in size.  Therefore  one or
more potential locations on this broad structure might be exploited now that the
initial test well, the McCabe Farms #1-4 wildcat,  proved to be  productive.  No
drill stem tests were taken in one well while drilling  uphole  formations but a
possible gas zone was  encountered  in a porous zone in the Mission Canyon which

                                       15

<PAGE>


is behind pipe.  Excellent  porosity and oil shows were  encountered  in the Red
River "C"  formation,  casing was set and the well was completed with 21 feet of
perforations  in an  interval  from  11,910 to 11,937.  Through a 17/64ths  inch
choke, the 90% owned McCabe Farms #1-4 flowed oil on initial test at the rate of
135 barrels per day with a water cut of 30% and a flowing tubing pressure of 150
psi. Since this well was not finally completed until early December,  it will be
considered as a fiscal 1998  discovery  although most of the costs were incurred
as part of 1997 fiscal year capital expenditures.

     Immediately following this completion the 69%-owned McCabe #3-2 exploratory
well was drilled to the Tyler  formation  at a depth of 7,200 feet but it proved
to be a dry hole.  While the meandering river bed seismic feature was confirmed,
the cut made by river  had  subsequently  been  filled in by shale and lime with
only a very  limited  amount of sand present as opposed to the 100 foot that had
been expected.

     Two short radius  laterals in  Columbus'  100% owned Lien lease in the west
Mondak  field  were  undertaken  in the  Lien #1 and Lien #3  wells  which  were
marginal Mission Canyon oil producers.  The first effort involved drilling a 921
foot lateral out of the cased hole in the Lien #3 well at a depth of about 8,900
feet.  Unfortunately,  this lateral only  encountered  very limited  fracturing.
After much higher initial oil production rates, the well appears to have settled
around 17 barrels  of oil and 60  barrels of water per day.  The Lien #1 lateral
was next undertaken near the end of the fiscal year. A record horizontal hole of
1,550  feet  was  accomplished  but  again  this  lateral  did not  encounter  a
recognizable  vertical  fracture system.  Thus far the Lien #1 appears not to be
any more  productive  than the Lien #3 despite the longer  lateral  interval but
there  have  been  problems  with the  downhole  pump so this is not yet a final
appraisal of the well's productivity.

Oklahoma - Anadarko Basin
-------------------------

     There were three (1.02 net) development  Morrow sand oil wells completed in
Beaver County,  Oklahoma all of which had excellent  appearance on electric logs
but  only  resulted  in  marginal  oil  producers.  This is  primarily  due to a
combination  of water  cuts in excess of 50% plus  unstable  frac sand which has
plugged  perforations  and  reduced  total fluid  productivity  to levels only a
fraction of the initial swab rates seen following frac treatment.

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

     As  previously  reported  in Form 10-K and  various  quarterly  and interim
special reports,  Columbus has a 12.5% working interest in a three township Area
of  Mutual  Interest  (AMI) in  mid-Louisiana  covering  41,000  gross  acres of
leaseholds  which overlie the geo- pressured,  fractured  Austin Chalk formation
below  15,000 feet in depth.  A good  portion of this block was  assembled  by a
co-venture  group which  included  EGY and 75% was then sold to Belco Oil & Gas.

                                       16

<PAGE>


Terms  included a modest  profit on acreage  plus an after  payout  carried  25%
interest  in a vertical  well to be drilled  from grass roots to 15,000 feet and
included updip and downdip horizontal legs approximately  3,000 to 4,000 feet in
length.  This deal was  subsequently  modified  to permit the use of an existing
mutually-  owned  abandoned  but cased  vertical  hole  from  which to drill two
laterals at no up front costs to  Columbus  or its  co-venturers  to be followed
later by a no cost vertical hole portion to be drilled at a second location. The
Morrow  #23-1H's  operations  began in February  with Belco  choosing to drill a
3,000-foot north updip lateral first. Belco purposely elected to drill laterally
below the base of the Austin  Chalk for  reasons  not clear to, and  despite the
objections of, the co-venture  group and this lateral resulted in a dry hole. As
a consequence,  Belco then drilled a piggyback lateral about 100 feet vertically
higher in the  prospective  pay  section  which  penetrated  numerous  shows and
fractures  throughout this 3,100-foot  horizontal  hole.  Belco was disappointed
with its  production  test from this updip lateral  which over a 66-hour  period
averaged a high water cut of about 70% in addition to varying rates of crude oil
and natural  gas.  The last few hours of test showed a total fluid rate of about
66 barrels per hour of which 21% was oil (over 12 BPH) and 600,000 cubic feet of
natural gas per day.

     Following  that test,  Belco  proposed to move the drilling rig off of that
location without drilling the obligatory  4,000-foot southerly direction downdip
lateral.  There  was  immediate  strong  objections  to  that  proposal  by  the
co-venturers  which was  eventually  settled by Belco  relinquishing  all of its
right,  title and  interest  in the cased  well bore,  the new updip  3,000-foot
lateral and the 1,960-acre  spacing unit to the  co-venturers who thereupon took
over operations.  Numerous  problems were encountered  while attempting to drill
this downdip  lateral not the least of which included  encountering  high bottom
hole  pressures  which  exceeded the maximum  attainable  weighting of the clear
drilling fluid being used and was needed to maintain control over the well. As a
result,  only 1,300 feet of the proposed  4,000-foot  southerly  downdip lateral
could  be  drilled  and  the  well  had  to  be  killed   with  a   conventional
barite-weighted mud system after replacing the clear drilling fluid. This change
created a severe lost circulation  problem so that any further efforts to finish
the entire 4,000-foot lateral were ceased. The co-venturers  generally agreed to
make another attempt to drill a new 4,000-foot downdip lateral from a new casing
window after this 1,300-foot  downdip lateral and the updip  3,100-foot  lateral
had been depleted.

     Subsequently,   numerous  other  problems  were   encountered   during  the
completion  operations.  These included packer  problems,  inability to push the
liner out to the full 1,300 feet  length of the  lateral,  inexperienced  crews,
faulty or improperly  serviced  rental  equipment from major service  companies,
several  poor  engineering   consultant's  decisions,   drilling  rig  equipment
failures,  disputes amongst the co-venturers on procedures,  etc. The final blow
occurred when a roughneck dropped a five inch bolt in the hole which blocked the

                                       17

<PAGE>


top of the packer and  contributed to several  additional days of rig and rental
equipment  expenses.  A  "jerry-rigged"  completion  had to be designed which at
least  permitted  the well to  produce  from the  downdip  lateral  only.  It is
impossible to predict how this will finally  affect  eventual  recovery from the
lateral  but well  cost  overruns  to the  100%  interest  exceeded  $2,000,000.
Fortunately,  Columbus only owns 55% WI of the completed  well and drilling unit
so that these  significant cost overruns did not have to be entirely absorbed by
it.

     Finally,  an initial  potential  of the  1,300-foot  downdip  lateral  only
resulted in the Morrow #23-1H  producing for a 26-hour  clean-up period followed
by a 24-hour  test  period  during  which the well flowed 560 barrels of 41o API
gravity oil, 831 Mcf of natural gas and 1,691  barrels of what  appeared to be a
mixture of formation  salt water and the clear calcium  bromide  drilling  fluid
lost during drilling operations.

     A gas gathering line was laid to a nearby  transmission  system about 7,500
feet to the south and a tank  battery,  separator,  treater,  plus other surface
equipment was  installed.  Also, a shallow water  disposal well has been drilled
and cased.  The well was placed on production  late in November on various small
sizes of surface  chokes  which  yielded  rates which have ranged from 60 to 200
barrels  of oil per day with  water  cuts from 70% to 80% and a  flowing  tubing
pressure of 750 to 950 psi. It is a bit early to forecast  with any accuracy the
amount of oil that will be recovered from this downdip lateral,  but through the
first 35 days to December 31, 1997,  it had  produced  5,156  barrels of oil, an
estimated 26,000 barrels of water and 4,179,000 cubic feet of natural gas. It is
planned to first try to  essentially  deplete the short downdip  lateral  before
attempting  removal of the junk and bridge  plug above the updip  lateral  which
will allow that lateral to be produced.  There is no forecast of when a drilling
rig might be  contracted  for another  attempt at drilling a 4,000-foot  downdip
lateral.

     At least one  additional  well in the AMI is proposed to be promoted at the
second  drillsite  along with a sale of the AMI acreage which remains.  However,
the  co-venturers  have already  determined not to exercise any of the remaining
option  acreage as no profit  would be realized  from  Belco.  Should the Morrow
#23-1H not perform as currently forecasted from the two existing laterals,  then
it is highly unlikely  further  development by drilling one or more new laterals
from  this  Morrow  #23-1H  well bore will  ever be  undertaken  by this  group.
Significant impairment charges for this area and well of $1,475,000 have already
been  recognized  in fiscal  1997 by the  Company  and this has reduced net book
value significantly and will lower depletion charges per barrel for this area in
1998.

                                       18

<PAGE>


     Columbus' own  expenditures  (before  impairment  charges) in this prospect
through  November  30, 1997  totaled  $939,000 for  undeveloped  leaseholds  and
$2,879,000  for  interests  in  producing  wells with most of the  latter  costs
related to the Morrow #23-1H completion.

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

                                       19

<PAGE>


of  importation  of foreign oil and gas; the cost and proximity to pipelines and
other   transportation   facilities;   the   regulation  of  state  and  federal
authorities;   and  the  cost  of  complying   with   applicable   environmental
regulations.

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

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

     Customers.  Sales to 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,  1997,  1996  and  1995,  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

                                       20

<PAGE>


given as to the future capital expenditures which may be required for compliance
with  environmental  regulations  as they may be adopted in future.  The Company
believes,  however, that it is reasonably likely that the trend in environmental
legislation and regulations will continue to be towards stricter standards.  For
instance, legislation previously considered in Congress would amend the Resource
Conservation  and Recovery Act to reclassify  oil and gas  production  wastes as
"hazardous  waste,"  the  effect  of which  would  be to  further  regulate  the
handling, transportation and disposal of such waste. If similar legislation were
to pass, it could have a significant  adverse  impact on the operating  costs of
the Company, as well as the oil and gas industry in general.

Operating Hazards

     The oil 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

                                       21

<PAGE>


short  term it has led to much  more  competitive  markets  and  raised  serious
questions about whether  gathering  systems of interstate  pipelines can be sold
off and totally escape regulation.

Item 3.  LEGAL PROCEEDINGS

     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 1997, no matters were  submitted to a vote of
security holders.

                                       22

<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)
                                               ----            ---

1998:
  December 1, 1997 through
     January 31, 1998                         $ 9.00         $ 8.325

1997:
  First quarter                               $ 8.80         $ 6.90
  Second quarter                                8.40           6.75
  Third quarter                                 8.625          7.50
  Fourth quarter                                9.125          7.75

1996:
  First quarter                               $ 4.60         $ 4.00
  Second quarter                                6.40           4.30
  Third quarter                                 9.10           5.60
  Fourth quarter                                8.70           7.60

1995:
  First quarter                               $ 6.45         $ 5.80
  Second quarter                                6.60           5.90
  Third quarter                                 6.30           5.10
  Fourth quarter                                5.40           4.50

(1)  Price  per share  amounts  have been  adjusted  for the 10% stock  dividend
     distribution  to  shareholders  of  record  on  February  24,  1995 and the
     five-for-four stock split on May 27, 1997.

     As of January 31, 1998 the reported  closing sales price of Columbus common
stock was $8.625 per share.

     As of November 30, 1997, there were  approximately 461 holders of record of
Columbus' common stock and an estimated 1,100 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.

                                       23

<PAGE>


Item 6.  SELECTED FINANCIAL DATA

     The table below sets forth selected historical financial and operating data
for the Company and its consolidated  subsidiaries for the years indicated.  The
historical data for each of the years in the five-year period ended November 30,
1997, were derived from the financial  statements of the Company which have been
audited by Coopers & Lybrand L.L.P.,  independent accountants.  This information
is  not  necessarily  indicative  of  the  Company's  future  performance.   The
information  set forth below should be read in  conjunction  with  "Management's
Discussion and Analysis of Financial  Condition and Results of Operations,"  and
the Company's Financial Statements and notes thereto, included elsewhere herein.
<TABLE>
<CAPTION>

                                                                       Year Ended November 30,
                                           ----------------------------------------------------------------------------
                                           1997            1996               1995(a)          1994                1993
                                           ----            ----               ----             ----                ----
                                                              (in thousands, except per share data)
<S>                                      <C>             <C>                <C>             <C>                <C>
Operating data:
  Revenues                               $ 15,096        $ 11,815           $ 9,400          $13,141             $12,913
  Loss on asset disposition,
    impairment of long-lived
    properties, and abandonment            (2,179)           (165)           (3,055)               -                (258)
  Earnings (loss) before cumulative
    effect of accounting change             2,167           2,098            (1,495)           2,190               2,814
  Cumulative effect of accounting
    change                                      -               -                 -                -                 992
                                          -------        --------          --------          -------             -------
  Net earnings (loss)                       2,167           2,098            (1,495)           2,190               3,806
                                          =======        ========          ========          =======             =======
  Earnings (loss) per share (primary):
    Before cumulative effect of
      accounting change                   $   .55        $    .54          $   (.38)         $   .54             $   .66
    Cumulative effect of
      accounting change                         -               -                 -                -                 .23
                                          -------        --------          --------          -------             -------
    Net earnings (loss)(b)                    .55             .54              (.38)             .54                 .89
                                          =======        ========          ========          =======             =======
    Fully diluted earnings per share          N/A             .51               N/A              N/A                 N/A
                                          =======        ========          ========          =======             =======
  Average number of common
   and common equivalent
   shares outstanding:
   Primary                                  3,908           3,872             3,928            4,087               4,255
                                          =======        ========          ========          =======             =======
   Fully diluted                              N/A           4,086               N/A              N/A                 N/A
                                          =======        ========          ========          =======             =======
  Cash flow data(d):
    Cash from operating activities        $ 8,638        $  5,638          $  3,929          $ 6,194             $ 5,540
    Cash used in investing activities     $(7,294)       $ (6,320)         $   (119)         $(7,194)            $(5,652)
    Cash provided by (used  in)
      financing activities                $  (883)       $    664          $ (4,223)         $   519             $    79
    Cash flow before changes in
      operating assets and liabilities    $ 9,132        $  6,340          $  3,920          $ 6,254             $ 6,468
    Discretionary cash flow               $ 9,672        $  6,658          $  4,096          $ 6,715             $ 6,633
 Balance sheet data:
  Total assets                            $26,135        $ 21,625          $ 18,321          $24,955             $22,938
  Long-term debt, excluding
    current maturities - bank debt        $ 2,200        $  2,200          $  1,600          $ 4,200             $ 3,200
 Stockholders' equity                     $17,958        $ 16,225          $ 13,186          $16,202             $14,400
</TABLE>

                                       24

<PAGE>


(a) Does not include  results of CEC Resources  Ltd.  after its  divestiture  on
February 24, 1995.
(b) Reflects  restated  amounts for 1993 through 1996 after stock  dividends and
stock split.
(c) No cash  dividends have been declared or paid in any period  presented.
(d) See  discussion of cash flows in  "Management's  Discussion  and Analysis of
Financial Condition and Results of Operations".

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

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

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

Liquidity and Capital Resources

     Fiscal  1997 was the best year in the  Company's  history  but this was not
readily  evident.  This  was  primarily  due  to  substantial   exploration  and
impairment charges which significantly reduced net earnings and overshadowed the
boost in  natural  gas  production  to  record  levels.  These  charges  totaled
$2,179,000 which,  after being tax effected,  reduced net earnings by $1,314,000
or $0.34 per share and resulted in earnings of  $2,167,000,  or $0.55 per share,
which were 3% higher  than last  year's net of  $2,098,000,  or $0.54 per share.
Discretionary  cash flow set a record at  $9,672,000 in 1997  surpassing  1996's
prior record of $6,658,000 by 45%. Gross revenues and oil and gas sales both set
historical records also.

     As of the end of  1997,  shareholders'  equity  had  risen  to  $17,958,000
compared to  $16,225,000  at November  30,  1996.  Positive  working  capital of
$722,000 at year end,  combined  with the  Company's  anticipated  cash flow for
1998, should be a sufficient source of capital to develop  undeveloped  reserves
and fund a 1998 exploration  program. As discussed later, a substantial increase
in the  percentage  working  interest  ownership in the  Louisiana  Austin Chalk
exploratory  well required  1997's $7.1 million  capital  budget to be raised by
over $1 million  and after the  overruns  $1.4  million  extra was  spent.  This
required  a short  term draw  from the  Company's  bank  credit  facility  until
additional  monthly cash flow could restore the amount to  $2,200,000  which had
been  outstanding at the beginning of the year. The $10,000,000  credit facility
has been  primarily  targeted  by  management  for  acquisitions  of oil and gas
properties,  but can be used  for any  legal  corporate  purpose  and is  always
available for such expanded operational expenditures.

                                       25

<PAGE>


     Generally accepted  accounting  principles ("GAAP") require cash flows from
operating  activities  to be determined  after giving effect to working  capital
changes.  Accordingly,  GAAP's net cash provided from  operating  activities has
fluctuated  widely from  $3,900,000 to  $8,600,000  during the last three years.
This source of funds, with a backup from the available  borrowing base under the
Company's credit facility, has provided all of the liquidity required to finance
those three  years' oil and gas capital  expenditures  as well as fund  treasury
stock repurchases. However, an important alternative measure of a company's cash
flow (not GAAP but  commonly  used in the  industry)  is one  determined  before
consideration  of either  working  capital  changes or deduction of  exploration
expenses and is generally  known as  Discretionary  Cash Flow  ("DCF").  This is
reported by successful efforts' companies for comparability purposes to the cash
flow results of a majority of independent energy companies who use the full cost
accounting method.  With the latter accounting method, all exploration costs are
capitalized,  and  consequently,  do not adversely  affect either operating cash
flow or net earnings.  Since exploration  expenses can be increased or decreased
at  management's  discretion,  DCF is the most  comparable  to their  full  cost
accounting results.  Columbus' DCF for 1997 was an all time record at $9,672,000
and compares to 1996's  $6,658,000 which itself had been the prior record.  This
45% improvement  directly reflects higher natural gas prices and increased crude
oil and natural gas  production  over 1996.  While DCF is calculated  before any
debt retirement  requirements,  in Columbus' case it does not matter because its
outstanding  bank debt  requires no principal  payments  before  August 1, 1999.
Interest expense on outstanding debt has recently been fairly  insignificant but
is deducted before computing DCF.

     Management  continues  to note its strong  exception  to the  Statement  of
Financial  Accounting  Standards No. 95 which directs that  operating  cash flow
must only be determined  after  consideration  of working  capital  changes.  We
continue to reflect that position in all public filings and reports based on our
belief such a requirement  by GAAP ignores  entirely the  significant  impact on
working capital that the timing of income received for, and expenses incurred on
behalf  of,  third  party  owners in wells has on a company  which  serves as an
operator  of  properties  with  only a  small  working  interest  therein  as in
Columbus' case.

     Nevertheless,  neither  discretionary  cash  flow nor  operating  cash flow
before  working  capital  changes  may be  substituted  for net  income  or cash
available from operations as defined by GAAP. Furthermore, current cash flows do
not  necessarily  indicate that there will be  sufficient  funds for future cash
requirements under any of the definitions of cash flow.

   At the present  time the Company has not hedged  either  crude oil or natural
gas prices similar to the swaps in prior years discussed  below. As a result the

                                       26

<PAGE>


Company's oil and gas revenues are fully exposed to risk of declining prices, as
has occurred  during first quarter 1998 but, in turn, can fully benefit from any
price increases, if any, later in 1998.

     In prior years Columbus has hedged both natural gas and crude oil prices by
selling a "swap". The swap is matched against the calendar monthly average price
on the NYMEX and settled  monthly.  Revenues are decreased when the market price
at settlement  exceeded the contract  swap price or increased  when the contract
swap price exceeded the market price.  The following  table shows the results of
these swaps:

                                                     Increase (decrease) in
                                                      oil and gas revenues
                                                     ----------------------
                      Volume
Description           per mo.       Period         1997       1996        1995
-----------           -------       ------         ----       ----        ----
                   (Mmbtu or bbl)
Natural Gas
-----------

$2.20/Mmbtu            60,000     3/97-10/97    $(86,400)
Futures Contracts      60,000    10/96-11/96                $  42,000
$1.74 & $1.88/Mmbtu   120,000     4/96-11/96                $(560,000)
$2.12/Mmbtu           100,000    12/94- 4/95                            $283,900

Crude Oil
---------

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

   The  Company's  natural  gas and crude oil swaps  were  considered  financial
instruments  with  off-balance  sheet risk  which  were in the normal  course of
business to partially  reduce its exposure to fluctuations in the price of crude
oil and natural gas. Those instruments involved, to varying degrees, elements of
market and credit risk in excess of the amount recognized in the balance sheets.
The Company had no natural gas or crude oil swaps outstanding as of November 30,
1997.

   Columbus had  outstanding  borrowings  of  $2,200,000 as of November 30, 1997
against its line of credit with Norwest Bank Denver,  N.A. which has a borrowing
base of $10,000,000 and is collateralized by oil and gas properties.  At the end
of 1997,  the ratio of bank debt to  shareholders'  equity was 0.12 and to total
assets  was 0.08.  The debt  outstanding  used a LIBOR  option  with an  average
interest rate of 7.2%. Subsequent to year end through January 31, 1998, the debt
was  increased by $600,000 to  $2,800,000  as payments were made for late fiscal
1997 and early fiscal 1998  drilling  activity.  The net increase or decrease in
long-term debt directly affects cash flows from financing activities.  This cash
flow item also  reflects  the  purchase of treasury  stock  discussed  below and
benefits from the proceeds from the exercise of stock options.

   Working  capital at 1997 year end remained  positive at $722,000  compared to
$1,966,000  at November  30,  1996.  This was achieved  despite  record  capital

                                       27

<PAGE>


expenditures  of $9,551,000  for new additions to oil and gas properties as well
as the purchase of 158,014 shares of treasury  stock for  $1,381,000  during the
year.  The change in working  capital  also  reflected a $832,000  reduction  in
current deferred income taxes during the year.

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

                                  Shares
       Fiscal year     --------------------------      Average
       repurchased     As purchased     Restated*       price*
       -----------     ------------     ---------      -------

          1995            243,200        247,730        $7.33
          1996             86,100        107,625        $5.33
          1997            158,000        179,875        $7.61

       *Restated for stock split and stock dividends

   As of November  30, 1997 a total of 143,000  shares  remained out of the most
recent  authorization  which may be  repurchased at a price not to exceed $8.875
per share. As of January 31, 1998,  49,650 of those shares have been acquired at
an average price of $8.60 per share.

   During 1997,  capital  expenditures  were incurred on oil and gas  properties
which totaled $9,551,000. This amount differs from the capital expenditure shown
in the  Consolidated  Statement of Cash Flows which  includes cash payments made
during 1997 for 1996  expenditures  incurred  but not yet paid as of 1996's year
end.  Similarly,  there have been expenditures  accrued in 1997 that will not be
actually  paid until 1998.  These were  primarily  for the expanded  exploratory
program in the Louisiana  Austin Chalk and Montana areas along with  development
drilling and  recompletions  in the South Texas and Gulf Coast  areas.  The cash
flows  from  investing  activities  had an  unusual  benefit  in 1995  from  the
$4,075,000 net proceeds received from the divestiture of Resources.

Results of Operations

     The  Company's  1997 gross  revenues of $15.1 million were 28% above 1996's
and was  attributable  to a record level of natural gas production plus improved
crude oil production generated by the Company's drilling program during 1997. It
should be obvious that 1996 revenues and expenses  were not entirely  comparable
to 1995's because of the aforementioned  divestiture of the Canadian  subsidiary
toward the end of the first quarter of 1995. Total Company revenues did increase
by 26% in 1996  but,  if  Canadian  operations  were  excluded  from  1995,  the
Company's revenues would have increased by 37%. Higher crude oil and natural gas
prices and production were responsible for the improvement.

                                       28

<PAGE>


     Operating  income of $3,766,000 in 1997  represented an improvement of only
5% when compared with 1996 because of the aforementioned exploratory charges and
impairment  provisions or otherwise that increase would have been 59%. Operating
income of $3,589,000 in 1996 reflected  improved revenues but was not comparable
to 1995 which  showed a loss of  $1,811,000,  a direct  result of  deduction  of
impairment  losses which are fully discussed  below.  The operating loss in 1995
also resulted from lower  revenues and higher  depletion  expense  following the
Canadian divestiture.

     Net  earnings  during  1997  set a new high for  U.S.  only  operations  of
$2,167,000 which surpassed 1996's earnings of $2,098,000. Had there not been the
extremely high non-cash  impairment  provisions during 1997, all time record net
earnings  would have  resulted  which  would have  surpassed  those  years which
included Canada's  operations.  Contrarily,  earnings in 1995, even ignoring the
impairment charge, were at their lowest level since 1991.

Impairments

     A non-cash  impairment  loss of  $243,000  for 1997 and  $165,000  for 1996
recognized that some marginal  Oklahoma  development oil wells completed  during
those years effectively  reduced future net revenues for this successful efforts
property pool below undepreciated costs.  Similarly,  the Louisiana Austin Chalk
oil discovery,  although  successful (see full discussion  about this area under
"Recent Activities" in Item 2, Properties), brought into question the likelihood
of future development of certain leaseholds. Where annual renewal rentals either
had already become due or would become due before a reasonable  production  test
period  for the  Morrow  #23-1H is  achieved  and/or a new test  well  promoted,
management  chose to write them off as impaired.  Also  included  were  numerous
small  leaseholds  where the  possibility of easily putting  together a unit was
rather  remote.  This  added  charge of  $251,000  brought  the  total  non-cash
impairment provision made during the third quarter to $494,000.

     Late in the fourth  quarter,  the Morrow #23-1H did commence  production at
rates well below the initial tests so year-end proved  reserves  attributable to
the horizontal  legs were reduced.  This resulted in carrying costs in excess of
the fair value and in an impairment  charge of $1,140,000 and $84,000 related to
Louisiana  leaseholds.  Undeveloped  leaseholds in general were also impaired in
the amount of $200,000 based upon management's  opinion further  development may
not be completed prior to some lease  expirations.  Two oil wells in Oklahoma in
progress  at the end of the third  quarter  failed to  respond  to  attempts  to
eliminate  shifting  frac  sands from  plugging  perforations  so an  additional
impairment of $260,000 was provided.

     The  Company  elected to adopt  early  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" as of the beginning of the
fourth quarter of 1995.

                                       29

<PAGE>


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 had to provide for  impairment of oil and gas properties
based on  expected  prices and year end proved  reserves  both of which would be
significantly  reduced.  Four  areas in Texas,  Oklahoma,  New  Mexico and North
Dakota showed that impairment losses were greater than previously anticipated so
it was deemed prudent to elect early adoption.  Accordingly,  a non-cash loss of
$3,055,000 ($2,260,000 after tax) was recognized as of September 1, 1995.

   Prior to September 1, 1995, a valuation provision had only been 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 had been necessary prior to
adopting SFAS-121 because total capitalized costs in the U.S. were far less than
discounted  future net revenues.  Interestingly,  had Columbus followed the full
cost  method  no  impairments  of oil  and gas  property  costs  (excluding  the
impairment of  undeveloped  leases) would have been necessary as the total value
of proved  reserves of the Company have  comfortably  exceeded such  capitalized
full cost method costs.

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
                             ------------    ---------------     --------------
1997 vs. 1996 (All U.S.)
   Gas                           23 %              25 %                53 %
   Oil                            1 %               1 %                 3 %

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 %

     Natural gas  revenues  increased  53% when  compared to 1996 as a result of
higher volumes and prices.  Average prices for natural gas increased 23% in 1997
compared with last year due  to  strong  demand and a fairly tight supply of gas

                                       30

<PAGE>


in excess of storage injection  requirements.  Gas revenues in 1997 were reduced
by $86,400 ($.03 per Mcf) and 1996's revenues were reduced by $518,000 ($.19 per
Mcf) from swaps of natural  gas.  Sales  volumes  improved by 25% over 1996 as a
result of numerous gas wells being  completed  and connected in Texas during the
past year.

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

     Columbus'  1997 average  sales volumes of natural gas of 9,283 Mcfd and oil
and liquids  production  of 682 barrels per day equates to daily  production  of
2,229 barrels of oil equivalent  (BOE).  This surpassed the previous  record for
U.S. daily production of 2,200 BOE achieved during the third quarter of 1994 and
the  1997  fourth  quarter  production  averaged  2,354  BOE per  day.  The next
challenge is to not only  maintain but to increase  that level of  production by
adding  substantial new reserves from an expanded  exploratory  budget hopefully
without  expensive  failures or high cost successes such as the Morrow #23-1H in
Louisiana.

     After the 25%  increase  in  natural  gas  production  during  1997 with an
increase of only 1% in oil  production,  the Company now produces  approximately
70% of its volumes from natural gas. This may be very fortuitous as the price of
crude oil in early 1998 rapidly declined.

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

     Oil  revenues  in the U.S.  for 1996 were up 28% from 1995 as a result of a
16% increase in the average price received and 9% higher  volumes.  Oil revenues
and average  prices for 1996 were reduced by $256,000  ($1.04 per barrel) due to
hedging  activity.  The Company had no oil hedges in 1995.  Crude oil production
improved because of two new Jackson sand oil well completions in the Sralla Road

                                       31

<PAGE>


field  plus a third  discovery  (78% WI) gas  condensate  well  almost  one mile
southwest which commenced  production in November 1996. These increases overcame
normal production declines elsewhere.

     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  deductions more than offset  additional well  connections in
Texas and  Oklahoma,  Average  prices for natural gas  decreased 11% compared to
1994 but did begin 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 revival of an 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 putting the 1996 oil swap
in place which  afforded  some  protection  from previous  drastic  downturns in
prices which each time halted drilling plans before anything could get underway.

     U.S. oil prices have fluctuated for several years with the same wide swings
experienced in world crude oil price.  In 1995 crude oil prices  declined during
mid-year months but recovered by year-end so that the average annual prices were
actually  higher than 1994.  By the spring of 1996 crude oil prices rose quickly
to above $20 per barrel, declined briefly, then again rose rapidly to almost $23
per  barrel  by year  end.  During  1997  crude oil  prices  have been  steadily
softening and have declined  each quarter which trend  accelerated  in the first
quarter of fiscal 1998.

     Fluctuations  of oil and gas revenues and operations in Canada which appear
in the table are  consistent  with the spin-off of  Resources in February  1995,
i.e. 1996 vs. 1995 revenues decreased 100% which reflects the fact 1995 included
the last quarter of Canadian activity.

     Lease  operating  expenses  for 1997 were 6% lower than 1996  despite  more
wells in  operation  because  the prior  year had  several  expensive  workovers
performed and  production  equipment was replaced on several older wells.  Lease
operating  expenses in the U.S.  increased  23% in 1996 over  1995's  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 1997  were down to $2.27  compared  to
$2.80 in 1996 and $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

                                       32

<PAGE>


compared  to $1.93 for 1994.  Operating  costs in the U.S.  as a  percentage  of
revenues  decreased  to 13% in 1997  versus 19% in 1996 due to  increasing  unit
prices and compared with 22% in 1995.

     Production and property taxes  approximated  9% of revenues in 1997 and 10%
of revenues in 1996 and 1995. These vary based on Texas' percentage share of the
total  production  where  oil tax  rates  are  lower  than  gas tax  rates.  The
relationship  of taxes and  revenue is not always  directly  proportional  since
several  of the local  jurisdiction's  property  taxes are  based  upon  reserve
evaluations as opposed to revenues  received or production rates for a given tax
period.

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.

     During 1997 operating and management  services profit was $349,000 compared
to a  $210,000  profit  for 1996 as the number of  operated  wells and  drilling
activity increased.

     Prior to the  Company's  divestiture  of  Resources  in 1995,  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, although 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 in each of the
last three years.  Until divested in 1995,  Canadian  operations had contributed
far greater  operating  margins than the U.S. but U.S. revenues in 1995 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 in that year.

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  increased  slightly  in 1997 to $147,000 as a result of higher
short-term   interest  rates   achieved  and  despite  a  decreased   amount  of
investments.  Interest  income  decreased in 1996 to $125,000  when  compared to
$160,000  in 1995,  reflecting  a  decreased  amount  of  investments  and lower
short-term interest rates.

                                       33

<PAGE>


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.

     The Company's general and administrative  expenses in 1997 were much higher
than the prior  year due to salary  increases  in May 1997 for  officers  and in
November  1996  for  employees  and  to  incentive  bonuses.   The  latter  were
discretionary and were actually based on the Company's  performance in 1996 with
total  bonuses of $220,000  ($70,000  non-cash) in 1997 compared to $83,000 (all
non-cash)  in 1996. A major source of this  increase  was also  attributable  to
legal  and  accounting  expenses  which  had been  accrued  in  connection  with
preparation of a registration  statement for a proposed  offering of convertible
preferred  shares which was  withdrawn  because of the rapid  paydown of debt in
latter 1996 from accelerating cash flow.

     During 1997 the Company upgraded its computer  software to a new release of
a major  software  vendor  that is  compliant  with the year  2000 and  expensed
$16,000 which is included in general and  administrative  expenses.  The Company
does not  expect  to incur  any  other  significant  amounts  in the  future  in
connection with the year 2000 problem.

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

     Reimbursement  for services provided by Columbus officers and employees for
managing Resources is expected to decrease in 1998 assuming that  Canadian-based
management takes over following an expected business  combination that Resources
is currently aggressively seeking.  Columbus' general and administrative expense
will rise commensurately when Resources' merger occurs since no staff reductions
are  contemplated  when this occurs.  Reimbursement  of $255,000 was realized in
1997  compared to $296,000 in 1996 and  $281,000 for all of fiscal year 1995 for
providing 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. 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 in each of the pools or fields. Depreciation and amortization of office
equipment and computer software is also included in the total charge.

     Total charges for depletion expense for oil and gas properties increased in
1997 over 1996 due to increased production and added development expenditures in
the  intervening  period.  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 depletion expense for oil and
gas  properties   increased  by  a  greater  percentage  than  the  increase  in
production. Contributing to the disproportionately higher depletion expense were
much  lower  gas and  crude  oil  prices  during  1995,  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 1997, the depletion and depreciation rate for the Company was $3.91 per
barrel of oil equivalent  ("BOE")  compared to $3.86 per BOE for fiscal 1996 and
$3.83  per BOE  equivalent  in  1995.  However,  had the  benefit  of the  lower
depletion  costs of Canadian gas  properties  not been included for one quarter,
the higher  cost U.S.  additions  would have raised the 1995 charge to $4.21 per
BOE.

     Effective  October 1, 1997 the Company sold its interests in seven wells in
the Berry Cox field in Texas for total proceeds of $750,000.  These wells were a
part of a  larger  pool  of  properties  in the  Laredo  area  for  purposes  of
calculating  depletion so those sale  proceeds were credited to the costs of the
successful  efforts pool and no book gain or loss was recognized.  The reduction
in proved reserves  connected with the sale could cause a small increase in that
pool's depletion rate in future periods.

Exploration Expense

   In  general,   the  exploration   expense  category   includes  the  cost  of
Company-wide  efforts  to acquire  and  explore  new  prospective  areas.  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  expensing  the  costs  of

                                       35

<PAGE>


unsuccessful  exploratory wells.  Other exploratory  charges such as 2-D and 3-D
seismic and geological costs must be immediately  expensed regardless of whether
a prospect is ultimately proved to be successful.

     Exploration charges for 1997 were up dramatically to $540,000 from $318,000
in 1996. These included $224,000 of 3-D seismic costs incurred in the S.E. Froid
area in Montana which located new exploratory well sites, $73,000 incurred for a
non-commercial  exploratory  oil well along with  ongoing  exploration  efforts.
Subsequent  to fiscal year end, a dry  exploratory  well was drilled in the S.E.
Froid  area  in  Montana  so  approximately  $190,000  will  be  recorded  as an
exploration expense during first quarter 1998.

     During 1996 two Oklahoma exploratory wells drilled proved non- economic 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.  All  exploration  expenses  reduce reported GAAP cash flow
from  operations  even though they are  discretionary  expenses;  however,  such
charges  are added back for  purposes  of  determining  DCF which  makes it more
comparable to the cash flow results reported by full cost accounting companies.

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 1997, 1996 and 1995 was 7.1%, 7.2%, and 7.9%, respectively.

                                       36

<PAGE>


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  has
limited the  utilization of net operating  loss  carryforwards.  Furthermore,  a
quasi-reorganization  occurred on December 1, 1987 which  requires that benefits
from net operating loss  carryforwards or any other tax credits that arose prior
to the  quasi-reorganization  be credited to additional  paid-in  capital rather
than to income.  Only post  quasi-reorganization  tax  benefits  realized can be
credited to income.

   As a result of available  net  operating  loss  carryforwards,  the Company's
Federal income tax obligations have been limited to "alternative minimum tax" so
that the  Company  has had a  current  Federal  tax  payable  of less than 2% of
pre-tax  earnings.  In 1997, the Company has a net operating  loss  carryforward
from 1995 and operating loss  carryforwards  remaining from periods prior to the
first Section 382 ownership  change.  Utilization  of those latter  benefits are
limited to $904,000 per year so that the Company's current Federal tax provision
and  liability  may increase in 1998 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.

   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 was added to additional paid-in capital.

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

                                       37

<PAGE>


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 would be affected by any recurrence of such economic  conditions.  Inflation
in general has had a minimal effect on the Company.

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

Item 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  1998  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 1998 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 1998  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 1997:

        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, 1997 and 1996                                            44

   Consolidated Statements of Operations for the
   years ended November 30, 1997, 1996 and 1995                          46

   Consolidated Statements of Stockholders'
   Equity for the years ended
   November 30, 1997, 1996 and 1995                                      48

   Consolidated Statements of Cash Flows for the
   years ended November 30, 1997, 1996 and 1995                          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, 1997 and 1996, and the related
consolidated  statements of operations,  stockholders' equity and cash flows for
each  of  the  three  years  in  the  period  ended  November  30,  1997.  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, 1997 and 1996, and the
consolidated  results of their  operations  and their cash flows for each of the
three years in the period ended November 30, 1997, 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, 1998

                                       43

<PAGE>


                              COLUMBUS ENERGY CORP.

                           CONSOLIDATED BALANCE SHEETS

                                     ASSETS

                                              November 30,
                                       -------------------------
                                       1997                 1996
                                       ----                 ----
                                             (in thousands)


Current assets:
  Cash and cash equivalents            $ 1,857           $ 1,396
  Accounts receivable:
    Joint interest partners              1,932               889
    Oil and gas sales                    2,054             1,544
    Allowance for doubtful accounts       (116)             (116)
  Deferred income taxes (Note 5)             -               631
  Inventory of oil field equipment,
    at lower of average cost or market     102               115
  Other                                     82                77
                                       -------           -------

   Total current assets                  5,911             4,536
                                       -------           -------

Property and equipment:
  Oil and gas assets, successful
    efforts method (Notes 3 and 4)      33,803            28,031
  Other property and equipment           2,053             2,001
                                       -------           -------

                                        35,856            30,032

  Less:  Accumulated depreciation,
    depletion, amortization and
    valuation allowance
    (Notes 2 and 3)                    (15,632)          (12,943)
                                      --------           -------

    Net property and equipment          20,224            17,089
                                      --------           -------

                                      $ 26,135           $21,625
                                      ========           =======

                                                                (continued)

                                       44

<PAGE>


                              COLUMBUS ENERGY CORP.

                    CONSOLIDATED BALANCE SHEETS - (continued)

                      LIABILITIES AND STOCKHOLDERS' EQUITY

                                                 November 30,
                                             -------------------
                                             1997           1996
                                             ----           ----
                                                (in thousands)

Current liabilities:
  Accounts payable                          $  3,023    $  1,292
  Undistributed oil and gas
    production receipts                          393          54
  Accrued production and property taxes          551         555
  Prepayments from joint interest owners         565         258
  Accrued expenses                               377         348
  Income taxes payable (Note 5)                   42          33
  Deferred income taxes (Note 5)                 201           -
  Other                                           37          30
                                             -------      ------

    Total current liabilities                  5,189       2,570
                                             -------      ------

Long-term bank debt (Note 4)                   2,200       2,200
Deferred income taxes (Note 5)                   788         630

Commitments and contingent liabilities (Note 8)

Stockholders' equity:
  Preferred stock authorized 5,000,000
    shares, no par value; none issued             -           -
  Common stock authorized 20,000,000 shares
    of $.20 par value; 4,492,068 shares
    issued in 1997 and 3,499,915 in 1996
    (outstanding 3,883,557 in 1997 and
    3,155,346 in 1996) (Notes 1 and 7)           898         700
  Additional paid-in capital                  18,124      17,361
  Retained earnings                            2,887         720
                                             -------     -------
                                              21,909      18,781
Less:
    Treasury stock, at cost (Note 7)
      608,511 shares in 1997 and
      344,569 shares in 1996                  (3,951)     (2,556)
                                             -------     -------
        Total stockholders' equity            17,958      16,225
                                             -------     -------
                                             $26,135     $21,625
                                             =======     =======


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

                                       45

<PAGE>


                              COLUMBUS ENERGY CORP.

                      CONSOLIDATED STATEMENTS OF OPERATIONS


                                           Year Ended November 30,
                                     -----------------------------------
                                     1997           1996            1995
                                     ----           ----            ----
                                    (in thousands, except per share data)
Revenues:
  Oil and gas sales                 $13,815      $10,572         $ 7,902
  Operating and management
    services                          1,176        1,087           1,338
  Gain (loss) on sale of asset          (60)          31               -
  Interest income and other             165          125             160
                                    -------      -------         -------
      Total revenues                 15,096       11,815           9,400
                                    -------      -------         -------

Costs and expenses:
  Lease operating expenses            1,849        1,965           1,811
  Property and production taxes       1,258        1,051             780
  Operating and management
    services                            827          877           1,017
  General and administrative          1,372          999           1,278
  Depreciation, depletion and
   amortization                       3,295        2,835           2,757
  Impairments                         2,179          165           3,055
  Exploration expense                   540          318             245
  Retirement and separation               -            -             141
  Litigation expense                     10           16             127
                                    -------      -------         -------

     Total costs and expenses        11,330        8,226          11,211
                                    -------      -------         -------

     Operating income (loss)          3,766        3,589          (1,811)
                                    -------      -------         -------

Other (income) expense:
  Interest                              174          260             185
  Other                                  (4)           2              26
                                    -------      -------         -------
                                        170          262             211
                                    -------      -------         -------
      Earnings (loss) before
         income taxes                 3,596        3,327          (2,022)
  Provision (benefit) for income
     taxes (Note 5)                   1,429        1,229            (527)
                                    -------      -------         -------

         Net earnings (loss)        $ 2,167      $ 2,098         $(1,495)
                                    =======      =======         =======


                                                           (continued)

                                       46

<PAGE>


                              COLUMBUS ENERGY CORP.

               CONSOLIDATED STATEMENTS OF OPERATIONS - (continued)

                                         Year Ended November 30,
                                  -----------------------------------
                                  1997           1996            1995
                                  ----           ----            ----
                                 (in thousands, except per share data)

Earnings (loss) per share:
  Primary                       $   .55         $   .54        $  (.38)
                                =======         =======        =======
  Fully diluted                     N/A         $   .51            N/A
                                                =======

Average number of common and
  common equivalent shares
  outstanding:
    Primary                       3,908           3,872           3,928
                                =======         =======         =======
    Fully diluted                   N/A           4,086             N/A
                                                =======

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, 1997

<TABLE>
<CAPTION>
                                                                                          Cumulative
                                                                            Retained       Foreign
                                 Common Stock              Additional       Earnings       Currency            Treasury Stock
                            -----------------------         Paid-In       (Accumulated    Translation        ------------------
                            Shares           Amount         Capital          Deficit)     Adjustments        Shares      Amount
                            ------           ------        ----------     ------------    -----------        ------      ------
                                                           (dollar amounts in thousands)

<S>                      <C>               <C>             <C>            <C>             <C>              <C>        <C>
Balances,
  December 1, 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
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)
                         ----------         -------         --------         -------          ----         --------      -------

                                                                                                                      (continued)
</TABLE>

                                       48

<PAGE>

                             COLUMBUS ENERGY CORP.
                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                  For The Three Years Ended November 30, 1997

<TABLE>
<CAPTION>
                                                                                          Cumulative
                                                                            Retained       Foreign
                                 Common Stock              Additional       Earnings       Currency            Treasury Stock
                            -----------------------         Paid-In       (Accumulated    Translation        ------------------
                            Shares           Amount         Capital          Deficit)     Adjustments        Shares      Amount
                            ------           ------        ----------     ------------    -----------        ------      ------
                                                           (dollar amounts in thousands)
<S>                      <C>               <C>             <C>            <C>             <C>              <C>        <C>
Exercise of employee
  stock options              99,233         $    20         $    548         $    -         $    -           13,333      $  (131)
Purchase of shares                -               -                -              -              -          158,014       (1,381)
Shares issued for Stock
  Purchase Plan               6,996               1               62              -              -           (1,762)          12
Shares issued for
  Incentive Bonus Plan
  and directors' fees             -               -               (7)             -              -          (13,451)         105
Shares issued under
  five-for-four stock
  split                     885,924             177             (178)             -              -          107,808            -
Tax benefit of disqualifying
  disposition of incentive
  stock options                   -               -               76              -              -                -            -
Income tax benefit of
  loss carryforwards
  arising prior to
  quasi-reorganization            -               -              262              -              -                -            -
Net earnings                      -               -                -          2,167              -                -            -
                         ----------         -------         --------         -------          ----         --------      -------

Balances,
  November 30, 1997       4,492,068         $   898          $18,124        $ 2,887          $  -0-         608,511      $(3,951)
                         ==========         =======         ========         ======           ====         ========      =======


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

</TABLE>

                                       49

<PAGE>


                                 COLUMBUS ENERGY CORP.

                         CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>

                                                               Year Ended November 30,
                                                          ----------------------------------
                                                          1997           1996           1995
                                                          ----           ----           ----
                                                                    (in thousands)

<S>                                                    <C>           <C>             <C>
Net earnings (loss)                                    $ 2,167       $ 2,098         $(1,495)
Adjustments to reconcile net earnings (loss) to
  net cash provided by operating activities:
    Depreciation, depletion, and
     amortization                                        3,295         2,835           2,757
    Impairments and loss on asset dispositions           2,179           165           3,055
    Deferred income tax provision                        1,328         1,148            (576)
    Exploration expense, noncash portion                     -             -              69
    Other                                                  163            94             110

Changes in operating assets and liabilities:
    Accounts receivable                                 (1,554)         (358)            411
    Other current assets                                    21           (38)             40
    Accounts payable                                       352           (22)            147
    Undistributed oil and gas production receipts          339          (294)            (89)
    Accrued production and property taxes                   (4)          (80)            (35)
    Prepayments from joint interest owners                 307            69            (264)
    Income taxes payable (receivable)                        9            41             (32)
    Other current liabilities                               36           (20)           (169)
                                                       -------        -------        -------

    Net cash provided by operating activities            8,638          5,638          3,929
                                                       -------        -------        -------
Cash flows from investing activities:
    Proceeds from sale of assets                         1,005           606              34
    Proceeds from sale of Resources
      common stock, net of cash                              -             -           4,075
    Additions to oil and gas properties                 (8,172)       (6,863)         (4,144)
    Additions to other assets                             (127)          (63)            (84)
                                                       -------        ------         -------
    Net cash used in investing activities               (7,294)       (6,320)           (119)
                                                       -------        ------         -------
Cash flows from financing activities:
    Proceeds from long-term debt                         3,000         3,400           2,090
    Reduction in long-term debt                         (3,000)       (2,800)         (4,690)
    Proceeds from exercise of stock options                498           643             209
    Purchase of treasury stock                          (1,381)         (579)         (1,830)
    Other                                                    -             -              (2)
                                                       -------        ------         -------
    Net cash provided by (used in)
      financing activities                                (883)           664          (4,223)
                                                       -------        -------         -------
    Effect of exchange rate on cash                          -              -               8
                                                       -------        -------         -------
Net decrease in cash and cash equivalents                  461            (18)           (405)
Cash and cash equivalents at beginning of year           1,396          1,414           1,819
                                                       -------         ------         -------
Cash and cash equivalents at end of year               $ 1,857        $ 1,396         $ 1,414
                                                       =======        =======         =======

Supplemental disclosure of cash flow information:
    Cash paid during the period for:
      Interest                                         $   182        $   250         $   214
                                                       =======        =======         =======
      Income taxes (net of refunds)                    $    91        $    41         $    82
                                                       =======        =======         =======

Supplemental disclosure of non-cash investing and financing activities:
    Non-cash compensation expense
      related to common stock                          $    98        $   114         $   162
                                                       =======        =======         =======
    Oil and gas property additions                     $     -        $   253         $   185
                                                       =======        =======         =======
    Use of loss carryforwards credited to
      additional paid-in-capital                       $   262        $   409         $     -
                                                       =======        =======         =======
    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.

     Financial Instruments and Concentrations of Credit Risk
     -------------------------------------------------------

     The Company  maintains  demand  deposit  accounts  with  separate  banks in
Denver,  Colorado. The Company also invests cash in the highest rated commercial
paper of large U.S.  companies,  with  maturities  not over 30 days,  which have
minimal risk of loss. At November 30, 1997 and 1996 the Company had  investments
in  commercial  paper of $900,000  and  $1,000,000,  respectively.  The carrying
amount of long-term  debt  approximates  fair value because the interest rate on
this instrument changes with market interest rates.

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

     Oil and Gas Properties
     ----------------------

     The Company  follows the successful  efforts  method of  accounting.  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,

                                       52

<PAGE>


                              COLUMBUS ENERGY CORP.

          NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


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.

     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.

                                       53

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     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,
1997 and 1996.

     Other Property and Equipment
     ----------------------------

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

     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 is computed using the weighted  average number of common
shares outstanding. Stock options are included as common stock equivalents, when
dilutive,  using the treasury  stock method.  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

                                       54

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


fully diluted shares.  For 1995 and 1997 such common stock  equivalents were not
dilutive.  Historical  amounts  have been  adjusted  for the 10% stock  dividend
distribution in 1995 and the five-for-four stock split in 1997.

     In March 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 128, "Earnings Per Share," effective
for interim and annual  periods  ending after  December  15, 1997.  SFAS No. 128
replaces the calculation of Primary Earnings per Share with a calculation called
Basic  Earnings per Share and replaces  Fully Diluted  Earnings per Share with a
calculation  called Diluted  Earnings per Share.  The following  table shows the
impact that adoption of SFAS No. 128, as of December 1, 1994,  would have had on
the Company's reported earnings per share.

                                          For the year ended November 30,
                                          -------------------------------
                                           1997         1996        1995
                                           ----         ----        ----

Primary earnings (loss) per
  share (as reported)                     $0.55        $0.54      $(0.38)
Basic earnings (loss) per
  share (proforma)                         0.55         0.55       (0.38)

Fully diluted earnings (loss)
  per share (as reported)                   N/A         0.51         N/A
Diluted earnings (loss) per
  share (proforma)                         0.54         0.54       (0.38)

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 is using the
alternative pro forma disclosures as provided.

New Accounting Pronouncement
----------------------------

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

                                       55

<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,
                                                 ----------------------
                                                  1997            1996
                                                 -------        -------

       Proved properties                         $33,074        $27,156
       Unproved properties                           729            875
                                                 -------        -------

                                                  33,803         28,031

       Less accumulated depreciation,
         depletion, amortization and
         valuation allowance                     (14,175)       (11,519)
                                                 -------        -------

       Total net properties                      $19,628        $16,512
                                                 =======        =======


              COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,
                    EXPLORATION AND DEVELOPMENT ACTIVITIES
                                (in thousands)

                                        Year Ended November 30,
                           ----------------------------------------------
                            1997        1996               1995
                           ------      ------     -----------------------
                           United      United             United
                           States      States     Total   States   Canada

Property acquisition
  costs:
       Proved              $    -      $3,025     $1,443  $1,443   $    -
     Unproved                  508        976         85      85        -
Exploration costs              540        318        245     196       49
Development costs            9,043      3,115      2,843   2,771       72
                            ------     ------     ------  ------   ------

Total costs incurred       $10,091     $7,434     $4,616  $4,495   $  121
                           =======     ======     ======  ======   ======

                                       56

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


                RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES
                                (in thousands)

                                      Year Ended November 30,
                           ----------------------------------------------
                            1997        1996               1995
                           ------      ------     -----------------------
                           United      United             United
                           States      States     Total   States   Canada
                           ------      ------     -----   ------   ------

Sales                      $13,815    $10,572    $7,902   $7,269   $  633
Production (lifting)
  costs (a)                  3,107      3,016     2,591    2,343      248
Exploration expenses           540        318       245      196       49
Impairment of long-
  lived assets               2,179        165     3,055    3,055        -
Depreciation
  depletion and
  amortization (b)           3,194      2,703     2,543    2,410      133
                           -------    -------    ------   ------   ------
                             4,795      4,370      (532)    (735)     203

Imputed income tax           1,905      1,614      (138)    (209)      71
                           -------    -------    ------   ------   ------
Results of operations
  from producing
  activities
  (excluding overhead
  and interest
  incurred)                $ 2,890    $ 2,756    $ (394)  $ (526)  $  132
                           =======    =======    ======   ======   ======

(a)  Production costs include lease operating expenses,  production and property
     taxes

(b)  Amortization expense per equivalent barrel of production: 1997 - $3.91 1996
     - $3.86 1995 - $3.83

     For the years ended  November 30, 1997,  1996 and 1995, 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.

                     1997                 1996                1995
              ------------------   ------------------   ------------------
              Amount   % Revenue   Amount   % Revenue   Amount   % Revenue
              ------   ---------   ------   ---------   ------   ---------

Customer A    $2,956     21.4%     $3,142      29.7%   $ 2,027      29.7%
Customer B     6,536     47.3       5,513      52.2      2,635      36.2
Customer C     1,395     10.1       1,212      11.5      1,046      14.4

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

                                       57

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(4)  LONG-TERM DEBT

     The Company has a Credit Agreement  ("Agreement") with Norwest Bank Denver,
N.A.  ("Bank")  having a  borrowing  base of  $10,000,000,  which is  subject to
semi-annual  redetermination  for any increase or decrease.  On 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, 1997 outstanding borrowings on the revolving line of credit
were  $2,200,000 and the unused  borrowing base  available was  $7,800,000.  The
$2,200,000 bears interest at LIBOR rate of 5.68% 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,:


                         1998              $     -
                         1999                  183
                         2000                  550
                         2001                  550
                         2002 and after        917
                                           -------
                               Total       $ 2,200

                                       58

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(5)    INCOME TAXES

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

                                           1997        1996        1995
                                           ----        ----        ----

       Current:
          Federal                        $   13       $    2      $   -
          Foreign (Canada)                    -            -         29
          State                              88           79         20
                                         ------       ------       ----
                                            101           81         49
                                         ------       ------       ----

       Deferred:
          Federal                           942          288       (612)
          Use of loss carryforwards         347          848          -
          Foreign (Canada)                    -            -         44
         State                               39           12         (8)
                                         ------       ------      -----
                                          1,328        1,148       (576)
                                         ------       ------      -----

       Total income tax
          (benefit) expense             $ 1,429       $1,229      $(527)
                                        =======       ======      =====

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

                                     1997            1996          1995
                                     ----            ----          ----

       U.S.                         $ 3,596        $ 3,327        $(2,231)
       Canada                             -              -            209
                                     ------         ------        -------

       Total                        $ 3,596        $ 3,327        $(2,022)
                                    =======        =======        =======

       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
                                     ----------------------------
                                     1997        1996        1995
                                     ----        ----        ----

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

       Effective rate                 40 %        37 %       (26)%
                                     ===         ===         ===

                                       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.
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.   The  remaining   post-1987  net  operating  loss
carryforwards were fully utilized during fiscal 1996.

     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 1997, certain U.S. tax assets (shown in the table below) were
utilized and the valuation allowance was decreased during the year by $26,000.

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

                                                        Current Year
                                                ---------------------------
                                      Dec. 1,   Stockholders'                   Nov. 30,
                                       1996        Equity        Operations      1997
                                      -------   -------------    ----------     --------

<S>                                   <C>       <C>              <C>            <C>
Deferred tax assets:
  Pre-1987 loss carryforwards         $1,361      $    -           $ (308)      $1,053
  Post-1987 loss carryforwards           596           -              (56)         540
  Percentage depletion
    carryforwards                      1,130           -              174        1,304
  State income tax loss
    carryforwards                         88           -               17          105
  Other                                  308           -               19          327
                                      ------       -----            -----       ------
            Total                      3,483           -             (154)       3,329
    Valuation allowance (long-term)   (1,469)        262(a)          (236)      (1,443)
                                      ------       -----            -----       ------
      Deferred tax assets              2,014         262             (390)       1,886
                                      ------       -----            -----       ------
  Tax benefit of disqualifying
    disposition of incentive
    stock options                          -          76(a)           (76)           -
                                      ------       -----           ------       ------

Deferred tax liabilities-
  Depreciation, depletion and
    amortization and other            (2,013)           -            (862)      (2,875)
                                      ------        -----          ------       ------

    Net tax asset (liability)         $    1        $ 338         $(1,328)      $ (989)
                                      ======        =====         =======       ======
</TABLE>

------------------------
(a)  Credited to additional paid-in capital.

     The Company has approximate net operating loss carryforwards (in thousands)
available at November 30, 1997 as follows:

                                                Net
            Expiration Year               Operating loss
            ---------------               --------------

                  1999                          $1,808
                  2000                             903
                  2001                             387
                  2010                           1,589
                                               -------
                                               $ 4,687
                                               =======

                                       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  $5,848,000 as of November 30, 1997.  The
Company also has percentage  depletion  carryforwards of $2,908,000 which do not
expire.   State  income  tax  operating  loss   carryforwards  of  approximately
$1,730,000 are available at November 30, 1997.

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

                                                1997         1996        1995
                                                ----         ----        ----

Earnings (loss) before income taxes
  per financial statements                    $ 3,596      $ 3,327     $(2,022)

Differences between income
  before taxes for financial
  statement purposes and
  taxable income:
  Intangible drilling costs
    deductible for taxes                       (6,158)      (1,520)     (3,125)
  Excess of book over tax
    depletion, depreciation
    and amortization                            1,683          754         607
  Disqualifying disposition of
    incentive stock options                      (200)        (273)        (88)
  Impairment expense                            1,843          165       3,055
  Lease abandonments                              (13)        (117)       (258)
  Dividend of rights of Resources                   -            -         234
  Other                                           153          (95)         72
                                              -------      -------      ------
Federal taxable income                        $   904      $ 2,241     $(1,525)
                                              =======      =======     =======

     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, 1997 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  $1,443,000  as of November  30,  1997,  $736,000
relates  to  pre-quasi-reorganization  tax assets  and the  balance of  $707,000
relates to post-quasi-  reorganization tax assets. In future periods,  reduction
of the  pre-quasi-reorganization  portion  of the  valuation  allowance  will be
credited   to   additional   paid-in   capital  and   reduction   of  the  post-
quasi-reorganization  portion of the  valuation  allowance  will be  credited to
income.

                                       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  $3,329,000.  This level of income can be achieved  using the value of proved
reserves reported in the year end November 30, 1997 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 1997 the valuation  allowance
was decreased by $262,000  related to pre-quasi-  reorganization  tax assets and
increased by $236,000 for  post-quasi-  reorganization  assets.  During 1996 the
valuation     allowance    was     decreased    by    $409,000     related    to
pre-quasi-reorganization    tax   assets   and   increased   by   $141,000   for
post-quasi-reorganization  tax assets.  During 1995 the valuation  allowance was
increased $96,000.

(6)  RELATED PARTY TRANSACTIONS

     Reimbursement  is made by Resources  to Columbus  for services  provided by
Columbus  officers and employees for managing  Resources and reduces general and
administrative  expense.  This  reimbursement  totaled $255,000 for fiscal 1997,
$296,000 for fiscal 1996 and $213,000 for the nine months in 1995  following the
divestiture of Resources.

(7)  CAPITAL STOCK

     The shares and prices of stock  options in this note have been  adjusted to
reflect the five-for-four  stock split in 1997 and 10% stock dividends in fiscal
1995 and 1994.

     Columbus has several  stock option plans with  outstanding  options for the
benefit of all  employees.  Under the 1985 Plan,  options for 75,344 shares were
exercisable at November 30, 1997. No additional options may be granted under the
1985 Plan. At November 30, 1996, 91,789 shares were exercisable.

     Under the 1995 Plan, as of November 30, 1997, 41,555 option shares remained
available for granting, and options for 300,490 shares were exercisable. Options
may be exercised  for a period  determined  at grant date but not to exceed five
years.  Options are vested in three equal annual amounts from grant date or each
part may be exercised immediately for each  twelve-month period the optionholder

                                       63

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


has been an employee of the Company.  At November 30, 1996,  176,305 shares were
available for granting, and options for 225,543 shares were exercisable.

     The Board of Directors  has granted  non-qualified  stock  options of which
there were  117,025  exercisable  at November  30, 1997 and 115,245  shares were
exercisable at November 30, 1996.

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

                                        1997          1996
                                        ----          ----
                                (thousands except per share amounts)

     Net Income
          As reported                  $2,167        $2,098
          Pro forma                    $1,968        $1,897

     Earnings per share (primary)
          As reported                  $  .55        $  .54
          Pro forma                    $  .50        $  .49

                                       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 is a summary of stock option  transactions  for the three years
ended November 30, 1997:

                                1997               1996              1995
                          ----------------   ----------------  ----------------
                                  Weighted-          Weighted-         Weighted-
                                   Average            Average           Average
                                  Exercise           Exercise          Exercise
                           Shares   Price     Shares   Price    Shares   Price
                          -------- -------   -------- -------  -------- -------
                                          (options in thousands)
Shares under option at
  beginning of year          445    $6.22       353    $5.77      421    $6.21
Granted                      174     8.12       307     5.80      228     5.48
Exercised                   (110)    5.17      (202)    4.86      (50)    3.55
Surrendered or expired        (3)    7.30       (13)    5.38     (246)    6.60
                            ----               ----              ----

Shares under option at
  end of year                506     7.09       445     6.22      353     5.77
                            ====               ====              ====
Options exercisable
  at November 30             493     7.01       433     6.22      324     5.75
Shares available for
  future grant at end
  of year                     42                176               275
Weighted-average fair value
  of options granted during
  the year                          $2.24              $1.32               N/A

     The  following  table  summarizes  information  about the  Company's  stock
options outstanding at November 30, 1997:

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

$5.15 - $5.90        88         1.3         $ 5.55          87         $ 5.56
$6.00 - $6.77       183         2.6           6.36         183           6.36
$7.80 - $8.63       235         3.5           8.22         223           8.22
                    ---         ---         ------         ---         ------

$5.15 - $8.63       506         2.8           7.09         493          7.06
                    ===         ===         ======         ===         ======

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

                                            1997           1996
                                            ----           ----

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

                                       65

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     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's 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 years 1997 and 1996 total matching  contributions
of $15,000 and $13,000, respectively, were accrued as an expense by the Company.
The price of the issued shares equals the average  trading price during each six
month purchase period or the ending price, whichever is less. During fiscal 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 1997 a total of 8,758 shares were  purchased  (1,762 shares from treasury
stock  for the  Company  contribution  of 25%) at an  average  cost of $8.58 per
share.

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

                                Shares
       Fiscal year     -------------------------     Average
       repurchased     As purchased     Restated*     price*
       -----------     -------------------------     -------

          1995            243,200        247,730      $7.33
          1996             86,100        107,625      $5.33
          1997            158,000        179,875      $7.61

       *Restated for stock split and stock dividends

                                       66

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


     As of November 30, 1997 a total of 143,000 shares  remained out of the most
recent  authorization  which may be  repurchased at a price not to exceed $8.875
per share. As of January 31, 1998,  49,650 of those shares have been acquired at
an average price of $8.60 per share.

(8)  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 1997,
1996 and 1995 was approximately $161,000,  $133,000 and $126,000,  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, 1997
are $135,000 for fiscal year 1998.

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

     The  separation  pay policy of Columbus  includes a  retirement  provision.
Officers and employees may retire at age 65, or older,  and at the discretion of
the Board of Directors be paid retirement  compensation based upon the length of
service  and  last  year's  average  compensation.  Such  compensation  has been
approved for three  individuals who have reached age 65. As of November 30, 1997
the accrued  liability  totals  $201,000  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 $23,000 and
$16,000 in 1997 and 1996, respectively.

                                       67

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     In prior years Columbus has hedged both natural gas and crude oil prices by
selling a "swap". The swap is matched against the calendar monthly average price
on the NYMEX and settled  monthly.  Revenues are decreased when the market price
at settlement  exceeded the contract  swap price or increased  when the contract
swap price exceeded the market price.  The following  table shows the results of
these swaps:

                                                    Increase (decrease) in
                                                     oil and gas revenues
                     Volume                         ----------------------
Description          per mo.       Period        1997         1996        1995
-----------          -------       ------        ----         ----        ----
                 (Mmbtu or bbl)
Natural Gas
-----------

$2.20/Mmbtu           60,000     3/97-10/97    $(86,400)
Futures Contracts     60,000    10/96-11/96               $  42,000
$1.74 & $1.88/Mmbtu  120,000     4/96-11/96               $(560,000)
$2.12/Mmbtu          100,000    12/94- 4/95                             $283,900

Crude Oil
---------

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

     The  Company's  natural gas and crude oil swaps were  considered  financial
instruments  with  off-balance  sheet risk  which  were in the normal  course of
business to partially  reduce its exposure to fluctuations in the price of crude
oil and natural gas. Those instruments involved, to varying degrees, elements of
market and credit risk in excess of the amount recognized in the balance sheets.
The Company had no natural gas or crude oil swaps outstanding as of November 30,
1997.

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

     The litigation expenses in 1995 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.

                                       68

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(9)  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  $95,000,
$90,000, and $101,000 in the fiscal years 1997, 1996 and 1995, respectively.

                                       69

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


(10)  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>

                                                               1997           1996          1995
                                                               ----           ----          ----
                                                                        (in thousands)

<S>                                                           <C>             <C>         <C>
Operating revenues from unaffiliated services (a):
     Oil and gas                                              $13,788         $10,617     $ 7,927
     Services                                                   1,308           1,198       1,473
                                                              -------         -------     -------

          Total                                               $15,096         $11,815     $ 9,400
                                                              =======         =======     =======

Depreciation, depletion and amortization (b):
     Oil and gas                                              $ 3,238         $ 2,763     $ 2,638
     Services                                                      57              72         119
                                                              -------         -------     -------

          Total                                               $ 3,295         $ 2,835     $ 2,757
                                                              =======         =======     =======

Operating income (loss):
     Oil and gas                                              $ 4,714(c)      $ 4,339(c)  $  (870)(c)
     Services                                                     424             249         337
     General corporate expenses                                (1,372)           (999)     (1,278)
                                                              -------         -------     -------

          Total operating income                                3,766           3,589      (1,811)
Interest expense and other                                        170             262         211
                                                              -------         -------     -------

          Earnings before income taxes                        $ 3,596         $ 3,327     $(2,022)
                                                              =======         =======     =======

Identifiable assets (b):
     Oil and gas                                              $21,917         $18,910     $15,238
     Services                                                   4,218           2,715       3,083
     Other corporate                                                -               -           -
                                                              -------         -------     -------

          Total                                               $26,135         $21,625     $18,321
                                                              =======         =======     =======

Additions to property and equipment:
     Oil and gas                                              $ 9,671         $ 7,167     $ 4,423
     Services                                                       7              12          31
                                                              -------         -------     -------

          Total                                               $ 9,678         $ 7,179     $ 4,454
                                                              =======         =======     =======
</TABLE>

(a)  Approximately  $105,000 of  inter-segment  revenues are included in service
revenues  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 $2,179,000 in 1997,  $165,000 in 1996
and $3,055,000 in 1995.

                                       70

<PAGE>


                             COLUMBUS ENERGY CORP.

         NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (continued)


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

     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
                                                              ----
                                                         (in thousands)
Operating revenues from unaffiliated services (a):
    Oil and gas                                             $   639
    Services                                                    150
                                                            -------
          Total                                             $   789
                                                            =======

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

Operating income:
    Oil and gas                                             $   225
    Services                                                    106
    General corporate expenses                                 (121)
                                                            -------
          Total operating income                                210

Interest expense and other                                        1
                                                            =======

    Earnings before income taxes                            $   209
                                                            =======

Identifiable assets:
    Oil and gas                                             $     -
    Services                                                      -
                                                            -------
          Total                                             $     -
                                                            =======

Additions to property and equipment:
    Oil and gas                                             $    45
    Services                                                     27
                                                            -------
          Total                                             $    72
                                                            =======

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

                                       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 19, 1998        By: /s/ Harry A. Trueblood, Jr.
        -----------------------             ------------------------------
                                            Harry A. Trueblood, Jr.
                                            Chairman of the Board

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

       Signature                     Title                            Date
       ---------                     -----                            ----

                          Principal Executive Officer

                                 Chairman of the Board,
                                 President, and Chief
/s/ Harry A. Trueblood, Jr.      Executive Officer                    2/19/98
    -------------------------
    Harry A. Trueblood, Jr.

                            Chief Operating Officer

                                 Executive Vice President
/s/ Clarence H. Brown            and Chief Operating Officer          2/19/98
    -------------------------
    Clarence H. Brown

                   Principal Accounting and Financial Officer


/s/ Ronald H. Beck               Vice President                       2/19/98
    -------------------------
    Ronald H. Beck

                         Majority of Board of Directors


/s/ Harry A. Trueblood, Jr.      Director                             2/19/98
    -------------------------
    Harry A. Trueblood, Jr.


/s/ Clarence H. Brown            Director                             2/19/98
    -------------------------
    Clarence H. Brown


/s/ J. Samuel Butler             Director                             2/19/98
    -------------------------
    J. Samuel Butler


/s/ William H. Blount, Jr.       Director                             2/19/98
    -------------------------
    William H. Blount, Jr.

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