UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended May 31, 1997
----------------
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
----------------- ----------------
Commission File Number: 1-9872
----------------
COLUMBUS ENERGY CORP.
(Exact name of registrant as specified in its charter)
Colorado 84-0891713
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification
No.)
1660 Lincoln St., Denver, CO 80264
(Address of principal executive offices) (Zip Code)
(303) 861-5252
(Registrant's telephone number, including area code)
Not Applicable
(Former name, former address and former fiscal year, if
changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Class Outstanding at July 11, 1997
- --------------------------- ----------------------------
Common stock, $.20 par value 3,903,628
<PAGE>
COLUMBUS ENERGY CORP.
INDEX
PAGE
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets -
May 31, 1997 and
November 30, 1996 3
Consolidated Statements of Income -
Three Months and Six Months
Ended May 31, 1997 and 1996 5
Consolidated Statement of
Stockholders' Equity -
Six Months Ended May 31, 1997 6
Consolidated Statements of Cash Flows -
Six Months Ended May 31, 1997
and 1996 7
Notes to the Financial Statements 9
Item 2. Management's Discussion and Analysis
of Financial Condition and
Results of Operations 17
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 27
Items 2-3. Not Applicable
Item 4. Submission of Matters to a Vote
of Security Holders 27
Item 5. Not applicable
Item 6. Exhibits and Reports
on Form 8-K 27
Signatures 28
<PAGE>
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
May 31, November 30,
1997 1996
------- -----------
(unaudited)
(in thousands)
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 1,186 $ 1,396
Accounts receivable:
Joint interest partners 1,919 889
Oil and gas sales 1,428 1,544
Less allowance for doubtful accounts (116) (116)
Deferred income taxes (Note 3) 304 631
Inventory of oil field equipment,
at lower of average cost or market 85 115
Other 82 77
------- -------
Total current assets 4,888 4,536
------- -------
Property and equipment:
Oil and gas assets, successful efforts
method (Note 2) 30,944 28,031
Other property and equipment 2,015 2,001
------- -------
32,959 30,032
Less: Accumulated depreciation,
depletion and amortization
and valuation allowance (14,379) (12,943)
------- -------
Net property and equipment 18,580 17,089
------- -------
$ 23,468 $ 21,625
======== ========
</TABLE>
(continued)
3
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED BALANCE SHEETS - (continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
<TABLE>
<CAPTION>
May 31, November 30,
1997 1996
------- -----------
(unaudited)
(in thousands)
<S> <C> <C>
Current liabilities:
Accounts payable $ 2,507 $ 1,292
Undistributed oil and gas
production receipts 33 54
Accrued production and property taxes 385 555
Prepayments from joint interest owners 180 258
Accrued expenses 330 348
Income taxes payable (Note 3) 109 33
Other 34 30
------ ------
Total current liabilities 3,578 2,570
------ ------
Long-term bank debt (Note 2) 1,500 2,200
Deferred income taxes (Note 3) 1,160 630
Commitments and contingent liabilities (Note 2)
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; shares issued
4,431,524 in 1997, and 3,499,915 in 1996
(outstanding 3,892,484 in 1997 and
3,155,346 in 1996) 886 700
Additional paid-in capital 17,442 17,361
Retained earnings, since
December 1, 1987 2,284 720
------ ------
20,612 18,781
Less: Treasury stock at cost
539,040 shares in 1997 and
344,569 shares in 1996 (3,382) (2,556)
------ ------
Total stockholders' equity 17,230 16,225
------ ------
$ 23,468 $ 21,625
====== ======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
4
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Six Months Ended Three Months Ended
---------------- ------------------
1997 1996 1997 1996
---- ---- ---- ----
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales $ 6,644 $ 5,231 $ 2,879 $ 2,639
Operating and management
services 577 558 301 270
Interest and other income 72 235 35 31
-------- -------- -------- --------
Total revenues 7,293 6,024 3,215 2,940
-------- -------- -------- --------
Costs and expenses:
Lease operating expenses 951 975 433 410
Property and production taxes 625 504 304 239
Operating and management
services 388 417 191 215
General and administrative 867 541 529 330
Depreciation, depletion and
amortization 1,490 1,373 737 698
Impairment of long-lived
assets - 165 - -
Exploration expense 380 144 318 111
Litigation (Note 4) 11 10 4 1
-------- -------- -------- -------
Total costs and expenses 4,712 4,129 2,516 2,004
-------- -------- -------- -------
Operating income 2,581 1,895 699 936
-------- -------- -------- -------
Other expenses (income):
Interest 65 142 30 71
Other (6) 7 (9) 6
------- -------- -------- -------
59 149 21 77
------- -------- -------- -------
Earnings before
income taxes 2,522 1,746 678 859
Provision for income taxes
(Note 3) 958 663 257 326
------- -------- ------- -------
Net earnings $ 1,564 $ 1,083 $ 421 $ 533
======= ======== ======= =======
Earnings per share (Note 1) $ .40 $ .28 $ .11 $ .14
======= ======== ======== =======
Average number of common
shares outstanding (Note 1) 3,932 3,810 3,901 3,799
======= ======== ======= =======
<FN>
Note 1 - 1996 shares and earnings per share restated for May 27, 1997
five-for-four stock split.
</FN>
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
5
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
For the Six Months Ended May 31, 1997
(Unaudited)
<TABLE>
<CAPTION>
Common Stock Additional Treasury Stock
------------ Paid-in Retained --------------
Shares Amount Capital Earnings Shares Amount
------ ------ ------- -------- ------ ------
(dollar amounts in thousands)
<S> <C> <C> <C> <C> <C> <C>
Balances,
December 1, 1996 3,499,915 $ 700 $ 17,361 $ 720 344,569 $ (2,556)
Exercise of employee
stock options 42,772 8 236 -- 13,333 (131)
Purchase of shares -- -- -- -- 87,514 (806)
Shares issued for Stock
Purchase Plan 2,913 1 29 -- (733) 5
Shares issued for
Incentive Bonus Plan
and directors' fees -- -- (7) -- (13,451) 106
Shares issued under
five-for-four stock
split (Note 1) 885,924 177 (177) -- 107,808 --
Net earnings -- -- -- 1,564 -- --
--------- --------- --------- --------- --------- --------
Balances,
May 31, 1997 4,431,524 $ 886 $ 17,442 $ 2,284 539,040 $ (3,382)
========= ========= ========= ========= ========= ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
6
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Six Months Ended
---------------------------
May 31, 1997 May 31, 1996
------------ ------------
(in thousands)
<S> <C> <C>
Net earnings $ 1,564 $ 1,083
Adjustments to reconcile net earnings
to net cash provided by operating
activities:
Depreciation, depletion, and
amortization 1,490 1,373
Impairment of assets -- 165
Deferred income tax provision 857 594
Gain on asset sale -- (175)
Other 62 69
Net change in operating assets and
liabilities 160 (658)
------- -------
Net cash provided by
operating activities 4,133 2,451
------- -------
Cash flows from investing activities:
Additions to oil and gas properties (2,913) (4,038)
Additions to other assets (67) (5)
Proceeds from sale of assets -- 336
------- -------
Net cash used in
investing activities (2,980) (3,707)
------- -------
Cash flows from financing activities:
Proceeds from long-term debt 500 2,700
Reduction in long-term debt (1,200) (1,000)
Proceeds from issuance of
common stock 143 26
Purchase of treasury stock (806) (332)
------- -------
Net cash provided by (used in)
financing activities (1,363) 1,394
Net increase (decrease) in cash and
cash equivalents (210) 138
Cash and cash equivalents at
beginning of period 1,396 1,414
------- -------
Cash and cash equivalents at
end of period $ 1,186 $ 1,552
======= =======
(continued)
</TABLE>
7
<PAGE>
COLUMBUS ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Six Months Ended
---------------------------
May 31, 1997 May 31, 1996
------------ ------------
(in thousands)
<S> <C> <C>
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest $ 78 $ 163
======= =======
Income taxes $ 25 $ 16
======= =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
8
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
(Unaudited)
(1) BASIS OF PRESENTATION
The accompanying consolidated financial statements include the accounts of
Columbus Energy Corp. ("Columbus") and its wholly-owned subsidiary, Columbus Gas
Services, Inc.("CGSI"). All significant intercompany balances have been
eliminated in consolidation. The term "Company" as used herein includes Columbus
and its subsidiary.
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 financial statements contain all adjustments
(consisting only of normal recurring accruals) which, in the opinion of
management, are necessary to present fairly the financial position of the
Company as of May 31, 1997 and November 30, 1996, the results of its operations
and cash flows for the three and six months ended May 31, 1997 and 1996. The
results of operations for such interim periods are not necessarily indicative of
results to be expected for the full year.
For purposes of the statements 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.
The Company uses crude oil and natural gas swaps to manage price exposure.
Realized gains and losses on the swaps are recognized in oil and gas sales as
settlement occurs.
Earnings per share are computed using the weighted average number of common
shares outstanding. Stock options are included as common stock equivalents, when
dilutive, using the treasury stock method. Common stock equivalents include
shares issuable upon assumed exercise of dilutive stock options using the
average price for primary shares and the period end price, if higher, for fully
diluted shares. For 1997 and 1996 such common stock equivalents were not
dilutive. Historical average number of shares outstanding and earnings per share
have been adjusted for the five-for-four stock split distributed June 16, 1997
to shareholders of record as of May 27, 1997.
The Company will adopt Financial Accounting Standards No. 128, "Earnings
per Share," ("SFAS-128") effective for the 1998 fiscal year. Earlier application
is not permitted. The purpose of SFAS- 128 is to simplify the computation of
earnings per share. The new standard replaces the calculation of "primary
earnings per share" with a calculation called "basic earnings per share" and
9
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
redefines "diluted earnings per share". The Company does not expect the
application of SFAS-128 to have a material impact on its EPS calculation.
Oil and Gas Properties
The Company follows the successful efforts method of account ing. 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 for
exploratory operations are expensed. Dry hole costs associated with developing
proved fields are capitalized. Expenditures for additions, betterments and
renewals are capitalized. Exploratory geological and geophysical costs are
expensed when incurred.
Upon sale or retirement of proved properties, the cost thereof and the
accumulated depreciation or depletion are removed from the accounts and any gain
or loss is credited or charged to income if significant. Abandonment,
restoration, and 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. Unproved properties are assessed periodically to
determine whether they are impaired. When impairment occurs, a loss is
recognized by providing a valuation allowance. When leases for unproved
properties expire, any remaining cost is expensed.
An impairment loss on oil and gas properties is reported as a component of
income from continuing operations. The Company recognizes an impairment loss
when the carrying value exceeds the expected undiscounted future net cash flows
of each property pool at which time the property pool is written down to the
fair value. Fair value is estimated to be a discounted present value of expected
future net cash flows with appropriate risk consideration.
The Company follows the entitlements method of accounting for gas balancing
of gas production. The Company's gas imbalances are immaterial at November 30,
1996 and May 31, 1997.
10
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
Other Property and Equipment
Depreciation of other assets are provided on the straight line method over
their estimated useful lives. 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.
Accounting for Stock-Based Compensation
The Financial Accounting Standards Board issued Statement No. 123 on the
"Accounting for Stock-Based Compensation". This statement prescribes the
accounting and reporting standards for stock-based employee compensation plans
and is effective for the Company's 1997 fiscal year. The Company has determined
it will use the alternative pro forma disclosures as permitted in the Standard.
(2) LONG-TERM DEBT
The Company has a credit agreement with Norwest Bank Denver, N.A. that was
amended and restated on October 23, 1996. The credit is collateralized by a
first lien on oil and gas properties.
As requested by the Company, the borrowing base was increased to a limit of
$10,000,000 from $7,000,000 effective May 13, 1997, without regard to the
maximum allowable amount that would be set by the bank during its semi-annual
redetermination. A commitment fee of .25% is payable for any unused portion of
the credit which is the difference between the borrowing base and the
outstanding borrowings.
(3) INCOME TAXES
The Company files a consolidated income tax return with CGSI and has
executed a tax allocation agreement which provides for an allocation and payment
of income taxes based upon each company's separate tax liability calculation.
Consolidated income taxes are payable only when taxable income exceeds available
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
11
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
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. Approximately $160,000 of these restricted post-1987
net operating loss carryforwards are available for fiscal 1997 or subsequent
years.
The Company uses the asset and liability method to account for income
taxes. Under this method, deferred tax liabilities and assets are determined
based on the temporary differences between financial statement and tax basis of
assets and liabilities using enacted rates in effect for the year in which the
differences are expected to reverse. Deferred tax assets (net of a valuation
allowance) primarily result from net operating loss carryforwards, percentage
depletion and certain accrued but unpaid employee benefits. Deferred tax
liabilities result from the recognition of depreciation, depletion and
amortization in different periods for financial reporting and tax purposes.
Because of the Company's previous 1987 quasi-reorganization, the Company is
required to report the effect of its net deferred tax asset arising prior to
December 1, 1987 as an increase in stockholders' equity rather than as an
increase to net earnings.
12
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
(Unaudited)
The provision for income taxes consists of the following (in thousands):
<TABLE>
<CAPTION>
Six Months Ended May 31,
------------------------
1997 1996
---- ----
<S> <C> <C>
Current:
Federal $ 25 $ 35
State 76 34
---- ----
101 69
---- ----
Deferred:
Federal 546 176
Use of loss carryforwards 311 418
---- ----
857 594
---- ----
Total income tax expense $958 $663
==== ====
</TABLE>
The total tax provision has resulted in effective tax rates which differ
from the statutory Federal income tax rates. The reasons for these differences
are:
<TABLE>
<CAPTION>
Percent of Pretax Earnings
--------------------------
Six Months Ended May 31,
--------------------------
1997 1996
---- ----
<S> <C> <C>
U.S. Statutory rate 34% 34%
State income taxes 3 2
Other 1 2
---- ----
38% 38%
==== ====
</TABLE>
13
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
During the six months of fiscal 1997, certain tax assets (shown in the
table below) were utilized. The tax effect of significant temporary differences
representing deferred tax assets and liabilities and changes were estimated as
follows (in thousands):
<TABLE>
<CAPTION>
Current Year
---------------------------------------
Dec. 1, May 31,
1996 Operations 1997
------- ---------- -------
<S> <C> <C> <C>
Deferred tax assets:
Pre-1987 loss carryforwards $ 1,361 $ -- $ 1,361
Post-1987 loss carryforwards 596 (298) 298
Percentage depletion
carryforwards 1,130 -- 1,130
State income tax loss
carryforwards 88 (13) 75
Other 308 (16) 292
------- ------- -------
Total 3,483 (327) 3,156
Valuation allowance (1,469) -- (1,469)
------- ------- -------
Deferred tax assets 2,014 (327) 1,687
------- ------- -------
Deferred tax liabilities-
Depreciation, depletion and
amortization and other (2,013) (530) (2,543)
------- ------- -------
Net tax asset (liability) $ 1 $ (857) $ (856)
======= ======= =======
</TABLE>
The Company has net operating loss carryforwards (in thousands) available
at November 30, 1996 as follows:
Net
Expiration Year Operating loss
--------------- --------------
1999 $2,710
2000 907
2001 386
2003 45
2004 115
2010 1,593
------
$5,756
======
For Alternative Minimum Tax purposes the Company had net operating loss
carryforwards of approximately $6,900,000 as of November 30, 1996. The Company
also has percentage depletion carryforwards of $2,974,000 which do not expire.
State income tax operating loss carryforwards of $1,450,000 were available at
November 30, 1996.
14
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(Unaudited)
(4) LITIGATION
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.
(5) CONTINGENCY
The Company entered into a natural gas swap by selling 60,000 Mmbtu per
month for the period from March 1997 through October 1997 at $2.20 per Mmbtu.
This volume represents approximately 23% of Columbus' second quarter gas
production.
Columbus also entered into a crude oil swap by selling a strip of 10,000
barrels per month for the twelve month period from November 1996 through October
1997 at an average daily price of $21.17 per barrel. This amount represents
approximately 48% of Columbus' May 1997 crude oil production. The difference
between the hedge price and the actual daily closing price on the New York
Mercantile Exchange ("NYMEX") is settled monthly.
The Company's natural gas and crude oil swaps are considered financial
instruments with off-balance sheet risk which were in the normal course of
business to reduce its exposure to fluctuations in the price of crude oil and
natural gas. Those instruments involve, to varying degrees, elements of market
and credit risk in excess of the amount recognized in the balance sheets. The
Company had natural gas and crude oil swaps outstanding subsequent to May 31,
1997 as follows:
Notional Market Value as of
Value 5/31/97
------- ------------------
Natural gas
(6/97-10/97) $ 660,000 $ 640,000
Crude oil
(6/97-10/97) 1,059,000 1,079,000
15
<PAGE>
COLUMBUS ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS - (continued)
(6) RELATED PARTY TRANSACTIONS
CEC Resources Ltd. ("Resources") was a wholly-owned subsidiary of Columbus
prior to its divestiture on February 24, 1995. 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 $131,000 and $150,000 for the six months of 1997 and 1996,
respectively.
16
<PAGE>
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following summarizes the Company's financial condition and results of
operations and should be read in conjunction with the consolidated financial
statements and related notes.
Liquidity and Capital Resources
Second quarter results were quite respectable, and one of the better
quarters in history, but were no match for the record results achieved during
the first quarter of 1997. This was mostly due to decreases in oil and gas
prices although some support was received from the Company's favorable swap
positions of crude oil and natural gas. Nevertheless, 1997's second quarter did
surpass 1996's like quarter in discretionary cash flow ("DCF") and sales but
expensed 3-D seismic costs and increased incentive bonuses reduced net earnings
to $421,000, or $0.11 per share, which was less than last year's net of
$533,000, or $0.14 per share. The six months results in 1997 surpassed 1996's
easily with net earnings of $1,564,000, or $0.40 per share, which were 44% above
the $1,083,000, or $0.28 per share, reported in 1996. As of the end of the
second quarter 1997, shareholders' equity was $17,230,000 compared to
$16,225,000 at November 30, 1996. Substantial positive working capital of
$1,310,000 on May 31, 1997 plus the Company's forecasted future cash flow for
the balance of the year should be more than a sufficient source of capital to
finish the $7.1 million program budgeted for developing undeveloped reserves
plus fund a significantly expanded exploratory program. As discussed later, an
increased percentage working interest in the Louisiana Austin Chalk exploratory
well will up total 1997 capital expenditures by a minimum of $1 million. This
will require a draw of funds from the Company's bank credit facility until
increased monthly cash flow during the balance of 1997 overcomes this
accelerated rate of drilling expenditures. While the $10,000,000 bank borrowing
base of the credit facility has been primarily targeted by management for
acquisitions of oil and gas properties, this credit can always be used for any
legal corporate purpose and is always available for such expanded budgeted
expenditures.
Generally accepted accounting principles ("GAAP") require cash flows from
operating activities to be deducted after effect of working capital changes.
Accordingly, GAAP net cash provided by operating activities was $4,133,000 for
the first six months of 1997 compared to $2,451,000 during 1996's period.
Management believes that a very important alternative measure of a company's
cash flow (not GAAP but commonly used in the industry) is one determined before
considering working capital changes and without deducting exploration expenses.
This is generally known as DCF and is used by successful efforts companies for
comparability purposes with results from the full cost accounting method used by
a majority of independent energy companies. Using the latter, all exploration
costs are capitalized and therefore do not adversely affect operating cash flow
17
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
or net earnings. Since exploration costs can be increased or decreased at
management's discretion, DCF is usually more comparable to the cash flow of full
cost companies. Columbus' DCF for the first six months 1997 was $4,353,000
compared to $3,253,000 in 1996. This 34% improvement reflects higher natural gas
and crude oil prices and increased natural gas production over last year's.
While DCF is calculated before debt retirement requirements, in Columbus' case
it does not matter because outstanding bank debt requires no principal payments
before July 1999. Furthermore, interest expense on the outstanding debt has been
relatively insignificant but has been deducted when arriving at DCF in any
event.
Management notes its strong exception to Financial Accounting Standards
Board Statement No. 95 which directs that operating cash flow must only be
determined after consideration of working capital changes and will continue to
reflect that position in all of its public filings and reports. Such a
requirement 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 can have on a company which serves as an operator of several
properties with only a small working interest therein as does Columbus.
Neither discretionary cash flow nor operating cash flow before working
capital may be substituted for net income or cash available from operations as
defined by GAAP. Furthermore, cash flows do not necessarily indicate that they
are sufficient to fund all cash requirements of a company under any of the
definitions.
Columbus' hedges (swaps) of natural gas and oil prices are discussed below
in Results of Operations as well as in Note 5 to the financial statements.
The Company's operation and management services segment remains profitable
but has not contributed meaningfully to earnings since Resources was spun-off in
February, 1995.
Columbus had outstanding borrowings of $1,500,000 as of May 31, 1997
against its line of credit with Norwest Bank Denver, N.A. which has a current
borrowing base of $10,000,000 and is collateralized by oil and gas properties.
At the end of the second quarter 1997, the ratio of bank debt to shareholders'
equity was 0.09 and to total assets was 0.06. The debt outstanding used a LIBOR
option at an interest rate of 7.2%. The net increase or decrease of long-term
debt affects reported cash flow from financing activities as does the purchase
of treasury stock and proceeds from the exercise of stock options.
18
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Working capital at May 31, 1997 remained positive at $1,310,000 compared to
$1,966,000 at November 30, 1996. This was achieved despite expenditures of
$2,913,000 for new additions to oil and gas properties out of the $7,100,000
budgeted for development and exploratory capital expenditures for 1997.
A 300,000-share repurchase authorized in February 1995 at less than $8.75
per share was completed in March 1997 for an average repurchase price of $7.21
($5.77 after five-for-four stock split).
Recently, during March 1997, an additional 100,000-share repurchase was
authorized at less than $7.80 (giving effect to five-for-four stock split) per
share. To date, 71,500 shares were acquired at an average price of $7.38 per
share. A second authorization was granted in May, 1997 effective following
distribution of split shares in June, 1997 which permits purchase of an
additional 200,000 shares at a price not to exceed $8.25 per share. None of this
authorization has as yet been acquired.
RESULTS OF OPERATIONS
During 1997's second quarter, the Company's revenues increased by 9% but
operating income decreased by 25% compared to 1996 due to significantly higher
exploration charges and general and administrative expenses which included
annual incentive bonuses granted in May. Other comparisons appear below for the
quarter and first half of 1997 versus like periods in 1996.
As previously indicated, a record drilling budget was approved for 1997 so
it should be expected that there will be a record number of well participations.
During the second quarter, seven gross wells (1.18 net) were completed and
resulted in five (0.28 net) successful gas wells in the Laredo area and two
(1.80 net) oil wells in Montana which included a new zone oil discovery. In
addition, one development well (0.53 net) which was drilled in the Laredo area
during 1995 and previously considered as "in progress awaiting completion" was
abandoned during the second quarter as uneconomic. The first of the two Montana
oil wells, the McCabe #1- X, which was a replacement Red River formation
completion in the S.E. Froid field, began pumping in early second quarter with
an initial potential of 88 barrels of oil per day and a similar amount of water.
Recently water percentage has increased such that a larger pump will be required
to improve oil production. The second well, the McCabe #1, was a successful
recompletion (and a new zone oil discovery) in the Winnepegosis formation at a
depth of about 11,100 feet. This was achieved after successfully removing junk
from the casing at about the 9,000 foot level which had previously obstructed
using the lower part of the wellbore. It was flow tested on May 23, 1997 with an
initial potential of 112 barrels of oil and two barrels of water through a
14/64ths choke with a tubing pressure of 100 psi but could not sustain a flowing
19
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
status due to formation water increasing to about 25%. The well was flowed
intermittently during May and was eventually placed on pump in June with an
indicated pumping production rate of 116 to 141 barrels of oil and 51 to 85
barrels of water per day. With an almost 75% net revenue interest ("NRI") in
each of these two Montana oil wells, the Company's oil production is expected to
show a significant improvement during the third quarter. This is regardless of
the outcome of the potential discoveries discussed below which were considered
as "in progress" as the quarter ended.
In Texas, about 20 miles southeast of EGY's Sralla Road field, the Company
participated in an exploratory seismic anomaly to test for gas in the Frio 16
sand at 9,000 feet. It is located adjacent to the old Anahuac field in Chambers
County, Texas that has produced several hundred million barrels of oil from
uphole Frio sands over several decades. The Syphrett Heirs #1 test well resulted
in a natural gas discovery in the Frio 16 sand. A drilling unit 480 acres in
size has been agreed upon and the Company will initially own about a 35% WI
which is subject to a 25% reduction after it fully recovers all of its costs of
acreage, drilling and completion costs of this initial well. The excellent log
and gas shows encountered led to EGY's assumption of operatorship and setting
casing. A gathering system and a pipeline connection was installed in advance of
perforating ten feet of a 40-foot gross interval of F-16 sand. The well was
tested on July 10th 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
4950 psig. An additional 600 acres of prospective acreage is owned to the south
and east of the discovery fault block. This acreage will require its own
exploratory test because it is in a separate fault block. A well should be
commenced later in 1997 and may be drilled to a depth of 11,000 feet to test the
underlying Vicksburg formation. A recent gas discovery was completed in this
zone about two miles east of the Syphrett fault block and during the past two
weeks a new Vicksburg location offsetting this southeast acreage block was
announced by that same operator. The Frio 15 sand is also considered prospective
for oil production at a structurally higher position in the Syphrett well
discovery fault block may also produce in the southeast block.
In the 1996 annual report (as well as several earlier quarterly reports),
details were disclosed about the Company's 12.5% WI participation in 55,000
acres of leaseholds in an Area of Mutual Interest ("AMI") overlying the deep,
fractured, geo- pressured Austin Chalk play in mid-Louisiana. Columbus and its
co- venturers sold a 75% participation of their initially assembled 23,000 acre
block to Belco Oil & Gas at a profit along with Belco's concurrent agreement to
carry the co-venturers for a 25% back-in after payout interest in a well drilled
20
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
from grass roots. That obligation was later amended so those upfront costs could
be spread over drilling two laterals in the first well and a vertical wellbore
in the second well. That first test called for re-entry of a mutually-owned
existing 15,000-foot cased vertical wellbore which Belco could utilize to drill
(while advancing all upfront costs) the two opposing laterals consisting of a
3,000- foot updip north lateral and a 4,400-foot downdip south lateral. Columbus
et al would pay for their 25% WI share of any required costs to get the vertical
hole in condition to be able to drill those opposing laterals. The co-venturers
would share in the initial revenues in a proportion that their share of those
vertical expenditures bear to the total costs of the completed well. A full
12.5% WI share of revenues would be received by Columbus and 12.5% by its
co-venturers after payout.
Belco drilled the first updip lateral along the base of the 250-foot
productive interval of the Austin Chalk despite the co- venturers' protest that
the proposed lateral would fall outside of the known productive interval. That
admonition proved to be accurate as that lateral yielded non-commercial rates of
production so Belco then decided to move up in the section about 100 feet. It
drilled a second "piggyback" updip lateral which encountered several fractures
and good oil and gas shows in a 3,100-foot horizontal hole which were an
improvement over the first lateral. Unfortunately, at about 2,800 feet out from
the vertical hole, a fault was encountered which most likely penetrates down to
the lower Tuscaloosa formation. This probably accounts for this second updip
lateral testing significant volumes of salt water along with produced oil and
gas. By the end of a 66 hour test through a 24/64ths inch choke, it had produced
4,431 barrels of water and 1,811 barrels of crude oil and the natural gas rate
had settled to around 600 MCFD. The fluid flow rate was still 66 barrels per
hour with a 21% oil cut at that time.
Belco thereafter gave notice to the co-venturer group of its intention to
move the drilling rig to another location and postpone drilling the previously
agreed to downdip 4,400-foot lateral. This was strenuously protested as a
significant breach of contract but Belco was offered an alternative to its
obligation to the co- venturers whereby it could assign all of its interest in
the 1,920 acre unit (including the well). In turn, the operations would be
assumed by the co-venturers who would proceed with drilling the downdip lateral.
Belco accepted that proposal with the co- venturers commitment to spend at least
$750,000 on this effort. That obligation is being split 75% WI to Columbus,
12.5% WI to each of the other co-venturers. The Company would serve as joint
operator with F. W. Rabalais, Inc. and each co-venturer is free to sell as much
of their interest as desired while remaining responsible for their designated
share of all costs. Columbus immediately sold 30% out of its 75% participation
in the lateral portion based on actual costs not to exceed $1.5 million. Each
21
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
participant's participation for a like ownership in the vertical hole portion
would not become a requirement until the downdip lateral had been drilled, liner
installed, and the well tested for at least 48 hours. Three participants
(including Mr. Trueblood) agreed to purchase 10% each on that basis. After
testing, each individual participant will be able to elect to either withdraw
from further expense and relinquish any interest in the well (and the unit) or
else purchase a 10% ownership interest in the vertical cased wellbore based on
an additional payment of $1.2 million ($120,000). Participants must also pay for
their share of additional costs for the surface equipment and gas gathering
system. A decision to opt out would effectively become a decision by such
participant that an uneconomic lateral had been drilled if weighed against the
required additional costs to own a 10% working interest in a productive well.
Such an economic circumstance would not necessarily apply to the Company since
most of its percentage ownership of the vertical holes had been acquired on an
entirely different cost basis. This sale to others was to be Columbus' primary
offset against possible cost overruns and hopefully would be a source of profit.
However, problems encountered to date with drilling and testing this lateral
have far exceeded the original budget of $1.5 million. It is unlikely any profit
will be realized assuming the participants choose to buy into the vertical
wellbore but still less than drilling a new single lateral well.
This Louisiana well was considered as in progress as of the end of the
second quarter and completion operations are still underway at the date of this
report. Increased ownership of 45% WI has raised EGY's exposure to increased
future cash flow from a producing well, even if only partially successful, but
the exploratory costs which must be expensed should it be totally unsuccessful
are large. Because of the lost circulation encountered after killing the well
with mud, this lateral's productivity has undoubtedly been diminished.
Nevertheless, management emphasizes that this vertical wellbore can and will
undoubtedly be utilized in future to drill at a minimum a second downdip lateral
of 4,000 feet in length using mud from the beginning. The co-venturers' initial
effort to utilize a clear weighted drilling fluid was doomed for failure from
the beginning but the excessive high pressures which could not be controlled
could not be foreseen. As a result, the lateral drilling was halted at a
measured depth of 17,233 feet which was only 1,300 feet out from vertical but
extensive vertical fracturing as well as significant high pressure shows of oil
and gas in that short distance are encouraging. We agreed to settle for
depleting the reserves from this interval for the time being with full
intentions to eventually abandon this lateral and drill a second lateral downdip
which will encounter the balance of the fracture system in the remaining 2,700
feet not yet tested. It would be total speculation at this point in time to even
22
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
hazard a guess as to the productivity of this current lateral or what a second
one might yield in the way of additional reserves. Only time will produce that
answer.
Oil and Gas Revenues and Operating Costs
The following table shows comparative crude oil and natural gas revenues,
sales volumes, average prices and percentage changes between periods for the
second quarters of 1997 and 1996 and the second quarter of 1997 versus the first
quarter of 1997.
<TABLE>
<CAPTION>
Second Quarter
-------------- % First Qtr. %
1997 1996 Change 1997 Change
------ ------ ------ ----------- ------
<S> <C> <C> <C> <C> <C>
Natural gas revenues M$ $1,672 $1,424 17 % $ 2,511 (33)%
Oil revenue M$ $1,207 $1,215 (1)% $ 1,254 (4)%
Natural gas sales volumes:
Millions of cubic feet 809 662 22 % 777 4 %
MCF/day 8,792 7,190 8,628
Oil sales volumes:
Barrels 61,792 61,576 - % 57,801 7 %
Barrels/day 672 669 642
Average price received:
Natural gas - $/MCF $ 2.07 $ 2.15 (4)% $ 3.23 (36)%
Oil - $/BBL $19.53 $19.74 (1)% $21.69 (10)%
</TABLE>
Natural gas revenues increased 17% in the second quarter of 1997 when
compared to 1996's quarter as a result of higher volumes which overcame lower
prices. Average prices for natural gas decreased 4% in the second quarter of
1997 compared with last year due to lower demand with milder spring weather and
improved storage volumes on hand. Gas revenues in the second quarter of 1997
were aided by $26,000 ($.03 per Mcf) and 1996's revenues were reduced by
$117,000 ($.18 per Mcf) from swaps of natural gas or otherwise the differential
would have been greater. Sales volumes improved by 22% over 1996's second
quarter as a result of numerous wells being completed and connected during the
intervening months. The latest quarter compared to first quarter of 1997 showed
a sales volume increase of 4% as a result of new well connections but a 36%
reduction in average prices received resulting in a revenue decrease of 33%.
Oil revenues for the 1997 second quarter were almost flat when compared to
the similar 1996 quarter. There was a slight decrease in the average price
received of 1% and slightly higher sales volumes. Crude oil production has begun
to show a reversal of its normal declines and there were sufficient new wells
completed in the second quarter to surpass last year's volumes and a noticeable
improvement of 7% over 1997's first quarter volume. Oil revenues for the second
quarter of 1997 were aided by $19,370 ($.31 per barrel) and second quarter 1996
revenues reduced by $67,500 ($1.10 per barrel) from crude oil swaps.
23
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Columbus' 1997 second quarter average sales volumes of natural gas of 8,792
Mcfd and oil production of 672 barrels per day equates to daily production of
2,137 barrels of oil equivalent (BOE). While this is 3% below the previous
record quarter for U.S. daily production of 2,200 BOE, production should reach
record levels over the summer quarter with the new oil and gas discoveries
previously discussed.
When comparisons are made with the first quarter results for 1997, second
quarter oil revenues were 4% lower despite 7% increase in production because of
a 10% decrease in average price per barrel received.
Lease operating expenses for the 1997 quarter were higher than second
quarter 1996 because the current quarter had several expensive workovers
performed and equipment replaced on older wells. However, lease operating costs
on a BOE basis were only $2.19 in 1997 compared to $2.37 in 1996 as a result of
increased production volumes. Operating costs as a percentage of revenues was
15% in the 1997 second quarter and 16% in 1996's comparable quarter.
Production and property taxes approximated 9% of revenues in 1997 and 10%
in 1996. These vary based on Texas' percentage of the total production where oil
tax rates are lower than gas tax rates and the relationship of taxes and revenue
is not always directly proportional. Some local jurisdiction's taxes are based
upon reserve evaluations as opposed to actual revenues or production for a given
period.
Operating and Management Services
This segment of the Company's U.S. business is comprised of operations and
services conducted on behalf of third parties and includes compressor rentals.
Operating and management services profit is fairly consistent between
quarters. There was a $189,000 profit during first six months 1997 compared to a
$141,000 profit for the equivalent period in 1996 as the number of operated
wells and drilling activity has increased.
Interest Income
Interest income is earned primarily from short-term invest ments whose
rates fluctuate with changes in the commercial paper rates and the prime rate.
Interest income increased in 1997 to $35,000 from $33,000 in 1996's second
quarter primarily as result of an increased amount of investments and stable
short-term interest rates.
24
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
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 also included.
The Company's general and administrative expenses in the second quarter of
1997 were much higher than last year. Those increased costs were due to salary
increases in May 1997 for officers and in November 1996 for employees and to
incentive bonuses, which are discretionary and are related to Company
performance for the prior year, which totaled $220,000 ($70,000 non-cash) in
May, 1997 compared to $83,000 (all non-cash) in May, 1996.
Reimbursement for services provided by Columbus officers and employees for
managing Resources is expected to decrease later in fiscal 1997 assuming that
Canadian-based management takes over following a business combination. Columbus'
general and administrative expenses will increase accordingly since no staff
reductions are planned when this occurs. Reimbursement of $64,000 compares with
$78,000 received during the second quarter of 1996 for providing services to
Resources.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization of oil and gas assets are
calculated based upon the units of production compared to proved reserves of
each field. The expense is not only directly related to the level of production,
but also is dependent upon past costs to find, develop, and recover those
reserves. Depreciation and amortization of office equipment and computer
software is also included in the total charge.
Total charges for depletion expense for oil and gas properties increased
over 1996 due to increased production and added development expenditures in the
intervening period. The 1997 second quarter depletion rate of $3.75 per BOE was
lower compared to $3.82 per BOE in the like period of fiscal 1996 and $3.86 per
BOE for all of 1996. These amounts are below the industry average primarily
because of historically lower finding costs compared to others who have grown
primarily by acquisitions.
A non-cash impairment loss of $165,000 was recognized during the 1996 first
quarter because a development well drilled in Oklahoma proved to be uneconomic
and its costs exceeded the remaining cash flows from other producing properties
in the field at that time.
25
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - (Continued)
Exploration Expense
In general, the exploration expense category includes the cost of
Company-wide efforts to acquire and explore new prospective areas. The
successful efforts method of accounting for oil and gas properties requires
expensing the costs of unsuccessful exploratory wells. Other exploratory charges
such as seismic and geologic costs must also be immediately expensed regardless
of whether a prospect is eventually proved successful. Exploration expenses for
comparative second quarters amounted to $318,000 for 1997 up from $111,000 for
1996 because of $235,000 of 3-D seismic costs incurred in the S.E. Froid area in
Montana which located new exploratory well sites that are planned to be drilled
later in 1997. Additional 3-D seismic costs for the Hay Creek area of Montana
budgeted for later in 1997 will also reduce this year's net earnings. These
exploration expenses also reduce reported GAAP cash flow from operations (as
well as net earnings) even though they are discretionary expenses; however, such
charges are added back for purposes of determining discretionary cash flow which
is more comparable to cash flow of full cost accounting companies.
Interest Expense
Interest expense varies in a direct proportion to the amount of bank debt
and the level of bank interest rates. The average amount of bank debt
outstanding has been lower during 1997's second quarter than in 1996. The
average bank interest rate paid this latest quarter was 7.1% which compares to
7.2% in 1996.
Income Taxes
During the first six months of 1997 the U.S. net deferred tax asset became
a net liability of $856,000 as a result of expected use of net operating loss
carryforwards. The net liability is comprised of $304,000 current deferred tax
asset and $1,160,000 long-term tax liability. The estimated utilization of
deferred tax assets was $857,000 during the six months. The valuation allowance
has remained unchanged so far in 1997. The effective tax rate for 1997 is 38%.
See also Note 3 to the consolidated financial statements for further explanation
of income taxes.
Statement Pursuant to Safe Harbor Provision of the Private
Securities Litigation Reform Act of 1995
This report 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.
26
<PAGE>
PART II - OTHER INFORMATION
Item 1. 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.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Annual Meeting held May 8, 1997 elected three directors to a two year term,
J. Samuel Butler, Clarence H. Brown and Jerol M. Sonosky. Continuing directors
until May 1998 are Harry A. Trueblood, Jr., William H. Blount, Jr. and Donald W.
Ringsby.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
11 - Computation of per share earnings
27 - Financial data schedule
(b) Reports on Form 8-K
None
27
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
COLUMBUS ENERGY CORP.
---------------------
(Registrant)
DATE: July 14, 1997 /s/ Harry A. Trueblood, Jr.
- ----- ------------- ---------------------------
Harry A. Trueblood, Jr.
Chairman, President and
Chief Executive Officer
(a duly authorized officer)
DATE: July 14, 1997 /s/ Ronald H. Beck
- ----- ------------- ------------------
Ronald H. Beck
Vice President
(Chief Accounting Officer)
28
<PAGE>
Commission File No. 1-9872
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
EXHIBIT
TO
FORM 10-Q
QUARTERLY REPORT
PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTER ENDED MAY 31, 1997
COLUMBUS ENERGY CORP.
(Exact Name of Registrant)
1660 Lincoln Street
Denver, Colorado 80264
(Address of Principal Executive Office)
EXHIBIT 11
COLUMBUS ENERGY CORP.
Statement of Computation of Per Share Earnings
(Unaudited)
(In Thousands Except Per Share Data)
<TABLE>
<CAPTION>
Six Months Three Months
Ended May 31, Ended May 31,
------------- -------------
1997 1996 1997 1996
---- ---- ---- ----
<S> <C> <C> <C> <C>
Primary:
Based on weighted average
shares outstanding including
the effect of common stock
equivalents:
Weighted average shares
outstanding: 3,932 3,810 3,901 3,799
Incremental shares attributable
to dilutive stock options and
warrants outstanding based on
average market price during
the period calculated using
the treasury stock method 69 14 44 25
------ ------ ------ ------
Total average common and
common equivalent shares 4,001 3,824 3,945 3,824
====== ====== ====== ======
Net earnings $1,564 $1,083 $ 421 $ 533
====== ====== ====== ======
Earnings per share $ .39 $ .28 $ .11 $ .14
====== ====== ====== ======
</TABLE>
Note: Fully diluted incremental shares for the six months were 95,000 and
19,000 with total average common and common share equivalent shares
4,027,000 and 3,829,000 in 1997 and 1996, respectively.
Fully diluted incremental shares for the three months were 96,000 and
34,000 with total average common and common share equivalent shares
3,997,000 and 3,833,000 in 1997 and 1996, respectively.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
The consolidated balance sheet as of May 31, 1997 and the
consolidated statement of income for the six months ended
May 31, 1997.
</LEGEND>
<MULTIPLIER> 1,000
<CURRENCY> U.S. Dollars
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> NOV-30-1997
<PERIOD-START> DEC-01-1996
<PERIOD-END> MAY-31-1997
<EXCHANGE-RATE> 1
<CASH> 1,186
<SECURITIES> 0
<RECEIVABLES> 3347
<ALLOWANCES> 116
<INVENTORY> 85
<CURRENT-ASSETS> 4,888
<PP&E> 32,959
<DEPRECIATION> 14,379
<TOTAL-ASSETS> 23,468
<CURRENT-LIABILITIES> 3,578
<BONDS> 0
0
0
<COMMON> 886
<OTHER-SE> 16,344
<TOTAL-LIABILITY-AND-EQUITY> 23,468
<SALES> 6,644
<TOTAL-REVENUES> 7,293
<CGS> 1,576
<TOTAL-COSTS> 4,712
<OTHER-EXPENSES> (6)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 65
<INCOME-PRETAX> 2,522
<INCOME-TAX> 958
<INCOME-CONTINUING> 1,564
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 1,564
<EPS-PRIMARY> .40
<EPS-DILUTED> .40
</TABLE>
